TerraForm Power Inc (TERP) Q4 2018 Earnings Conference Call Transcript
TerraForm Power Inc (NASDAQ: TERP)Q4 2018 Earnings Conference CallMarch 15, 2019, 9:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good day, ladies and gentlemen, and welcome to TerraForm Power 2018 Fourth Quarter and Full-Year Results. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. (Operator Instructions) As a reminder, today's call is being recorded.
I would now like to turn the call over to Mr. Chad Reed, Head of Investor Relations. Sir, you may begin.
Chad Reed -- Director, Investor Relations
Thank you, operator. Good morning, everyone, and thank you for joining us for our 2018 full-year results conference call. I'm joined today John Stinebaugh, our Chief Executive Officer; and Michael Tebbutt, our Chief Financial Officer.
Before we begin, I'd like to remind you that a copy of our earnings release, supplemental information and letter to shareholders can be found on our website. Also available on our website is an updated corporate profile. I want to remind you that we may make forward-looking statements on this call. These forward-looking statements are subject to known and unknown risks, and our actual results may differ materially. For more information, you're encouraged to review the Risk Factors section in our SEC filings, which can be found on our website.
In addition, we will refer to non-GAAP financial measures. For more information on a reconciliation of these non-GAAP measures to comparable GAAP measures, please refer to our earnings release and supplemental information.
With that, I'll now turn the call over to John.
John Stinebaugh -- Chief Executive Officer
Thanks, Chad. Upon becoming our sponsor in late 2017, Brookfield articulated a strategy to transform TerraForm Power into a fully integrated renewable power company that delivers an annual total return in the low-teens to our shareholders.
Total return will be comprised of a dividend yield backed by a payout ratio of 80% to 85% of CAFD and a dividend growth rate of 5% to 8% per year. Three simple pillars underpin our strategy. First, investing on a value basis in operating wind and solar assets in North America and Western Europe. Second, enhancing the value of our existing assets by optimizing costs, increasing revenue and investing in organic growth; and third, strengthening our balance sheet. During 2018, we made significant progress in building the foundation to deliver on this long-term strategy.
We invested $1.2 billion to acquire Saeta, increasing our asset base by 40%. With Saeta, we acquired a 1,000 megawatt portfolio of high-quality wind and solar assets primarily in Spain at a very attractive value, and we established a scale operating platform from which we will continue to build our European operations.
When we acquired Saeta, there was considerable uncertainty regarding the reset of the regulatory return in Spain in 2020. We priced the deal such that in a conservative downside case, we would earn a return on equity within our target range of 9% to 11%. Despite uncertainty regarding the elections in Spain that will take place in April of this year, we are optimistic that the outcome will be significantly better than our underwriting assumption, as there is broad-based support for renewable power among the political parties in Spain.
In addition, we executed an 11-year framework agreement with GE to enter into long-term service agreements for turbine operations and maintenance, as well as other balance of plant services for our 1.6 gigawatt North American wind fleet.
Once the LTSAs are fully implemented, which we anticipate will occur in the first half of this year, we expect to realize $20 million of annual cost savings on full-wrap basis. The LTSAs also contain performance guarantees, backed by liquidated damages, that will increase to a level that is in line with our estimated long-term average generation.
Furthermore, we successfully executed our solar performance improvement plan to enhance revenue. Following irradiation scans of nearly all of our North American solar facilities, we've identified and remediated all high priority issues that caused production deficiencies within our solar fleet.
On an annual basis, production from our fleet is expected to increase by 61 gigawatt hours per year, which should equate to $11 billion of revenue. As a result, we anticipate that revenue in 2019 will increase by approximately $8 million compared to 2018 on a resource adjusted basis.
Finally, we strengthened our balance sheet. Our financing plan for the Saeta acquisition was comprised of the issuance of equity and project financings of existing unlevered assets rather than any new corporate debt commitments.
Once we close the final project financings in the first half of 2019 and our results reflect a full year of contribution from Saeta, our balance sheet should deleverage significantly. As a result of this expected deleveraging, Moody's upgraded TERP's corporate credit rating to Ba3 following the close of the acquisition.
