Exhibit 99.2

 Q3 2019 Supplemental Information  Three Months Ended September 30, 2019 

   This communication contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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, distribution growth, CAFD accretion, earnings, revenues, income, loss, capital expenditures, liquidity, capital structure, margin enhancements, cost savings, 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.Important factors that could cause actual results to differ materially from our expectations, or cautionary statements, are listed below and further disclosed under the section entitled Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018 and in our subsequent Quarterly Reports on Form 10-Q: risks related to weather conditions at our wind and solar assets; 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 close the acquisitions of, and integrate the projects that we expect to acquire from, third parties, including our ability to successfully integrate our recently acquired portfolio of solar distributed generation assets; our ability to successfully achieve expected synergies and to successfully execute on the funding plan for our recently acquired portfolio of solar distributed generation assets, including our ability to successfully close any contemplated capital recycling initiatives; our ability to realize the anticipated benefits from acquisitions; our ability to close, implement and realize the benefit of our cost and performance enhancement initiatives, including long-term service agreements and our ability to realize the anticipated benefits from such initiatives; the willingness and ability of counterparties to fulfill their obligations under offtake agreements; price fluctuations, termination provisions and buyout provisions in offtake agreements; 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 Asset Management Inc.; 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 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 Annual Report on Form 10-K for the year ended December 31, 2018 and in subsequent Quarterly Reports on Form 10-Q, as well as additional factors we may describe from time to time in our 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 

 Q3 2019 and Recent Highlights  Terraform Power generated cash available for distribution (“CAFD”) of $48 million compared to $46 million in the same period of the prior year, primarily due to higher generation in Spain, cost saving initiatives, contributions from recently completed acquisitions offset by higher management fees, lower market prices in Spain and increased cost of covering our hedge obligations during the summer in TexasClosed on the acquisition of approximately 320 MW1 Distributed Generation (“DG”) portfolio in the United States from AltaGas for ~$720 millionIn October, we completed the following transactions, providing approximately $1.2 billion of corporate liquidity:Issued $300 million of new equity by way of a $250 million public offering and concurrent $50 million private placement with BrookfieldClosed a $700 million offering of 10-year senior notes. The notes priced at a coupon of 4.75%. Net proceeds were used to repay the $300 million notes due 2025 and the $344 million Term Loan B due 2022. The refinancing will lock in debt service savings of ~$6 million per year and extend our maturity profile, such that we have no corporate maturities until 2023Upsized Corporate Revolving Credit Facility by $200 million to $800 million with 1-year extension to 2024 Executed a 10-year outsourcing Framework Agreement with SMA Solar Technology to provide operations and maintenance for our North American solar fleet, which is expected to reduce costs by $5 million per year and mitigate operational risk of the portfolio through performance guaranteesDeclared a Q4 2019 dividend of $0.2014 per share, implying $0.8056 per share on an annual basis  Includes certain Delayed Projects for which AltaGas have not yet received the required third party consents or have not completed construction, and will be transferred to TERP once such third party consents are received or construction is completed, subject to certain terms and conditions. As of October 2019, the Delayed Projects represent approximately 17 MW of the combined nameplate capacity of the acquired renewable energy facilities.  

 2,063GWh Generation  Q3 2019 Highlights (continued)  Performance Highlights  Our portfolio delivered in Q3 net loss, Adjusted EBITDA and CAFD of $(62) million, $195 million and $48 million, respectively, versus $(19) million, $197 million and $46 million, respectively, in the prior yearAdjusted EBITDA decreased by $2 million due to lower market prices in Spain and increased cost of covering our hedge obligations during the summer in Texas. These are partially offset by higher SREC prices, benefits from our O&M cost saving initiatives, and higher production in our regulated wind plants in SpainCAFD increased $2 million due to lower distributions to non-controlling interests (NCI) from timing and buyouts, offset by increased management fees Net loss increased $43 million due in part to higher interest expense as part of the Saeta acquisition funding plan and unrealized foreign currency lossesQuarterly CAFD per share of $0.23, 5% higher than the same period of 2018  Key Performance Metrics  $48 millionCAFD 

