Exhibit 99.2

Q4 2018 Supplemental Information Three and Twelve Months Ended December 31, 2018

This communication contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts. These statements involve estimates, expectations, projections, goals, assumptions, known and unknown risks, and uncertainties and typically include words or variations of words such as “expect,” “anticipate,” “believe,” “intend,” “plan,” “seek,” “estimate,” “predict,” “project,” “opportunities,” “goal,” “guidance,” “outlook,” “initiatives,” “objective,” “forecast,” “target,” “potential,” “continue,” “would,” “will,” “should,” “could,” or “may” or other comparable terms and phrases. All statements that address operating performance, events, or developments that the Company expects or anticipates will occur in the future are forward-looking statements. They may include estimates of expected cash available for distribution, dividend growth, earnings, Adjusted EBITDA, revenues, income, loss, capital expenditures, liquidity, capital structure, future growth, financing arrangements and other financial performance items (including future dividends per share), descriptions of management’s plans or objectives for future operations, products, or services, or descriptions of assumptions underlying any of the above. Forward-looking statements provide the Company’s current expectations or predictions of future conditions, events, or results and speak only as of the date they are made. Although the Company believes its expectations and assumptions are reasonable, it can give no assurance that these expectations and assumptions will prove to have been correct and actual results may vary materially. By their nature, forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Factors that might cause such differences include, but are not limited to: risks related to weather conditions at our wind and solar assets; the willingness and ability of counterparties to fulfill their obligations under offtake agreements; price fluctuations, termination provisions and buyout provisions in offtake agreements; our ability to enter into contracts to sell power on acceptable prices and terms, including as our offtake agreements expire; government regulation, including compliance with regulatory and permit requirements and changes in tax laws, market rules, rates, tariffs, environmental laws and policies affecting renewable energy; our ability to compete against traditional utilities and renewable energy companies; pending and future litigation; our ability to successfully integrate projects we acquire from third parties, including Saeta Yield S.A.U., and our ability to realize the anticipated benefits from such acquisitions; our ability to implement and realize the benefit of our cost and performance enhancement initiatives, including the long-term service agreements with an affiliate of General Electric; risks related to the ability of our hedging activities to adequately manage our exposure to commodity and financial risk; risks related to our operations being located internationally, including our exposure to foreign currency exchange rate fluctuations and political and economic uncertainties, the regulated rate of return of renewable energy facilities in our Regulated Wind and Solar segment, a reduction of which could have a material negative impact on our results of operations; the condition of the debt and equity capital markets and our ability to borrow additional funds and access capital markets, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness in the future; operating and financial restrictions placed on us and our subsidiaries related to agreements governing indebtedness; our ability to identify or consummate any future acquisitions, including those identified by Brookfield; our ability to grow and make acquisitions with cash on hand, which may be limited by our cash dividend policy; risks related to the effectiveness of our internal control over financial reporting; and risks related to our relationship with Brookfield, including our ability to realize the expected benefits of the sponsorship. The Company disclaims any obligation to publicly update or revise any forward-looking statement to reflect changes in underlying assumptions, factors, or expectations, new information, data, or methods, future events, or other changes, except as required by law. The foregoing list of factors that might cause results to differ materially from those contemplated in the forward-looking statements should be considered in connection with information regarding risks and uncertainties, which are described in our most recent Annual Report on Form 10-K and any subsequent Quarterly Report on Form 10-Q, as well as additional factors we may describe from time to time in other filings with the Securities and Exchange Commission (the “SEC”). We operate in a competitive and rapidly changing environment. New risks and uncertainties emerge from time to time, and you should understand that it is not possible to predict or identify all such factors and, consequently, you should not consider any such list to be a complete set of all potential risks or uncertainties. This Supplemental Information contains references to Adjusted Revenue, Adjusted EBITDA, and cash available for distribution (“CAFD”), which are Non-GAAP measures that should not be viewed as alternatives to GAAP measures of performance, including revenue, net income (loss), operating income or net cash provided by operating activities. Our definitions and calculation of these Non-GAAP measures may differ from definitions of Adjusted Revenue, Adjusted EBITDA and CAFD or other similarly titled measures used by other companies. We believe that Adjusted Revenue, Adjusted EBITDA and CAFD are useful supplemental measures that may assist investors in assessing the financial performance of the Company. None of these Non-GAAP measures should be considered as the sole measure of our performance, nor should they be considered in isolation from, or as a substitute for, analysis of our financial statements prepared in accordance with GAAP, which are available on our website at www.terraform.com, as well as at www.sec.gov. Cautionary Statement Regarding Forward-Looking Statements

Executing our Business Plan Invested $1.2 billion to acquire Saeta Yield, S.A.U. (“Saeta”), a ~1,000 MW portfolio of high-quality wind and solar assets primarily in Spain that established a scale operating platform in Europe Progressed efforts to execute long term service agreements with General Electric (“GE”) for North American wind fleet that are expected to lock in annual cost savings of ~$20 million and enhance revenues through performance guarantees backed by liquidated damages Completed our solar performance improvement plan, expected to increase annual production by ~61 GWh and revenue by ~$11 million Progressed deleveraging of our balance sheet through Saeta acquisition and achieved upgraded corporate credit rating from Moody’s to Ba3 We raised ~$160 million of non-recourse debt to support the financing plan for the Saeta acquisition We repriced our $350 million Term Loan B, yielding projected annual savings of approximately $2.5 million 2018 Highlights

8,088 GWh Generation 2018 Highlights (continued) Performance Highlights During 2018, our portfolio delivered Net loss, Adjusted EBITDA and CAFD of $153 million, $590 million and $126 million, respectively, versus $236 million, $438 million and $88 million, respectively, in 2017 Net loss was $83 million lower than 2017 and Adjusted EBITDA increased by $152 million primarily due to the Saeta acquisition CAFD increased by $38 million largely attributable to the contribution from the European platform. Savings in corporate interest resulting from our Q4 2017 financing initiatives were largely offset by lower resource in Central Wind, timing of incentive revenue invoicing in 2017, and the impact of the Raleigh outage in Q1 2018 Excluding the European platform, the total generation in 2018 of 6,919 GWh was 3% lower than prior year, primarily due to resource and availability in the Central Wind portfolio. Production was below Long term average (‘LTA”) primarily due to resource but was also impacted by greater than normal curtailments and maintenance, which will be largely mitigated upon full implementation of our LTSAs with GE Including the contribution of our European platform, total generation in 2018 was 8,088 GWh CAFD per share increased by $0.07 versus prior year due to the addition of the European platform and offset in part by the increased shares in issue Total capitalization $8.6 billion after funding European platform acquisition Key Performance Metrics $126 million CAFD $8.6 billion Total Capitalization 2018 2017 10,012 7,578 8,088 7,167 $ 824 $ 626 590 438 (153) (236) 126 88 $ 0.07 $ (1.61) $ 0.69 $ 0.62 (2) (MILLIONS, EXCEPT AS NOTED) Total generation (GWh) (1) (1) Adjusted Revenue (2) CAFD per share (2)(3) Adjusted for sale of our UK solar and Residential portfolios. Non-GAAP measures. See “Calculation and Use of Non-GAAP Measures” and “Reconciliation of Non-GAAP Measures” sections. Amounts in 2017 adjusted for sale of our UK and Residential portfolios. CAFD (2) Net loss Dec 31 LTA generation (GWh) Adjusted EBITDA (2) Earnings (loss) per share (3) (3) Loss per share is calculated using a weighted average diluted Class A common stock shares outstanding. CAFD per share is calculated using a weighted average diluted Class A common stock and weighted average Class B common stock shares outstanding. For the twelve months ended December 31, 2018, weighted average diluted Class A common stock shares outstanding totaled 182 million, including issuance of 61 million to affiliates (for the twelve months ended December 31, 2017, this amount was 104 million). For the twelve months ended December 31, 2018, there are no weighted average Class B common stock shares outstanding (for the twelve months ended December 31, 2017, this amount was 38 million). Dec 31 Dec 31 2018 2017 5,797 3,643 2,768 2,422 8,565 6,065 (IN $ MILLIONS) Total long-term debt Total capitalization (1) (1) Total stockholders' equity and redeemable non-controlling interest Total capitalization is comprised of total stockholders’ equity, redeemable non-controlling interests, and Total long-term debt.

TERP’s mandate is to acquire, own and operate wind and solar assets in North America and Western Europe Overview of TerraForm Power $8.5 billion Total power assets 3,737 MW of capacity4 64% wind5 36% solar5 ~$2.6 Billion1 Market Capitalization TERP NASDAQ ~6.4% Yield2 $0.8056 Target 2019 per Share Dividend ~65% Brookfield Ownership Significant NOLs3 Tax advantaged structure (C Corp) Based on the closing price of TERP’s Class A common stock of $12.54 per share on March 11, 2019. Based on 2019 target dividend of $0.8056 per share and the closing price of TERP’s Class A common stock of $12.54 per share on March 11, 2019. Net Operating Losses (“NOLs”). In this presentation, all information regarding megawatt (“MW”) capacity represents the maximum generating capacity of a facility as expressed in (1) direct current (“DC”), for all facilities within our Solar reportable segment, and (2) alternating current (“AC”) for all facilities within our Wind and Regulated Solar and Wind reportable segments. Expressed as a percentage of total MW owned.

Renewables Portfolio with Scale in North America and Western Europe Owner and operator of an over 3,700 MW diversified portfolio of high-quality wind and solar assets, underpinned by long-term contracts Spain Portugal Uruguay Chile U.K. Wind Solar Total US 1,536 MW 911 MW 2,447 MW International 856 MW 434 MW 1,290 MW Total 2,392 MW 1,345 MW 3,737 MW

Significant Diversity Determined based on Total MW. Based on Projected Revenue for 2019. Solar Wind Solar Wind 41% 14% 2% 4% 3% 24% 7% 2% 3% 0% 10% 20% 30% 40% 50% 60% 70% United States Spain Canada Portugal Chile Uruguay Significant Resource Diversity 1 Meaningful Portfolio Effect Wind Solar

Long-term contracted and regulated assets Long Term Stable Cash Flows Tenor of Offtake Contracts and Offtaker Credit Ratings are calculated based on total MW, as of December 31, 2018. Offtaker Credit Rating indicates “IG” if rated as Investment Grade by either Moody’s or S&P, "NR" if not rated by both S&P and Moody's, “< IG” if the former cases are not applicable and rated less than Investment Grade by either Moody’s or S&P. Assets remunerated through the Spanish guaranteed return on deemed investment (RAB) regime (see Slide 29). Determined based on TERP projected 2019 revenue. > 6 years 0-6 years Regulated2 Contracted Uncontracted 20+ years 10-14 years 5-9 years 0-4 years 15-19 years < IG NR IG ~95% of cash flows1 are under long-term contract or regulatory framework2 ~13 years of contracted cash flow with creditworthy offtakers

Generation and Revenue LTA annual generation is expected generation at the point of delivery net of all recurring losses and constraints. We expect that our wind and solar fleet will be able to produce at LTA on a run rate basis during 2019 as we improve the performance of our fleet 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 wind conditions and irradiance conditions will vary from one period to the next; however, we expect our facilities will produce electricity in-line with their LTA over time Actual Generation LTA Generation Adjusted Revenue (1) 2018 2017 2018 2017 2018 2017 Wind Central Wind 2,260 2,590 2,650 101 $ 123 $ 136 $ 157 $ Texas Wind 1,627 1,556 1,713 38 $ 38 $ 26 $ 35 $ Hawaii Wind 240 228 307 43 $ 41 $ 44 $ 41 $ Northeast Wind 972 1,006 1,023 64 $ 71 $ 76 $ 79 $ International Wind (2) 358 - 693 35 $ - $ 35 $ - $ 5,457 5,380 6,386 281 $ 273 $ 317 $ 312 $ Solar North America Utility Solar 1,021 1,008 1,074 142 $ 134 $ 141 $ 138 $ International Utility Solar 257 244 240 31 $ 46 $ 30 $ 33 $ Distributed Generation 541 535 580 126 $ 157 $ 134 $ 143 $ 1,819 1,787 1,894 299 $ 337 $ 305 $ 314 $ Regulated Solar and Wind (2) 812 - 1,732 187 $ - $ 202 $ - $ Total 8,088 7,167 10,012 767 $ 610 $ 824 $ 626 $ (2) Represents the actual performance after the closing of the acquisition of our Saeta on June 12, 2018. (MILLIONS) (GWh) Operating Revenues, Net (1) Non-GAAP measure. Adjusted Revenue is operating revenues, net, adjusted for non-cash items, including (i) unrealized gain/loss on derivatives, (ii) amortization of favorable and unfavorable rate revenue contracts, net, and (iii) an adjustment for wholesale market revenues to the extent above or below the regulated price bands. See "Calculation and Use of Non-GAAP Measures" and "Reconciliation of Non-GAAP Measures” sections.

Selected Income Statement and Balance Sheet information The following tables present selected income statement and balance sheet information by operating segment: Balance Sheet Income Statement 2018 2017 $ (44) $ (49) 60 128 Regulated Solar and Wind 38 - (207) (315) $ (153) $ (236) 205 206 255 262 Regulated Solar and Wind 158 - (28) (30) $ 590 $ 438 80 75 138 149 Regulated Solar and Wind 61 - (153) (136) $ 126 $ 88 Twelve months ended Dec 31 (MILLIONS) Net income (loss) Solar Wind Corporate Total Adjusted EBITDA Solar Wind Corporate Total Total CAFD Solar Wind Corporate $ 3,733 $ 3,402 2,763 2,897 Regulated Solar and Wind 2,748 - 86 88 $ 9,330 $ 6,387 1,188 884 1,225 1,152 Regulated Solar and Wind 1,891 - 2,258 1,929 $ 6,562 $ 3,965 2,545 2,518 1,538 1,745 - Regulated Solar and Wind 857 - (2,172) (1,841) $ 2,768 $ 2,422 Solar Wind Corporate Total (MILLIONS) Dec 31, 2017 Total Assets Total Dec 31, 2018 Total Equity and NCI Total Liabilities Solar Wind Corporate Solar Wind Corporate Total

Operating Segments

Wind Performance Highlights Including acquired Saeta Wind assets in 2018, Adjusted EBITDA and CAFD were $205 million and $80 million, respectively, versus $206 million and $75 million, respectively, in 2017 Adjusted EBITDA was in line with 2017, primarily due to lower wind resource, particularly in Central Wind, Raleigh outages in Q1 2018 and the impact of Texas pricing, partially offset by the contribution of the International Wind portfolio resulting from acquisition of the European platform in June 2018 CAFD was $5 million higher than in 2017 primarily due to interest savings relating to the refinancing of the MidCo term loan with corporate level debt Net loss was $44 million, $5 million lower than 2017, due to higher depreciation and amortization from the addition of European platform offset by interest savings from repayment of the MidCo term loan in 2017 Sustaining capital expenditures are reported based on long-term averages starting in 2018 1,853 MW capacity $80M CAFD Actual Generation (GWh) Average Adj. Revenue per MWh (MILLIONS, EXCEPT AS NOTED) 2018 2017 2018 2017 Central Wind 2,260 2,590 60 $ 61 $ Texas Wind 1,627 1,556 16 22 Hawaii Wind 240 228 182 180 Northeast Wind 972 1,006 78 79 International Wind (1) 358 - 98 - Total 5,457 5,380 58 $ 58 $ (1) Includes Portugal Wind and Uruguay Wind. 2018 (1) 2017 Capacity (MW) 1,853 1,531 6,386 5,693 $ 317 $ 312 (112) (106) $ 205 $ 206 (50) (72) (61) (53) (15) (16) Sustaining capital expenditures (7) (2) 8 12 $ 80 $ 75 205 206 (51) (77) (183) (168) (15) (10) $ (44) $ (49) Depreciation and amortization Adjusted EBITDA Adjusted interest expense Levelized principal repayments Distributions to NCI Other Twelve months ended Dec 31 Other Net loss CAFD Adjusted EBITDA Interest expense (MILLIONS, UNLESS NOTED) Adjusted Revenue Direct operating costs LTA Generation (GWhs)

Solar Adjusted EBITDA and CAFD were $255 million and $138 million, respectively, versus $262 million and $149 million, respectively, in 2017 Adjusted EBITDA decreased $7 million due to lower incentive revenue caused by additional SREC inventory monetization in 2017 and the First Energy Solution bankruptcy, partially offset by higher SREC pricing in the Northeast and reduced costs CAFD decreased $11 million due to lower Adjusted EBITDA, new project financings to fund the Saeta acquisition, partially offset by lower distributions to non-controlling interests in 2018 due to timing from 2016 project defaults and related cash traps remediated in 2017 Net income of $60 million was $68 million lower than in 2017 primarily due to gain on sale of U.K. renewable energy facilities in 2017 and the Enfinity asset impairment related to the First Energy Solution bankruptcy in DG Solar in 2018 Performance Highlights 1,092 MW capacity $138M CAFD 2018 2017 Capacity (MW) 1,092 1,075 1,894 1,885 $ 305 $ 314 (50) (52) $ 255 $ 262 (61) (60) (52) (46) (11) (14) Sustaining capital expenditures (1) - 8 7 $ 138 $ 149 255 262 (64) (71) - 37 (117) (117) (14) 17 $ 60 $ 128 Depreciation and amortization Other Net income (MILLIONS, UNLESS NOTED) Adjusted Revenue Direct operating costs Adjusted EBITDA Adjusted interest expense Levelized principal repayments Distributions to NCI Other CAFD Adjusted EBITDA Interest expense Dec 31 Twelve months ended Gain on sale of U.K. renewable energy facilities LTA Generation (GWhs) Actual Generation (GWh) Average Adj. Revenue per MWh (MILLIONS, EXCEPT AS NOTED) 2018 2017 2018 2017 North America Utility Solar 1,021 1,008 139 $ 137 $ International Utility Solar (1) 257 244 117 120 Distributed Generation 541 535 248 268 Total 1,819 1,787 168 $ 173 $ (1) Average Adjusted Revenue per MWh excludes pass-through transmission costs.

Regulated Solar and Wind Performance Highlights Regulated Solar and Wind assets contribution following the acquisition of Saeta in June 2018 Adjusted EBITDA and CAFD were $158 million and $61 million, respectively Spanish market revenues have been ahead of budget due to very high market prices offset in part by lower wind resource (8%) and lower solar irradiation (9%) Net income was $38 million with interest expense and income taxes in line with expectations 792 MW capacity $61M CAFD (MILLIONS, UNLESS NOTED) 2018 Capacity (MW) 792 LTA Generation (GWh) 1,732 Adjusted Revenue $ 202 Direct operating costs (44) Adjusted EBITDA $ 158 Adjusted interest expense (35) Levelized principal repayments (60) Other (2) CAFD $ 61 Adjusted EBITDA 158 Interest expense (16) Income taxes (11) Depreciation and amortization (78) Regulated Solar and Wind price band adjustment (12) Other (3) Net income $ 38 Twelve months ended Dec 31 346 467 Return on Investment Revenue $ 84 $ 20 per KW per month $ 37 $ 20 per KW per month Return on Operation Revenue $ 19 $ 56 / MWh $ - $ - Market Revenue (1) $ 30 $ 78 / MWh $ 32 $ 62 / MWh Adjusted Revenue $ 133 $ $385 $ 69 $ $149 (1) Includes $3 million of insurance compensation for revenue losses Actual Results Generation (GWh) (MILLIONS, UNLESS NOTED) Actual Results Average Adj. Revenue per MWh Regulated Solar Regulated Wind Twelve months ended Dec 31 Twelve months ended Dec 31 Average Adj. Revenue per MWh

Corporate The following table presents our Corporate segment’s financial results: Performance Highlights Direct operating costs were in line with 2017 Interest expense was higher than 2017, primarily driven by revolver and sponsor line draws to fund the Saeta transaction and interest expense on the $350 million Term Loan B issued in Q4 2017 to replace Midco debt within the Wind segment. These were offset in part by the Q4 2017 refinancing of our high yield bonds with interest saving of ~200 bps, and the savings from the repricing of the Term Loan B in Q2 2018 (spread reduction of ~75 bps) Net loss of $207 million was $108 million lower than 2017, primarily due to loss on extinguishment of debt caused by Senior Notes financing in Q4 2017 and lower non-operating general and administrative expenses in 2018 2018 2017 $ (29) $ (30) Settled FX gain / (loss) 1 - $ (28) $ (30) (15) (4) (110) (102) $ (153) $ (136) (28) (30) (118) (114) 3 20 (15) - (36) (97) Loss on extinguishment of debt 1 (78) (14) (16) Net loss $ (207) - (315) Other Adjusted interest expense CAFD Adjusted EBITDA Interest expense Non-operating general and administrative expenses Direct operating costs Adjusted EBITDA Management fee Income tax (expense)/benefit Acquisition and related costs Twelve months ended Dec 31 (MILLIONS, UNLESS NOTED)

Liquidity We operate with sufficient liquidity to enable us to fund expected growth initiatives, capital expenditures, and distributions, and to provide protection against any sudden adverse changes in economic circumstances or short-term fluctuations in generation Principal sources of liquidity are cash flows from operations, our credit facilities, up-financings of subsidiary borrowings and proceeds from the issuance of securities Corporate liquidity and available capital were $695 million and $1,017 million, respectively, as of December 31, 2018: (MILLIONS, UNLESS NOTED) Unrestricted corporate cash $ 53 $ 47 Project-level distributable cash Cash available to corporate Credit facilities: Committed revolving credit facility Drawn portion of revolving credit facilities Revolving line of credit commitments Undrawn portion of Sponsor Line Available portion of credit facilities Corporate liquidity $ 695 $ 855 Other project-level unrestricted cash 178 Project-level restricted cash 144 Available capital $ 1,017 $ 1,012 Dec 31, 2018 Dec 31, 2017 18 21 71 68 600 450 (377) (60) 60 97 (99) (103) 500 500 624 787

Maturity Profile We finance our assets primarily with project level debt that generally has long-term maturities that amortize over the contract life, few restrictive covenants and no recourse to either TerraForm Power or other projects We have long-dated, staggered debt maturities The following table summarizes our scheduled principal repayments, overall maturity profile and average interest rates associated with our borrowings over the next five years: ($ IN MILLIONS) Weighted Average Life (Years) 2019 2020 2021 2022 2023 Thereafter Total Weighted Average Interest Rate (%) Principal Repayments Corporate borrowings Notes 7 $ - $ - $ - $ - $ 500 $ 1,000 $ 1,500 5.1% Term Loan 4 3 4 4 336 - - 347 4.5% Revolver 3 - - - - 377 - 377 4.7% Total corporate 6 3 4 4 336 877 1,000 2,224 4.9% Non-recourse debt Utility scale 17 52 42 43 46 48 627 858 5.9% Distributed generation 6 28 18 18 19 119 33 235 5.0% Solar 15 80 60 61 65 167 660 1,093 5.7% Wind 9 76 73 75 229 47 470 970 4.9% Regulated energy 12 117 112 118 124 130 915 1,516 4.1% Total non-recourse 12 273 245 254 418 344 2,045 3,579 4.8% Total borrowings 10 $ 276 $ 249 $ 258 $ 754 $ 1,221 $ 3,045 $ 5,803 4.9%

Contract Profile Our portfolio has a weighted-average remaining contract duration of ~13 years. Over the next five years, contracts accounting for 10% of our expected generation expire. We are focused on securing new long-term contracts through recontracting or repowering as these contracts expire The majority of our long-term contracted power is with investment-grade counterparties. The composition of our counterparties under power purchase agreements is as follows: Public utilities: 56% Government institutions: 26% Financial institutions: 12% Commercial and industrial customers: 6% The following table sets out our contracted generation over the next five years as a percentage of expected generation. We currently have a contracted profile of approximately 96% of future generation and our goal is to maintain this profile going forward 2019 2020 2021 2022 2023 Contracted Solar 100% 100% 100% 100% 100% Wind 93% 89% 85% 84% 84% Regulated Solar and Wind 100% 100% 100% 100% 100% Total Portfolio Contracted 96% 93% 90% 90% 90% Uncontracted Solar 0% 0% 0% 0% 0% Wind 7% 11% 15% 16% 16% Regulated Solar and Wind 0% 0% 0% 0% 0% Total Portfolio Uncontracted 4% 7% 10% 10% 10% For the Year ended 31 December

Quarterly Performance

Q4 2018 Highlights During the fourth quarter, our portfolio delivered Net loss, Adjusted EBITDA and CAFD of $30 million, $170 million and $27 million, respectively, versus $142 million, $110 million and $26 million, respectively, in Q4 2017 Net loss was $112 million lower than 2017, primarily due to loss on extinguishment of debt caused by Senior Notes financing in Q4 2017 Adjusted EBITDA increased by $60 million largely attributable to the contribution from the European platform, partially offset by lower wind resource in the Central Wind region, the impact of Texas pricing and lower SREC revenues due to 2017 timing of collections CAFD increased $1 million primarily due to higher Adjusted EBITDA, partially offset by increased debt service costs in Solar relating to the Saeta acquisition funding plan Excluding the European platform, the total generation in Q4 2018 of 1,742 GWh was 6% lower than prior year, primarily due to lower resource in the Central and Texas Wind regions and lower resource in the solar segment, particularly in Canada (MILLIONS) Actual Generation LTA Generation Q4 2018 Q4 2017 Q4 2018 Q4 2018 Q4 2017 Q4 2018 Q4 2017 Q4 2018 Q4 2017 Q4 2018 Q4 2017 Wind 1,567 1,491 1,755 $ 97 $ 87 $ 70 $ 61 $ 31 $ 35 $ (2) $ (6) Solar 352 361 369 62 70 50 57 18 28 5 3 Regulated Solar and Wind 295 - 309 76 - 58 - 19 - 2 - Corp - - - - - (8) (8) (41) (37) (35) (139) Total 2,214 1,852 2,433 $ 235 $ 157 $ 170 $ 110 $ 27 $ 26 $ (30) $ (142) (GWh) Adjusted Revenue Adjusted EBITDA CAFD Net Income (Loss)

Appendix 1 – Reconciliation of Non-GAAP Measures

This communication contains references to Adjusted Revenue, Adjusted EBITDA, and cash available for distribution (“CAFD”), which are supplemental Non-GAAP measures that should not be viewed as alternatives to GAAP measures of performance, including revenue, net income (loss), operating income or net cash provided by operating activities. Our definitions and calculation of these Non-GAAP measures may differ from definitions of Adjusted Revenue, Adjusted EBITDA and CAFD or other similarly titled measures used by other companies. We believe that Adjusted Revenue, Adjusted EBITDA and CAFD are useful supplemental measures that may assist investors in assessing the financial performance of the Company. None of these Non-GAAP measures should be considered as the sole measure of our performance, nor should they be considered in isolation from, or as a substitute for, analysis of our financial statements prepared in accordance with GAAP, which are available on our website at www.terraform.com, as well as at www.sec.gov. We encourage you to review, and evaluate the basis for, each of the adjustments made to arrive at Adjusted Revenue, Adjusted EBITDA and CAFD. Calculation of Non-GAAP Measures We define Adjusted Revenue as operating revenues, net, adjusted for non-cash items, including (i) unrealized gain/loss on derivatives, (ii) amortization of favorable and unfavorable rate revenue contracts, net, and (iii) an adjustment for wholesale market revenues to the extent above or below the regulated price bands. We define Adjusted EBITDA as net income (loss) plus (i) depreciation, accretion and amortization, (ii) non-cash general and administrative costs, (iii) interest expense, (iv) income tax (benefit) expense, (v) acquisition related expenses, and (vi) certain other non-cash charges, unusual or non-recurring items and other items that we believe are not representative of our core business or future operating performance. We define “cash available for distribution” or “CAFD” as Adjusted EBITDA (i) minus cash distributions paid to non-controlling interests in our renewable energy facilities, if any, (ii) minus annualized scheduled interest and project level amortization payments in accordance with the related borrowing arrangements, (iii) minus average annual sustaining capital expenditures (based on the long-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, (iv) plus or minus operating items as necessary to present the cash flows we deem representative of our core business operations. As compared to the prior year periods, we revised our definition of CAFD to (i) exclude adjustments related to deposits into and withdrawals from restricted cash accounts, required by project financing arrangements, (ii) replace sustaining capital expenditures payment made in the year with the average annualized long-term sustaining capital expenditures to maintain reliability and efficiency of our assets, and (iii) annualized debt service payments. We revised our definition of CAFD as we believe the revised definition provides a more meaningful measure for investors to evaluate our financial and operating performance and ability to pay dividends. For items presented on an annualized basis, we present actual cash payments as a proxy for an annualized number until the period commencing January 1, 2018. Furthermore, to provide investors with the most appropriate measures to assess the financial and operating performance of our existing fleet and the ability to pay dividends in the future, we have excluded results associated with our U.K. solar and Residential portfolios, which were sold in 2017, from Adjusted Revenue, Adjusted EBITDA and CAFD reported for all periods. Use of Non-GAAP Measures We disclose Adjusted Revenue because it presents the component of operating revenue that relates to energy production from our plants, and is, therefore, useful to investors and other stakeholders in evaluating performance of our renewable energy assets and comparing that performance across periods in each case without regard to non-cash revenue items. We disclose Adjusted EBITDA because we believe it is useful to investors and other stakeholders as a measure of our financial and operating performance and debt service capabilities. We believe Adjusted EBITDA provides an additional tool to investors and securities analysts to compare our performance across periods without regard to interest expense, taxes and depreciation and amortization. Adjusted EBITDA has certain limitations, including that it: (i) does not reflect cash expenditures or future requirements for capital expenditures or contractual liabilities or future working capital needs, (ii) does not reflect the significant interest expenses that we expect to incur or any income tax payments that we may incur, and (iii) does not reflect depreciation and amortization and, although these charges are non-cash, the assets to which they relate may need to be replaced in the future, and (iv) does not take into account any cash expenditures required to replace those assets. Adjusted EBITDA also includes adjustments for goodwill impairment charges, gains and losses on derivatives and foreign currency swaps, acquisition related costs and items we believe are infrequent, unusual or non-recurring, including adjustments for general and administrative expenses we have incurred as a result of the SunEdison bankruptcy. We disclose CAFD because we believe cash available for distribution is useful to investors and other stakeholders in evaluating our operating performance and as a measure of our ability to pay dividends. CAFD is not a measure of liquidity or profitability, nor is it indicative of the funds needed by us to operate our business. CAFD has certain limitations, such as the fact that CAFD includes all of the adjustments and exclusions made to Adjusted EBITDA described above. The adjustments made to Adjusted EBITDA and CAFD for infrequent, unusual or non-recurring items and items that we do not believe are representative of our core business involve the application of management judgment, and the presentation of Adjusted EBITDA and CAFD should not be construed to infer that our future results will be unaffected by infrequent, non-operating, unusual or non-recurring items. In addition, these measures are used by our management for internal planning purposes, including for certain aspects of our consolidated operating budget, as well as evaluating the attractiveness of investments and acquisitions. We believe these Non-GAAP measures are useful as a planning tool because it allows our management to compare performance across periods on a consistent basis in order to more easily view and evaluate operating and performance trends and as a means of forecasting operating and financial performance and comparing actual performance to forecasted expectations. For these reasons, we also believe these Non-GAAP measures are also useful for communicating with investors and other stakeholders. Calculation and Use of Non-GAAP Measures