Now, I'll turn the call over to Michael to discuss our financial results and provide a liquidity update.
Michael Tebbutt -- Chief Financial Officer
Thanks, John, and good morning, everyone.
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 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 Nino 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.
In terms of a liquidity update, 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 approximately $100 million and $90 million, respectively, by the first half of 2019.
We also recently launched the refinancing of our 95 megawatt wind facility in Uruguay. 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.
Now, I'll turn it back over to John.
John Stinebaugh -- Chief Executive Officer
Thanks, Michael. Now, I'll provide an update on operations. To date, we've 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, are in -- 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 megawatts of our Spanish wind fleet. The fleet is comprised of turbines manufactured by Vestas, GE, Siemens and Gamesa. Based on the 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, beginning in the second half of this year.
Finally, for our North American and European wind farms, we've 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 at least $2 million of incremental revenue.
In terms of growth initiatives, we continued to advance the 160 megawatt repowering of our New York wind farms. We believe 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 NYSERDA, we've 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 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's 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 existing clipper turbines that have been derated and have significant operating risk going forward.
And we expect to utilize production tax credit 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 is a project that has an attractive value proposition for all stakeholders. Hawaii has a very aggressive goal of 100% carbon free power generation by 2040. The repowering would increase production from Kahuku by 30%, and similar to New York, we would reduce the 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 megawatts 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, we invested $4 million to acquire a regulated 4 megawatt solar PV asset as part of our consolidation strategy in the fragmented Spanish renewables market.
Moving on to regulatory updates. In December, the Spanish government published a proposed law, which provides the option of keeping a 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.
However, in February 2019, following the failure to ratify its budget, the Spanish government announced that new elections will be held on April 28. Despite this uncertainty, we are optimistic that a favorable outcome on the regulated rate of return will be achieved, in light of broad-based support for renewable power among 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 29th. 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 purchase contracts.
As we look forward, we are optimistic about TerraForm Power's prospects in light of the foundation for growth that we built in 2018. First of all, going forward, TerraForm Power will benefit from a full year of contribution from the Saeta acquisition, which is very accretive. Secondly, in 2018, wind production was significantly below our LTA. Although it is inherently variable, we expect that wind resource should improve compared with 2018 levels. If wind resource reaches P50 production levels and we experience normalized curtailments, we believe our adjusted EBITDA and CAFD will increase by $28 million.
Finally, we expect to realize significant upside from the margin enhancement initiatives that we executed in the past year. Once we fully transition O&M of our North American wind fleet to GE, we will realize cost savings that we expect will approximate $20 million per year.
In addition, we expect to benefit from production guarantees backed by liquidated damages that will increase to levels consistent with our LTAs, which we expect will yield $15 million in incremental revenue on an annual basis and significantly mitigate the risk of operational challenges like those experienced last year.
We believe we will also realize incremental revenue of approximately $8 million over 2018 from the solar performance improvement plan. In total, these completed margin enhancement initiatives are expected to generate up to $43 million of additional run rate adjusted EBITDA.
In addition to these building blocks, we expect to execute additional margin enhancement activities in 2019, primarily within our European portfolio, and to progress our repowerings in New York and Hawaii. We will actively pursue opportunities to deploy capital on a value basis.
As part of our Spanish renewable consolidation strategy, we are considering a number of acquisitions. We believe that the greater uncertainty regarding the regulated rate of return should lead to opportunities to acquire assets at more attractive prices. As we grow our business, we will strive to further strengthen our balance sheet, with a long-term objective of achieving an investment grade rating. As a result of this progress, we are pleased to announce that, on March 13, 2019, our Board declared a quarterly dividend with respect to our Class A common stock of $0.2014 per share.
This dividend represents a 6% increase over TerraForm Power's Q4 2018 dividend, in line with our dividend growth target of 5% to 8% per year. We anticipate that this dividend amount will be within our targeted payout ratio range of 80% to 85% of CAFD.
As always, we look forward to updating you on our progress in executing our business plan over the coming quarters.
This concludes our formal remarks. Thank you for joining us this morning. We'd be pleased to take questions at this time.
Questions and Answers:
Operator
(Operator Instructions) Our first question comes from the line of Nelson Ng from RBC Capital Markets. You may begin.
Nelson Ng -- RBC Capital Markets -- Analyst
Great. Thanks. Good morning, everyone. Just in terms of my first question, the new dividend, you mentioned that it's within 80% to 85% of your payout. Is that for calendar 2019, or are you referring to your run rate CAFD with all the improvements?
John Stinebaugh -- Chief Executive Officer
We think it should be within the 80% to 85% of CAFD for 2019 based upon normal resource conditions. We expect that we should get pretty close to three quarters of the positive impact from GE cost savings in 2019. And we should get the full benefit of the performance improvement plan and in addition to that, once the GE contract is in effect with the performance guarantees, that should work approximately three quarters of the year on average, achieve 98% availability that is based within our LTAs. So with those factors, we think we should be within the 80% to 85% of CAFD for 2019.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay. Got it. And then just in terms of optimizing the various assets, there was one, I think, one asset class you guys didn't really mentioned, but it was the -- it's the solar facilities in Spain, you touched on the wind facilities, but have you -- is there much opportunity to improve the operations from the Spanish solar facilities?
John Stinebaugh -- Chief Executive Officer
There is opportunity to do so. And that's something that we are actively working on. We are under a long-term contract with ACS, which is the party that we ended up buying 24% of Saeta from, and we are looking to try to restructure that contract, so that there is benefit to both us, as well as ACS. So, there is a win-win situation and as we make more progress on that, we'll provide an update in coming quarters.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay. And then just one last question before I get back in the queue. You mentioned the repowering initiatives in the state of New York and also Hawaii, and you also mentioned that you have PTC qualified turbines. Could you just talk about what needs to happen in terms of the next steps before you move forward with repowering? And then, can you also talk about the timeline in terms of whether you need to repower by like 2020 or 2021 in terms of which vintage of turbines or PTC qualified turbines you have?
John Stinebaugh -- Chief Executive Officer
Sure. So in terms of the gating item that is really going to drive the timeline, it's going to be the permitting process because it's a repowering. And one of the things we've been working on is to see if we can be exempt from the Article VIII permitting requirements that govern greenfield and to be under local permitting requirements, which we think will be more timely in terms of being able to obtain approvals. And we're cautiously optimistic that we'll be able to work under the local regimes.
So, that's the biggest gating item. In terms of the timeline for repowering, in order to -- we've got access to GE turbines as a result of the O&M contract that we executed. So, we currently have an ability to procure 80% PTC safe-harbored turbines. So, that's what our repowering plans are based upon. And we need to bring the projects online by 2021 under the provisions of the Safe Harbor.
Nelson Ng -- RBC Capital Markets -- Analyst
Okay. Thanks, John. I'll get back in the queue.
Operator
Thank you. And our next question comes from the line of Moses Sutton from Barclays. You may begin.
Moses Sutton -- Barclays -- Analyst
Thanks for taking my question. A few more questions on repowerings. You mentioned 40% lower cost in greenfield, any ballpark range you'd be able to provide on like what total spend would be, let's say, just given your portion?
John Stinebaugh -- Chief Executive Officer
In terms of the total spend, we anticipate that it's going to be roughly about $70 million of equity investments. That's assuming, that the tax equity predominantly is going to be roughly 65% of the capital structure.
Moses Sutton -- Barclays -- Analyst
Got it. That's very helpful. And you talked about the 25% to 30% uplift in production for New York. So is it -- does it sound correct that at historical, capacity factor has been around like 22%, so it bumped you up to like 28 or 20s (ph).
John Stinebaugh -- Chief Executive Officer
That sounds about right. But the 25% to 30% is our estimate of based on the turbines with the larger rotor diameters that we're looking to deploy, that with that increased production, the repower is not going to increase capacity at all. And I think the capacity factor is in line with what you're talking about, but that's a little hard for me to do that math within my head right now.
Moses Sutton -- Barclays -- