TerraForm Power Reports Fourth Quarter and Full Year 2018 Results
- Invested $1.2 billion to acquire Saeta Yield, S.A.U. (“Saeta”), a 1,000 MW portfolio of high-quality wind and solar assets located primarily in Spain that established a scale operating platform in Europe
- Invested ~$28 million in organic growth initiatives with an average return on equity of ~19%
- 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 solar performance improvement plan, expected to increase annual production by ~61 GWh and revenue by ~$11 million
- Issued $650 million in equity to fund the Saeta acquisition at attractive terms pursuant to backstop arrangement with affiliates of Brookfield Asset Management
- Raised ~$160 million of non-recourse debt in conjunction with the financing plan for the Saeta acquisition
- Achieved upgrade of corporate credit rating from Moody’s to Ba3
- Repriced $350 million Term Loan B yielding projected annual savings of approximately $2.5 million
- Declared a Q1 2019 dividend of $0.2014 per share, an increase of 6% from Q4 2018, and implying $0.8056 per share on an annual basis
“During 2018, we made significant progress building the foundation to transform TerraForm Power into a fully-integrated renewable power company that delivers a sustainable, total return in the low teens to our shareholders,” said John Stinebaugh, CEO of TerraForm Power. “In 2019, we look forward to reaping the benefits from this foundation and further investing in our repowerings and other growth opportunities.”
| 3 Months Ended
| 3 Months Ended
| 12 Months Ended
| 12 Months Ended
|Net Loss ($ in millions)||(30)||(142)||(153)||(236)|
|Earnings (loss) per Share1||$(0.07)||$(0.31)||$0.07||$(1.61)|
|Adjusted EBITDA2 ($ in millions)||170||110||590||438|
|Cash Available for Distribution (“CAFD”)2 ($ in millions)||27||26||126||88|
1 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 were no weighted average Class B common stock shares outstanding (for the twelve months ended December 31, 2017, this amount was 38 million).
2 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.
While we made much progress, 2018 was a transitional year for TerraForm Power. During the course of the year, we accelerated our blade inspection and repair program due to the Raleigh outage and to prepare to turn over operations of our wind farms to GE. This resulted in a significant increase in turbine downtime. In addition, we lost a considerable amount of production from our solar fleet, which operated at an availability of 91% in the first half of the year prior to the initiation of our performance improvement plan.
For the full year 2018, TerraForm Power delivered Net Loss, Adjusted EBITDA and cash available for distribution (“CAFD”) of $(153) million, $590 million and $126 million, respectively. This represents a decrease in Net Loss of $83 million, an increase in Adjusted EBITDA of $152 million and an increase in CAFD of $38 million, compared to 2017. The improvement in our results primarily reflects two fiscal quarters of contribution from Saeta. This contribution was offset by below average North American wind production in part due to an especially strong El Niño and challenging ERCOT pricing dynamics as a result of maintenance of the transmission system, which reduced transfer capacity during peak wind resource season. Thus far in 2019, power prices in the Texas panhandle have improved as the transmission system has been fully on-line.
In 2018, North American wind production was 10% below our LTA. Of the shortfall, 4% can be attributed to poor wind resource, particularly in Hawaii and the Midwest, 2% to abnormally high non-reimbursable curtailment, 2% to the impact of the Raleigh-related outages and 2% to downtime for blade inspections and repairs. Our solar and regulated platforms performed in-line with expectations for the most part. In our solar platform, significantly reduced curtailment in Chile due to debottlenecking of the transmission grid offset low availability in the first half of the year. In our regulated platform, lower than expected solar resource was offset by wholesale electricity prices that averaged 10% higher than the prior year.
We continue to progress the execution of the $350 million non-recourse debt component of our financing plan for the Saeta acquisition. We expect to close our third and fourth project financings, raising proceeds of ~$100 million and $90 million, respectively by the end of the first half of 2019.
We also recently launched the refinancing of our wind facility in Uruguay (~95 MW). Based on negotiations with lenders, we are planning on extending the tenor, improving sizing parameters and reducing the margin. Upon expected closing in the second quarter, we anticipate upsizing the financing by approximately $60 million. To further support corporate liquidity, we released $24 million in cash in December by collateralizing reserve accounts with letters of credit at two wind projects in North America. In addition, we launched the consent process for certain Spanish projects to replace cash funded reserve accounts with letters of credit.