Reconciliation of Non-GAAP Measures for the Twelve Months Ended December 31, 2018 and 2017 Twelve Months Ended Twelve Months Ended December 31, 2018 December 31, 2017 (MILLIONS, EXCEPT AS NOTED) Wind Solar Regulated Solar and Wind Corp Total Wind Solar Corp Total Operating revenues, net 281 $ 299 $ 187 $ - $ 767 $ 273 $ 337 $ - $ 610 $ Unrealized (gain) loss on commodity contract derivatives, net (a) 4 - - - 4 7 - - 7 Amortization of favorable and unfavorable rate revenue contracts, net (b) 32 7 - - 39 32 8 - 40 Regulated Solar and Wind price band adjustment (c) - - 12 - 12 - - - - Adjustment for asset sales - - - - - - (15) - (15) Other items (d) - (1) 3 - 2 - (16) - (16) Adjusted Revenue 317 $ 305 $ 202 $ - $ 824 $ 312 $ 314 $ - $ 626 $ Direct operating costs (e) (112) (50) (44) (29) (235) (106) (52) (30) (188) Settled FX gain - - - 1 1 - - - - Adjusted EBITDA 205 $ 255 $ 158 $ (28) $ 590 $ 206 $ 262 $ (30) $ 438 $ Non-operating general and administrative expenses (f) (4) (9) - (36) (49) - - (97) (97) Stock-based compensation expense - - - - - - - (17) (17) Acquisition and related costs, including affiliate - - - (15) (15) - - - - Depreciation, accretion and amortization expense (g) (183) (117) (78) (2) (380) (168) (117) (2) (287) Impairment charges - (15) - - (15) - (1) - (1) Loss on extinguishment of debt - - - 1 1 (3) - (78) (81) Gain on sale of U.K. renewable energy facilities - - - - - - 37 - 37 Interest expense, net (51) (64) (16) (118) (249) (77) (71) (114) (262) Income tax benefit (expense) - 20 (11) 3 12 - - 20 20 Adjustment for asset sales - - - - - - 10 - 10 Regulated Solar and Wind price band adjustment (c) - - (12) - (12) - - - - Management Fee (o) - - - (15) (15) - - (3) (3) Other non-cash or non-operating items (h) (11) (10) (3) 3 (21) (7) 8 6 7 Net income (loss) (44) $ 60 $ 38 $ (207) $ (153) $ (49) $ 128 $ (315) $ (236) $ Twelve Months Ended Twelve Months Ended December 31, 2018 December 31, 2017 (MILLIONS, EXCEPT AS NOTED) Wind Solar Regulated Solar and Wind Corp Total Wind Solar Corp Total Adjusted EBITDA 205 $ 255 $ 158 $ (28) $ 590 $ 206 $ 262 $ (30) $ 438 $ Fixed management fee (o) - - - (10) (10) - - (3) (3) Variable management fee (o) - - - (5) (5) - - (1) (1) Adjusted interest expense (i) (50) (61) (35) (110) (256) (72) (60) (102) (234) Levelized principal payments (j) (61) (52) (60) - (173) (53) (46) - (99) Cash distributions to non-controlling interests (k) (15) (11) - - (26) (16) (14) - (30) Sustaining capital expenditures (l) (7) (1) - - (8) (2) - - (2) Other (m) 8 8 (2) - 14 12 7 - 19 Cash available for distribution (CAFD) (n) 80 $ 138 $ 61 $ (153) $ 126 75 $ 149 $ (136) $ 88 $

Reconciliation of Non-GAAP Measures for the Three Months Ended December 31, 2018 and 2017 Three Months Ended Three Months Ended Twelve Months Ended December 31, 2018 December 31, 2017 (MILLIONS, EXCEPT AS NOTED) Wind Solar Regulated Solar and Wind Corp Total Wind Solar Corp Total Operating revenues, net 81 $ 61 $ 71 $ - $ 213 $ 74 $ 62 $ - $ 136 $ Unrealized (gain) loss on commodity contract derivatives, net (a) 8 - - - 8 8 - - 8 Amortization of favorable and unfavorable rate revenue contracts, net (b) 8 2 - - 10 8 2 - 10 2017 Incentive revenue recognition recast (n) - - - - - (3) 12 - 9 Regulated Solar and Wind price band adjustment (c) - - 2 - 2 - - - - Other items (d) - (1) 3 - 2 - (6) - (6) Adjusted Revenue 97 $ 62 $ 76 $ - $ 235 $ 87 $ 70 $ - $ 157 $ Direct operating costs (e) (27) (12) (18) (9) (66) (26) (13) (8) (47) Settled FX gain - - - 1 1 - - - - Adjusted EBITDA 70 $ 50 $ 58 $ (8) $ 170 $ 61 $ 57 $ (8) $ 110 $ Non-operating general and administrative expenses (f) (4) (9) - 2 (11) - - (29) (29) Stock-based compensation expense - - - - - - - (10) (10) Depreciation, accretion and amortization expense (g) (45) (29) (38) - (112) (42) (29) - (71) Impairment charges - - - - - - (1) - (1) Loss on extinguishment of debt - - - 1 1 (3) - (78) (81) Gain on sale of U.K. renewable energy facilities - - - - - - - - - Interest expense, net (14) (17) (11) (30) (72) (13) (16) (26) (55) Income tax benefit (expense) 1 21 (6) 6 22 - - 17 17 Regulated Solar and Wind price band adjustment (c) - - (2) - (2) - - - - Management Fee (o) - - - (4) (4) - - (3) (3) Other non-cash or non-operating items (h) (10) (11) 1 (2) (22) (9) (8) (2) (19) Net income (loss) (2) $ 5 $ 2 $ (35) $ (30) $ (6) $ 3 $ (139) $ (142) $ Three Months Ended Three Months Ended Twelve Months Ended December 31, 2018 December 31, 2017 (MILLIONS, EXCEPT AS NOTED) Wind Solar Regulated Solar and Wind Corp Total Wind Solar Corp Total Adjusted EBITDA 70 $ 50 $ 58 $ (8) $ 170 $ 61 $ 57 $ (8) $ 110 $ Fixed management fee (o) - - - (3) (3) - - (3) (3) Variable management fee (o) - - - (2) (2) - - (1) (1) Adjusted interest expense (i) (14) (16) (14) (28) (72) (9) (16) (26) (51) Levelized principal payments (j) (18) (15) (27) - (60) (14) (10) - (24) Cash distributions to non-controlling interests (k) (3) (3) - - (6) (3) (4) - (7) Sustaining capital expenditures (l) (2) - - - (2) (1) - - (1) Other (m) (2) 2 2 - 2 1 1 1 3 Cash available for distribution (CAFD) (n) 31 $ 18 $ 19 $ (41) $ 27 $ 35 $ 28 $ (37) $ 26 $

Reconciliation of Non-GAAP Measures for the Three and Twelve Months Ended December 31, 2018 and 2017 Represents unrealized (gain)/loss on commodity contracts associated with energy derivative contracts that are accounted for at fair value with the changes recorded in operating revenues, net. The amounts added back represent changes in the value of the energy derivative related to future operating periods, and are expected to have little or no net economic impact since the change in value is expected to be largely offset by changes in value of the underlying energy sale in the spot or day-ahead market. Represents net amortization of purchase accounting related to intangibles arising from past business combinations related to favorable and unfavorable rate revenue contracts. Represents Regulated Solar and Wind Price Band Adjustment to Return on Investment Revenue as dictated by market conditions. To the extent that the wholesale market price is greater or less than a price band centered around the market price forecasted by the Spanish regulator during the preceding three years, the difference in revenues assuming average generation accumulates in a tracking account. The Return on Investment is either increased or decreased in order to amortize the balance of the tracking account over the remaining regulatory life of the assets. Primarily represents recognized deferred revenue related to the upfront sale of investment tax credits, insurance compensation for revenue losses, and adjustments for SREC replacements. In the three months ended December 31, 2017, reclassifies $1 million wind sustaining capital expenditure into direct operating costs, which will now be covered under long-term service contracts (“LTSA”) with General Electric (“GE”). In the twelve months ended December 31, 2017, reclassifies $6 million wind sustaining capital expenditure into direct operating costs. Pursuant to the historical management services agreement (the “Management Services Agreement,”) with SunEdison, Inc. (“SunEdison”), SunEdison agreed to provide or arrange for other service providers to provide management and administrative services to us in 2017. In the twelve months ended December 31, 2017, we accrued costs incurred for management and administrative services that were provided by SunEdison under the Management Services Agreement that were not reimbursed by TerraForm Power and were treated as an addback in the reconciliation of net loss to Adjusted EBITDA. In addition, non-operating items and other items incurred directly by TerraForm Power that we do not consider indicative of our core business operations are treated as an addback in the reconciliation of net loss to Adjusted EBITDA. These items include, but are not limited to, extraordinary costs and expenses related primarily to restructuring, IT system arrangements, relocation of the headquarters to New York, legal, advisory and contractor fees associated with the bankruptcy of SunEdison and certain of its affiliates (the “SunEdison bankruptcy”) and investment banking, and legal, third party diligence and advisory fees associated with the Brookfield and Saeta transactions, dispositions and financings. The Company’s normal general and administrative expenses in Corporate, paid by Terraform Power, are the amounts shown below and were not added back in the reconciliation of net loss to Adjusted EBITDA ($ in millions): Includes reductions/(increases) within operating revenues due to net amortization of favorable and unfavorable rate revenue contracts as detailed in the reconciliation of Adjusted Revenue. Represents other non-cash items as detailed in the reconciliation of Adjusted Revenue and associated footnote and certain other items that we believe are not representative of our core business or future operating performance, including but not limited to: loss/(gain) on foreign exchange (“FX”), unrealized loss on commodity contracts, loss on investments and receivables with affiliate, loss on disposal of renewable energy facilities, and wind sustaining capital expenditure previously reclassified. Represents project-level and other interest expense and interest income attributed to normal operations. The reconciliation from Interest expense, net as shown on the Consolidated Statements of Operations to adjusted interest expense applicable to CAFD is as follows: $ in millions Q4 2018 Q4 2017 YTD 2018 YTD 2017 Operating general and administrative expenses in Corporate $ 9 $ 8 $ 29 $ 30 $ in millions Q4 2018 Q4 2017 YTD 2018 YTD 2017 Interest expense, net $ (72) $ (55) $ (249) $ (262) Amortization of deferred financing costs and debt discounts 3 4 11 24 Adjustment for asset sales - - - 8 Other, primarily fair value changes in interest rate swaps and purchase accounting adjustments due to acquisition (3) 1 (18) (4) Adjusted interest expense $ (72) $ (50) $ (256) $ (234)

Reconciliation of Non-GAAP Measures for the Three and Twelve Months Ended December 31, 2018 and 2017 (continued) Represents levelized project-level and other principal debt payments to the extent paid from operating cash. Represents cash distributions paid to non-controlling interests in our renewable energy facilities. The reconciliation from Distributions to non-controlling interests as shown on the Consolidated Statement of Cash Flows to Cash distributions to non-controlling interests, net for the three months ended December 31, 2018 and 2017 is as follows: Represents long-term average sustaining capex starting in 2018 to maintain reliability and efficiency of the assets. Represents other cash flows as determined by management to be representative of normal operations including, but not limited to, wind plant “pay as you go” contributions received from tax equity partners, interconnection upgrade reimbursements, major maintenance reserve releases or (additions), and releases or (postings) of collateral held by counterparties of energy market hedges for certain wind plants, and recognized SREC gains that are covered by loan agreements. CAFD in 2017 was recast as follows to present the levelized principal payments, adjusted interest expense, and incentive revenue recognition was recast to provide period to period comparisons that are consistent and more easily understood. The 2017 incentive revenue was recast based on an estimate in the same proportions as the 2018 phasing, which differs from the actual 2017 phasing due to the adoption of the revenue recognition standard. In the twelve months ended December 31, 2017, CAFD remained $88 million as reported previously. Represents management fee that is not included in Direct operating costs. $ in millions Q4 2018 Q4 2017 YTD 2018 YTD 2017 Distributions to non-controlling interests $ (8) $ (7) $ (29) $ (30) Buyout of non-controlling interests 2 - 2 - Adjustment for non-operating cash distributions - - 1 - Cash distributions to non-controlling interests, net $ (6) $ (7) $ (26) $ (30) $ in millions Q1 2017 Q2 2017 Q3 2017 Q4 2017 2017 Cash available for distribution (CAFD) before debt service reported $ 104 $ 120 $ 106 $ 91 $ 421 Levelized principal payments (25) (25) (25) (24) (99) Adjusted interest expense (60) (61) (63) (50) (234) Estimated incentive revenue recognition recasted (1) (9) 1 9 - Cash available for distribution (CAFD), recast $ $18 $ $25 $ $19 $ $26 $ $88

Appendix 2 – Additional Information

2018 Annualized Long-Term Average Generation (LTA) GENERATION (GWh) (1)(2) Q1 Q2 Q3 Q4 Total Wind (3) Central Wind 779 664 445 762 2,650 Texas Wind 454 472 349 438 1,713 Northeast Wind 324 227 175 297 1,023 International Wind 186 160 163 184 693 Hawaii Wind 66 80 87 74 307 1,809 1,603 1,219 1,755 6,386 Solar (4) North America Utility Solar 219 343 319 193 1,074 International Utility Solar 66 49 52 73 240 Distributed Generation 115 185 177 103 580 400 577 548 369 1,894 Regulated Solar and Wind Spain Wind 362 243 190 251 1,046 CSP 83 249 296 58 686 445 492 486 309 1,732 Total 2,654 2,672 2,253 2,433 10,012 (1) (2) (3) (4) LTA is calculated on an annualized basis from the beginning of the year, regardless of the acquisition or commercial operation date. Wind LTA is the expected average generation resulting from simulations using historical wind speed data normally from 1997 to 2016 (20 years), adjusted to the specific location and performance of the different wind farms. Solar LTA is the expected average generation resulting from simulations using historical solar irradiance level data normally from 1998 to 2016 (19 years), adjusted to the specific location and performance of the different sites. LTA does not include Q4 acquisitions for Tinkham Hill Expansion assets and IFM assets. The Tinkham Hill Expansion asset is expected to achieve its commercial operation date during the second quarter of 2019.

Spanish Regulated Revenue Framework Under the Spanish regulatory framework, revenues have three components Return on Investment: All renewable power plants receive a monthly capacity payment. This capacity payment, when combined with margin from the market revenues forecasted by the regulator, is sized to allow the generator to earn the regulated rate of return (currently 7.4%) on its deemed capital investment. The Return on Investment is recalculated every three years. Since the capacity payment is a fixed payment, it is very stable, with no volume or price risk. Historically, this revenue stream has comprised in the range of 65% of our regulated revenue. Return on Operation: Applicable only to our concentrated solar power plants (CSP), this revenue stream consists of an additional payment for each MWh produced to recover deemed operating costs that are in excess of market revenue forecasted by the regulator, such that the margin on forecasted market revenues is equal to zero. The Return on Operations is recalculated every three years. Aside from the volumetric risk associated with production, this revenue stream has no market price risk and has historically comprised less than 10% of our regulated revenue. Market Revenue: Renewable power plants sell power into the wholesale market and receive the market-clearing price for all MWhs they produce. Although this revenue stream is subject to both volume and market price risk, its impact on overall revenues is mitigated by the reset of the Return on Investment every three years. Market revenues historically comprise in the range of 25% of our regulated revenue yet only 8% of TerraForm Power’s consolidated revenues. Every three years, the regulated components of revenue (i.e., the Return on Investment and Return on Operations) are reset in order to mitigate the overall variability of revenues. Based on market conditions, the regulator updates its market price forecast. Since the combination of margin from market revenues forecasted by the regulator and the regulated components of revenue are sized to equal the regulated return, the Return on Investment and Return on Operations are reset accordingly. Furthermore, to the extent that the wholesale market price is greater or less than a price band centered around the market price forecasted by the regulator during the preceding three years, the difference in revenues assuming average generation accumulates in a tracking account. The Return on Investment is either increased or decreased in order to amortize the balance of the tracking account over the remaining regulatory life of the assets. Over time, this adjustment dampens the impact of wholesale price variability. Every six years, the regulated rate of return may be reset to a level that allows generators to earn a fair rate of return in light of market conditions. The regulator may take factors such as interest rates, the equity market premium, etc. into account when making its recommendation, and any change to the regulated rate of return must be proposed by the Spanish government and approved by a decree of parliament. To the extent there is no decree of parliament, the regulated rate of return will remain unchanged. In early November, after receiving input from stakeholders, the regulator made a final non-binding recommendation to reset the regulated rate of return to 7.09% from the current 7.40%. Based on this recommendation and other considerations, parliament may decide to change the regulated rate

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