 Based on the closing price of TERP’s Class A common stock of $16.89 per share October 8, 2019Based on 2019 annualized target dividend of $0.8056 per share and the closing price of TERP’s Class A common stock of $16.89 per share on October 8, 2019As of October 8, 2019. As of September 30, 2019, Brookfield and institutional partners was 65% of TERP’s outstanding Class A common stockNet Operating Losses (“NOLs”)Includes power assets from AltaGas DG portfolio acquisitionIn 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. Includes the Delayed Projects as described in the footnote on slide 3 of this presentationExpressed as a percentage of total MW owned Based on projected revenue for 2019, including AltaGas DG Portfolio annualized revenue  Overview of TerraForm Power  TERP’s mandate is to acquire, own and operate wind and solar assets in North America and Western Europe  ~$3.8 Billion1Market Capitalization  TERPNASDAQ  ~4.8% Yield2$0.8056 Target 2019 per Share Dividend  ~61.5%Ownership by Brookfield and Institutional Partners3  Significant NOLs4 Tax advantaged structure (C Corp)     $9 billionTotal power assets5  4,066 MWof capacity6  59% / 41%wind / solarcapacity7  45% / 55%wind / solarprojected revenue8 

 Renewables Portfolio with Scale in North America and Western Europe  Owner and operator of an over 4,000 MW diversified portfolio of high-quality wind and solar assets, underpinned by long-term contracts    Wind  Solar  Total  US  1,536 MW  1,239 MW  2,775 MW  International  856 MW  435 MW  1,291 MW  Total  2,392 MW  1,674 MW  4,066 MW          Spain  Portugal  Uruguay    Chile                                                                                                                                                                                                                                                    U.K.                                                                                                                                                   

 Generation and Revenue  Long-term average annual generation (“LTA”) is expected generation at the point of delivery, net of all recurring losses and constraintsWe compare actual generation levels against the long-term average to highlight the impact of operational factors that affect 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  Generation excludes AltaGas DG portfolio, which was acquired at the end of Q3 2019Non-GAAP measures. See Appendix 1 and “Reconciliation of Non-GAAP Measures.” Adjusted for unrealized (gain) loss on commodity contract derivatives, amortization of favorable and unfavorable rate revenue contracts, and other non-cash items 

 Selected Income Statement and Balance Sheet Information by Segment  Balance Sheet  Income Statement 

 Operating Segments   

   Adjusted EBITDA and CAFD were $37 million and ($4) million, respectively, versus $36 million and ($1) million, respectively, in the prior yearWind generation this quarter was approximately 14% lower than our LTA, primarily due to lower availability in North America, mainly in our Central and Texas wind portfolios, and to a lesser extent, lower wind resource, mainly in our Hawaii and Central wind portfoliosAdjusted EBITDA was $1 million higher than prior year, primarily due to the implementation of cost savings initiatives and a higher contribution from the international plants in Portugal and Uruguay due to higher generation and price, offset by increased cost of covering our hedge obligations during the summer in Texas. The transition to LTSAs with GE resulted in cost savings of $4 million in the quarter, after operations of an additional 4 sites were transferred to GE maintenance in Q3 2019CAFD was $3 million below the prior year, primarily due to debt service from the International Wind segment, related to up-financing in UruguayNet loss was ($49) million, $19 million below the prior year, primarily due to higher interest expense related to higher depreciation, up-financing, and one-time blade repairs costs related to the transition to the GE LTSAs  Wind  Performance Highlights   1,854 MWcapacity  ($4)MCAFD 

 Solar  Performance Highlights   1,420 MWCapacity (1)  $59MCAFD  Adjusted EBITDA and CAFD were $90 million and $59 million, respectively, versus $84 million and $54 million, respectively, in the prior yearAdjusted EBITDA increased by $7 million compared to the prior year, primarily due to higher SREC prices and contribution from the Integrys acquisition completed in Q2 2019CAFD increased by $5 million compared to the prior year due to higher Adjusted EBITDA, partially offset by debt service related to new project financings, executed as part of the Saeta acquisition funding planNet income of $41 million was $3 million higher than prior year, primarily due to higher revenue offset by higher income tax expense 

 Regulated Solar and Wind  Performance Highlights   792 MWcapacity  $33MCAFD  Adjusted EBITDA and CAFD were $74 million and $33 million, respectively, versus $83 million and $33 million, respectively, in the prior yearAdjusted EBITDA decreased by $9 million compared to the prior year, primarily due to lower market prices in Spain, partially offset by increased generation from our regulated wind plants and the contribution of the assets acquired in the last 12 monthsCAFD was in line with the prior year, due to lower cash taxes in Spain offset by lower Adjusted EBITDANet income of $9 million was $15 million lower than the prior year, primarily due to lower revenue and higher non cash financial expenses  

 Corporate  The following table presents our Corporate segment’s financial results:  Performance Highlights  Corporate direct operating costs were $2 million higher in Q3 2019, primarily driven by support for growth initiatives and professional feesAdjusted interest expense was $3 million lower in Q3 2019 than the prior year, primarily driven by lower draws on our Revolver, following the completion of the Saeta acquisition funding plan Net loss of $63 million was $12 million higher than the prior year, primarily due to unrealized foreign currency exchange losses in the current period 

 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 generationCorporate liquidity was $682 million as of September 30, 2019; following our $300 million equity issuance and upsizing of our revolving credit facility, our Pro Forma corporate liquidity as of October 8, 2019 increased to $1.2 billion, including our $500 million sponsor line with Brookfield  Pro Forma as of October 8, 2019 to include (i) the concurrent public and private offerings of $300 million of the Company’s common stock and (ii) the upsize of the Company’s senior secured revolving credit facility (the “Revolver”) by $200 million to $800 million, each of which occurred on October 8, 2019.The Pro Forma column reflects the upsize of the Revolver by $200 million to $800 million that occurred on October 8, 2019.The Pro Forma column reflects the application of the proceeds received from the Company’s concurrent public and private offerings of $300 million of the Company’s common stock that occurred on October 8, 2019  ($ IN MILLIONS, UNLESS NOTED)  Pro Forma1    Sep 30, 2019    Dec 31, 2018    Unrestricted corporate cash    19     19     53  Project-level distributable cash     32     32  18    Cash available to corporate  $  51  $ 51    $ 71    Credit facilities:                Revolving credit facility commitments2    800   600     600    Drawn portion of revolving credit facilities3    (56)   (356)    (377)    Revolving line of credit commitments    (113)   (113)    (99)    Undrawn portion of Sponsor Line     500   500     500    Available portion of credit facilities  $  1,131  $ 631    $ 624    Corporate liquidity  $  1,182   $  682   $  695  Other project-level unrestricted cash    189     189  178    Project-level restricted cash     105     105  144    Available capital   $   1,476    $   976    $   1,017  

 ($ IN MILLIONS)     Weighted Average Life (Years)     2019     2020     2021     2022     2023     Thereafter     Total     Weighted Average Interest Rate (%)  Principal Repayments                                         Corporate borrowings                                         Notes1    6     -    -    -    -    500     1,000     1,500     5.1%  Term Loan2    3     1     4     4     335     -    -    344     4.5%  Revolver3     5      -     -     -     -     356      -     356      4.7%  Total corporate    5   $  1     $ 4   $  4   $  335   $  856   $  1,000   $  2,200     4.9%                                           Non-recourse debt                                         Utility scale    16     19     46     51     56     58     699   $  929     5.9%  Distributed generation4     2      4      491      16      20      122      23    $  676      5.0%  Solar    11     23     537     67     76     180     722   $  1,605     5.7%  Wind    10     28     85     87     242     60     614   $  1,116     4.9%  Regulated energy     11      45      106      112      118      124      869    $  1,374      4.1%  Total non-recourse     11   $  96   $  728   $  266   $  436   $  364   $  2,205    $  4,095      4.8%  Total borrowings as of Sep 30, 2019    9   $  97   $  732   $  270   $  771   $  1,220   $  3,205   $  6,295      4.9%  Total borrowings Pro Forma     10   $  96   $  729   $  266   $  435   $  920   $  3,606   $  6,051      4.6%  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 projectsThe following table summarizes our scheduled principal repayments, overall maturity profile and average interest rates associated with our borrowings over the next five years as of September 30, 2019 and a Pro Forma as of October 8th, 2019, to include corporate financing activities1,2,3 executed after the quarter end   Maturity Profile  Subsequent to quarter close, the senior notes due 2025 have been repaid with the proceeds of the $700 million offering issued on October 16. The Pro forma line in the table above reflects the updated maturity profile after this repaymentSubsequent to quarter close, the secured term loan due 2022 has been repaid with the proceeds of the $700 million offering issued on October 16. The Pro forma line in the table above reflects the updated maturity profile after this repaymentSubsequent to quarter close, the revolving credit facility has been upsized by $200 million up to $800 million, and maturity extended by one year to 2024. The Pro forma line in the table above reflects the updated maturity profile and the partial repaymentIncludes the $475.0 million Bridge Facility we entered into on September 26, 2019, which matures on September 25, 2020 with an optional one-year extension. We intend to refinance the balance on a long-term basis prior to maturity 

 Contract Profile  Our portfolio has a weighted-average remaining contract duration of ~13 years. Over the next five years, contracts accounting for approximately 10% of our expected generation expire. We are focused on securing new long-term contracts through recontracting as these contracts expireThe 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: 53%Government institutions: 27%Financial institutions: 11%Commercial and industrial customers: 9%  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  Includes the expected Q4 2019 generation for AltaGas DG Portfolio, which was acquired at the end of Q3 2019.  1 

 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 TerraForm Power. 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 MeasuresWe define Adjusted Revenue as operating revenues, net, adjusted for non-cash items, including (i) unrealized gain/loss on derivatives, net (ii) amortization of favorable and unfavorable rate revenue contracts, net, (iii) an adjustment for wholesale market revenues to the extent above or below the regulated price bands, and (iv) other items that we believe are representative of our core business or future operating performance.We define Adjusted EBITDA as net income (loss) plus (i) depreciation, accretion and amortization, (ii) interest expense, (iii) non-operating general and administrative costs, (iv) impairment charges, (v) (gain) loss on extinguishment of debt, (vi) acquisition and related costs, (vii) income tax (benefit) expense, (viii) adjustment for wholesale market revenues to the extent above or below the regulated price bands, (ix) management fees to Brookfield, an (x) 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 management fees to Brookfield, (ii) minus annualized scheduled interest and project level payments of principal in accordance with the related borrowing arrangements, (iii) minus cash distributions paid to non-controlling interests in our renewable energy facilities, if any, (iv) 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, and (v) plus or minus operating items as necessary to present the cash flows we deem representative of our core business operations.Use of Non-GAAP MeasuresWe 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 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 distributions. 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’s 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 they allow 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 Measuresfor the Three Months Ended September 30, 2019 and 2018 

 Reconciliation of Non-GAAP Measuresfor the Nine Months Ended September 30, 2019 and 2018 

 Reconciliation of Non-GAAP Measures  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, and losses on disposal of property, plant and equipment.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 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 and investment banking, and legal, third party diligence and advisory fees associated with acquisitions, dispositions and financings. TerraForm Power’s normal, recurring 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: Represents the Regulated Solar and Wind segment’s 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.Represents management fee that is not included in Direct operating costs.Represents other non-cash or non-operating 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, sale of transmission line access in Regulated Solar and Wind, and one-time blade repairs related to the preparation for GE transition.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. Primarily represents insurance compensation for revenue losses, transmission capacity revenue, and adjustments for solar renewable energy certificate (”SREC”) recognition due to timing.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: 

 Reconciliation of Non-GAAP Measures  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 September 30, 2019 and 2018 is as follows: Represents long-term average sustaining capital expenditures 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. 

 Appendix 2 – Additional Information   

 2019 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)(5)                  North America Utility Solar         219    343    319    193    1,074   International Utility Solar         66    49    52    73    240   North America Distributed Generation         208    329    324    205    1,066              493    721    695    471    2,380   Regulated Solar and Wind                  Spain Wind          362    243    190    251    1,046   Spain Solar         85    252    298    60    695               447    495    488    311    1,741                     Total           2,749    2,819    2,402    2,537    10,507                     (1)  LTA is calculated on an annualized basis from the beginning of the year, regardless of the acquisition or commercial operation date.  LTA is calculated on an annualized basis from the beginning of the year, regardless of the acquisition or commercial operation date.              (2)  LTA does not include Q4 acquisitions for Tinkham Hill Expansion assets. The Tinkham Hill Expansion asset is expected to achieve its commercial operation date during Q4 2019.  LTA does not include Q4 acquisitions for Tinkham Hill Expansion assets. The Tinkham Hill Expansion asset is expected to achieve its commercial operation date during Q4 2019.              (3)  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.  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.              (4)  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.  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.              (5)  Distributed Generation includes AltaGas DG portfolio, which was acquired at the end of Q3 2019. The LTA for AtlaGas DG portfolio is based on the budget of the Company.  Distributed Generation includes AltaGas DG portfolio, which was acquired at the end of Q3 2019. The LTA for AtlaGas DG portfolio is based on the budget of the Company.             

 Spanish Regulated Revenue Framework  Under the Spanish regulatory framework, revenues have three componentsReturn 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 November 2018, 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. In Spain new elections were held on November 10, 2019. The Spanish Socialist Workers’ Party (“PSOE”) won the largest number of seats in Congress, yet again they were unable to win a majority of seats to form a coalition government. The PSOE will now have to negotiate with the other parties with regards to next steps, and a resolution is not expected before early 2020. We are actively monitoring political developments in Spain, but we continue to believe that the political environment is positive for the regulated rate of return as renewables enjoy broad support across the political spectrum.  

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