To date, we have signed LTSAs with GE for 10 of 16 projects in our North American wind fleet. In parallel, we have made significant progress obtaining the required lender and tax equity partner consents and are in negotiations with service providers for the early termination of existing service contracts. GE is now fully operating six sites, and we anticipate handing over the remaining sites in the first half of this year.
Beginning in Q3 2018, we solicited proposals for LTSAs for 500 MW of our Spanish wind fleet. The fleet is comprised of turbines manufactured by Vestas, GE, Siemens and Gamesa. Based on proposals that we have received, we are in the process of replacing the current operator of the wind farms with the respective manufacturers. In December, we reached a preliminary agreement with Vestas to extend the O&M contract for our Uruguayan wind farms in exchange for an improvement in technical and economic terms. Finally, we recently launched an RFP to improve the O&M contract terms for our North American solar fleet. Thus far, there has been very strong interest from large third-party providers. Our goal is to lower our cost and improve the alignment of interests by implementing production guarantees with penalties and bonuses based upon performance, similar to our North American wind LTSAs. As a result of these initiatives, we believe that we will be able to reduce annual O&M costs by approximately $6 million, commencing in the second half of this year.
Finally, for our North American and European wind farms, we have commenced the technical analysis and permitting to implement turbine optimization technology, including GE’s Power Up offering. Upon completion, we expect to increase production across our wind fleet and generate approximately $2 million of incremental revenue.
During the year, we continued to advance the 160 MW repowering of our New York wind farms. We believe that there is strong support in the state for investment in renewable power, particularly with Governor Cuomo’s vision for a “Green New Deal” to achieve a 100% carbon-free power grid by 2040. Through engagement with key government stakeholders, including the Governor’s office, the Department of Public Service, and the New York State Energy Research and Development Authority (“NYSERDA”), we have built a strong base of support for a proposal that would benefit our repowerings. In January 2019, NYSERDA expressed support for a plan which includes a greater allocation of renewable energy credits (“RECs”) for repowerings based on their projected increase in production over the status quo, which was largely based on our proposal. On a parallel path, there is a bill in the New York State legislature that would require all electricity suppliers to procure RECs from renewable generators built before 2015. While it is unclear how these processes will unfold, it is encouraging that both the key regulatory agencies and the state legislature are looking to create a competitive market for RECs generated by repowered facilities.
In light of our progress to date, we have accelerated the pace of our repowering efforts in New York. Since we can build these wind farms at a 40% discount to greenfield projects, we plan to replace the existing Clipper turbines that have been derated and have significant operating risk going forward, and we expect to utilize production tax credit (“PTC”) safe-harbored turbines that would increase production by 25% to 30%, we believe we can earn returns above our target range of 9% to 11% on equity based on the existing incentive regime and current wholesale power market prices. If we are able to obtain additional incentives and/or we are able to obtain premium pricing for renewable power, we could achieve significant upside. Finally, we are in discussions with Hawaiian Electric to evaluate options for repowering our Kahuku wind facility on Oahu island. We believe that this project has an attractive value proposition for all stakeholders. Hawaii has a very aggressive goal of 100% carbon free power generation by 2040. This repowering would increase production from Kahuku by 30%, and similar to New York, we would reduce prospective operating cost and risk by replacing the existing Clipper turbines.
During 2018, we invested ~$28 million in organic growth initiatives, which we expect will earn a return on equity of approximately 19%. Highlights include acquiring 6 MW of solar assets under a legacy right of first offer for $4 million, investing $4 million to acquire minority interests, including tax equity interests, investing $4 million in the expansion of one of our solar farms and investing $11 million in our battery energy storage project in Hawaii. Furthermore, in December 2018, we invested $4 million to acquire a regulated 4 MW solar PV asset as part of our consolidation strategy in the fragmented Spanish renewables market.
Regulatory and Counterparty Update
In December 2018, the Spanish Government published a proposed law, which provides the option of keeping the regulated return at its current level of 7.4% for the next 12 years commencing 2020 for all renewable assets in operation before September 2013. This applies to all of our Spanish assets. In February 2019, following the failure to ratify its budget, the Spanish government announced that new elections will be held on April 28, 2019. Despite this uncertainty, we are optimistic that a favorable outcome on the regulated return will be achieved, in light of broad based support for renewable power amongst Spanish political parties as well as the recommendation of a 7.1% regulated return put forward by the CNMV, which is an independent Spanish state agency. However, with the pending election, this could delay the timeline for ratification of the law and could also result in a change to the proposed regulated rate of return.
Facing billions of dollars in claims over deadly wildfires in California, PG&E filed for bankruptcy on January 29, 2019. The bankruptcy filing has not resulted in an event of default for any of our projects with PG&E as an offtaker. At this stage, it is unclear whether PG&E will be able to reject its existing renewable power contracts. Even though our PG&E exposure is less than 1% of our portfolio, we have joined with other industry players to advocate for continuing to honor existing renewable power contracts.
Announcement of Quarterly Dividend
TerraForm Power today announced that, on March 13, 2019, its Board declared a quarterly dividend with respect to TerraForm Power’s Class A common stock of $0.2014 per share. The dividend is payable on March 29, 2019, to stockholders of record as of March 24, 2019. This dividend represents TerraForm Power’s fifth consecutive quarterly dividend payment under Brookfield’s sponsorship.
About TerraForm Power
TerraForm Power owns and operates a best-in-class renewable power portfolio of solar and wind assets located primarily in the U.S. and E.U., totaling more than 3,700 MW of installed capacity. TerraForm Power’s goal is to acquire operating solar and wind assets in North America and Western Europe. TerraForm Power is listed on the Nasdaq stock exchange (Nasdaq: TERP). It is sponsored by Brookfield Asset Management, a leading global alternative asset manager with more than $350 billion of assets under management.
For more information about TerraForm Power, please visit: www.terraformpower.com.
Quarterly Earnings Call Details
Investors, analysts and other interested parties can access TerraForm Power’s 2018 Full Year and Fourth Quarter Results as well as the Letter to Shareholders and Supplemental Information on TerraForm Power’s website at www.terraformpower.com.
The conference call can be accessed via webcast on March 15, 2019 at 9:00 a.m. Eastern Time at event.on24.com/wcc/r/1868899/535D3AA90E42BFE84348A1E0721D4251, or via teleconference at 1-844-464-3938 toll free in North America. For overseas calls please dial 1-765-507-2638, at approximately 8:50 a.m. Eastern Time. A replay of the webcast will be available for those unable to attend the live webcast.
Safe Harbor Disclosure
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 TerraForm Power expects or anticipates will occur in the future are forward-looking statements. They may include estimates of expected cash available for distribution (CAFD), dividend growth, earnings, Adjusted EBITDA, 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 TerraForm Power’s current expectations or predictions of future conditions, events, or results and speak only as of the date they are made. Although TerraForm Power 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 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.
TERRAFORM POWER, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
Three Months Ended December 31,
Twelve Months Ended December 31,
|Operating revenues, net||$||213,093||$||135,539||$||766,570||$||610,471|
|Operating costs and expenses:|
|Cost of operations||74,752||42,331||220,907||150,733|
|Cost of operations – affiliate||—||7,377||—||17,601|
|General and administrative expenses||22,239||40,230||87,722||139,874|
|General and administrative expenses – affiliate||5,310||6,498||16,239||13,391|
|Acquisition costs – affiliate||6,925||—||6,925||—|
|Impairment of renewable energy facilities||—||—||15,240||1,429|
|Depreciation, accretion and amortization expense||102,660||60,681||341,837||246,720|
|Total operating costs and expenses||205,030||157,117||696,591||569,748|
|Operating income (loss)||8,063||(21,578)||69,979||40,723|
|Other expenses (income):|
|Interest expense, net||72,349||55,254||249,211||262,003|
|Loss on extinguishment of debt, net||1,480||81,099||1,480||81,099|
|Gain on sale of renewable energy facilities||—||—||—||(37,116)|
|Gain on foreign currency exchange, net||(6,736||)||(366||)||(10,993||)||(6,061||)|
|Loss on investments and receivables – affiliate||—||1,759||—||1,759|
|Other income, net||(6,972)||(135||)||(4,102)||(5,017||)|
|Total other expenses, net||60,121||137,611||235,596||296,667|
|Loss before income tax benefit||(52,058||)||(159,189||)||(165,617||)||(255,944||)|
|Income tax benefit||(21,707)||(17,385||)||(12,290)||(19,641)|
|Less: Net (loss) income attributable to redeemable non-controlling interests||(5,893)||(8,668)||9,209||1,596|
|Less: Net loss attributable to non-controlling interests||(8,969)||(20,473||)||(174,916||)||(77,745||)|
|Net income (loss) income attributable to Class A common stockholders||$||(15,489||)||$||(112,663||)||$||12,380||$||(160,154||)|
|Weighted average number of shares:|
|Class A common stock – Basic and diluted||209,142||138,401||182,239||103,866|
|Earnings (Loss) earnings per share:|
|Class A common stock – Basic and diluted||$||(0.07||)||$||(0.82||)||$||0.07||$||(1.61||)|
|Dividends declared per share:|
|Class A common stock||$||0.19||$||1.94||$||0.76||$||1.94|
TERRAFORM POWER, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
|As of December 31,|
|Cash and cash equivalents||$||248,524||$||128,087|
|Accounts receivable, net||145,161||89,680|
|Prepaid expenses and other current assets||79,520||65,393|
|Due from affiliate||196||4,370|
Total current assets
|Renewable energy facilities, net, including consolidated variable interest entities of $3,064,675 and $3,273,848 in 2018 and 2017, respectively||6,470,026||4,801,925|
|Intangible assets, net, including consolidated variable interest entities of $751,377 and $823,629 in 2018 and 2017, respectively||1,996,404||1,077,786|
|Liabilities, Redeemable Non-controlling Interests and Stockholders’ Equity|
|Current portion of long-term debt and financing lease obligations, including consolidated variable interest entities of $64,251 and $84,691 in 2018 and 2017, respectively||$||464,332||$||403,488|
|Accounts payable and accrued expenses, including consolidated variable interest entities of $55,446 and $32,624 in 2018 and 2017, respectively||177,089||85,693|
|Other current liabilities||38,244||2,845|
|Due to affiliates||6,991||3,968|
|Total current liabilities||688,282||513,853|
|Long-term debt and financing lease obligations, less current portion, including consolidated variable interest entities of $885,760 and $833,388 in 2018 and 2017, respectively||5,297,513||3,195,312|
|Deferred revenue, less current portion||12,090||38,074|
|Deferred income taxes||178,849||24,972|
|Asset retirement obligations, including consolidated variable interest entities of $86,456 and $97,467 in 2018 and 2017, respectively||212,657||154,515|
|Redeemable non-controlling interests||33,495||34,660|
|Class A common stock, $0.01 par value per share, 1,200,000,000 shares authorized, 209,642,140 and 148,586,447 shares issued in 2018 and 2017, respectively, and 209,141,720 and 148,086,027 shares outstanding in 2018 and 2017, respectively||2,096||1,486|
|Additional paid-in capital||2,391,435||1,872,125|
|Accumulated other comprehensive income||40,238||48,018|
|Treasury stock, 500,420 shares in 2018 and 2017||(6,712||)||(6,712||)|
|Total TerraForm Power, Inc. stockholders’ equity||2,067,454||1,527,713|
|Total stockholders’ equity||2,734,922||2,387,712|
|Total liabilities, redeemable non-controlling interests and stockholders’ equity||$||9,330,354||$||6,387,021|
TERRAFORM POWER, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|Year Ended December 31,|
|Cash flows from operating activities:|
|Adjustments to reconcile net loss to net cash provided by operating activities:|
|Depreciation, accretion and amortization expense||341,837||246,720|
|Amortization of favorable and unfavorable rate revenue contracts, net||38,767||39,576|
|Loss on extinguishment of debt, net||1,480||81,099|
|Gain on sale of renewable energy facilities||—||(37,116||)|
|Impairment of goodwill||—||—|
|Impairment of renewable energy facilities||15,240||1,429|
|Loss on disposal of property, plant and equipment||6,231||5,828|
|Amortization of deferred financing costs and debt discounts||11,009||23,729|
|Unrealized (gain) loss on interest rate swaps||(13,116||)||2,425|
|Loss on note receivable||4,510||—|
|Unrealized loss on commodity contract derivatives, net||4,497||6,847|
|Recognition of deferred revenue||(1,320||)||(18,238||)|
|Stock-based compensation expense||257||16,778|
|Unrealized (gain) loss on foreign currency exchange, net||(12,899||)||(5,583||)|
|Loss on investments and receivables – affiliate||—||1,759|
|Changes in assets and liabilities, excluding the effect of acquisitions and divestitures:|
|Prepaid expenses and other current assets||(5,512||)||803|
|Accounts payable, accrued expenses and other current liabilities||(18,976||)||(42,736||)|
|Due to affiliates, net||3,023||3,968|
|Net cash provided by operating activities||253,201||67,197|
|Cash flows from investing activities:|
|Cash paid to third parties for renewable energy facility construction and other capital expenditures||(22,445||)||(8,392||)|
|Proceeds from insurance reimbursement||1,543||—|
|Proceeds from the settlement of foreign currency contracts||47,590||—|
|Proceeds from sale of renewable energy facilities, net of cash and restricted cash disposed||—||183,235|
|Proceeds from energy state rebate and reimbursable interconnection costs||8,733||25,679|
|Other investing activities||—||5,750|
|Acquisitions of renewable energy facilities from third parties, net of cash and restricted cash acquired||(8,315||)||—|
|Acquisition of Saeta business, net of cash and restricted cash acquired||(886,104||)||—|
|Net cash (used in) provided by investing activities||$||(858,998||)||$||206,272|
|Cash flows from financing activities:|
|Proceeds from issuance of Class A common stock to affiliates||$||650,000||$||—|
|Proceeds from the Sponsor Line – affiliate||86,000||—|
|Repayments of the Sponsor Line – affiliate||(86,000||)||—|
|Repayment of the Old Senior Notes due 2023||—||(950,000||)|
|Proceeds from the Senior Notes due 2023||—||494,985|
|Proceeds from the Senior Notes due 2028||—||692,979|
|Proceeds from Term Loan||—||344,650|
|Term Loan principal repayments||(3,500||)||—|
|Old Revolver repayments||—||(552,000||)|
|Proceeds from borrowings of non-recourse long-term debt||236,251||79,835|
|Principal payments and prepayments on non-recourse long-term debt||(259,017||)||(569,463||)|
|Debt premium prepayment||—||(50,712||)|
|Debt financing fees||(9,318||)||(29,972||)|
|Sale of membership interests and contributions from non-controlling interests in renewable energy facilities||7,685||6,935|
|Purchase of membership interests and distributions to non-controlling interests in renewable energy facilities||(29,163||)||(31,163||)|
|Net SunEdison investment||—||7,694|
|Due to/from affiliates, net||4,803||(8,869||)|
|Payment of dividends||(135,234||)||(285,497||)|
|Recovery of related party short swing profit||2,994||—|
|Other financing activities||—||1,085|
|Net cash provided by (used in) financing activities||782,501||(789,513||)|
|Net increase (decrease) in cash, cash equivalents and restricted cash||176,704||(516,044||)|
|Net change in cash, cash equivalents and restricted cash classified within assets held for sale||—||54,806|
|Effect of exchange rate changes on cash, cash equivalents and restricted cash||(8,682||)||3,188|
|Cash, cash equivalents and restricted cash at beginning of period||224,787||682,837|
|Cash, cash equivalents and restricted cash at end of period||$||392,809||$||224,787|
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.
The following tables present a reconciliation of operating revenues to Adjusted Revenue and net loss to Adjusted EBITDA and to CAFD and has been adjusted to exclude asset sales in the U.K. and Residential portfolios:
|Three Months Ended December 31||Twelve Months Ended December 31|
|Adjustments to reconcile operating revenues, net to Adjusted Revenue|
|Operating revenues, net||$213||$136||$767||$610|
|Unrealized (gain) loss on commodity contract derivatives, net (a)||8||8||4||7|
|Amortization of favorable and unfavorable rate revenue contracts, net (b)||10||10||39||40|
|2017 Incentive revenue recognition recast (n)||–||9||–||–|
|Regulated Solar and Wind price band adjustment (c)||2||–||12||–|
|Adjustment for asset sales||–||–||–||(15)|
|Other items (d)||2||(6)||2||(16)|
|Direct operating costs (e)||(66)||(47)||(235)||(188)|
|Settled FX gain (loss)||1||–||1||–|
|Non-operating general and administrative expenses (f)||(11)||(29)||(49)||(97)|
|Stock-based compensation expense||–||(10)||–||(17)|
|Acquisition and related costs||–||–||(15)||–|
|Depreciation, accretion and amortization expense (g)||(112)||(71)||(380)||(287)|
|Loss on extinguishment of debt||1||(81)||1||(81)|
|Gain on sale of U.K. renewable energy facilities||–||–||–||37|
|Interest expense, net||(72)||(55)||(249)||(262)|
|Income tax benefit||22||17||12||20|
|Adjustment for asset sales||–||–||–||10|
|Regulated Solar and Wind price band adjustment (c)||(2)||–||(12)||–|
|Management Fee (o)||(4)||(3)||(15)||(3)|
|Other non-cash or non-operating items (h)||(22)||(19)||(21)||7|
|(in millions)||Three Months Ended December 31||Twelve Months Ended December 31|
|Reconciliation of Adjusted EBITDA to CAFD||2018||2017||2018||2017|
|Fixed management fee (o)||(3)||(3)||(10)||(3)|
|Variable management fee (o)||(2)||(1)||(5)||(1)|
|Adjusted interest expense (i)||(72)||(51)||(256)||(234)|
|Levelized principal payments (j)||(60)||(24)||(173)||(99)|
|Cash distributions to non-controlling interests (k)||(6)||(7)||(26)||(30)|
|Sustaining capital expenditures (l)||(2)||(1)||(8)||(2)|
|Cash available for distribution (CAFD) (n)||$27||$26||$126||$88|
a) 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.
b) Represents net amortization of purchase accounting related to intangibles arising from past business combinations related to favorable and unfavorable rate revenue contracts.
c) 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.
d) Primarily represents recognized deferred revenue related to the upfront sale of investment tax credits, insurance compensation for revenue losses, and adjustments for SREC replacements.
e) 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 $6 million wind sustaining capital expenditure into direct operating costs.
f) Pursuant to the historical management services agreement (the “Management Services Agreement”) with SunEdison, Inc. (“SunEdison”), SunEdison agreed to provide or arrange for other service providers to provide management and administrative services to us in 2017. In the twelve months ended December 31, 2017, we accrued costs incurred for management and administrative services that were provided by SunEdison under the Management Services Agreement that were not reimbursed by TerraForm Power and were treated as an addback in the reconciliation of net loss to Adjusted EBITDA. In addition, non-operating items and other items incurred directly by TerraForm Power that we do not consider indicative of our core business operations are treated as an addback in the reconciliation of net loss to Adjusted EBITDA. These items include, but are not limited to, extraordinary costs and expenses related primarily to restructuring, IT system arrangements, relocation of the headquarters to New York, legal, advisory and contractor fees associated with the bankruptcy of SunEdison and certain of its affiliates (the “SunEdison bankruptcy”) and investment banking, and legal, third party diligence and advisory fees associated with the Brookfield and Saeta transactions, dispositions and financings. The Company’s normal general and administrative expenses in Corporate, paid by Terraform Power, are the amounts shown below and were not added back in the reconciliation of net loss to Adjusted EBITDA ($ in millions):
|$ in millions||Q4 2018||Q4 2017||YTD 2018||YTD 2017|
|Operating general and administrative expenses in Corporate||$9||$8||$29||$30|
g) Includes reductions (increases) within operating revenues due to net amortization of favorable and unfavorable rate revenue contracts as detailed in the reconciliation of Adjusted Revenue.
h) Represents other non-cash items as detailed in the reconciliation of Adjusted Revenue and associated footnote and certain other items that we believe are not representative of our core business or future operating performance, including but not limited to: loss (gain) on foreign exchange (“FX”), unrealized loss on commodity contracts, loss on investments and receivables with affiliate, loss on disposal of renewable energy facilities, and wind sustaining capital expenditure previously reclassified.
i) Represents project-level and other interest expense and interest income attributed to normal operations. The reconciliation from Interest expense, net as shown on the Consolidated Statements of Operations to adjusted interest expense applicable to CAFD is as follows:
|$ in millions||Q4 2018||Q4 2017||2018||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)||($234)|
j) Represents levelized project-level and other principal debt payments to the extent paid from operating cash.
k) Represents cash distributions paid to non-controlling interests in our renewable energy facilities. The reconciliation from Distributions to non-controlling interests as shown on the Consolidated Statement of Cash Flows to Cash distributions to non-controlling interests, net for the three months ended December 31, 2018 and 2017 is as follows:
|$ in millions||Q4 2018||Q4 2017||2018||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)|
l) Represents long-term average sustaining capex starting in 2018 to maintain reliability and efficiency of the assets.
m) 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), 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.
n) CAFD in 2017 was recast as follows to present the levelized principal payments, adjusted interest expense, and incentive revenue recognition 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 $88 million as reported previously.
|$ 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 recast||(1)||(9)||1||9||–|
|Cash available for distribution (CAFD), recasted||$18||$25||$19||$26||$88|
(o) Represents management fee that is not included in Direct operating costs.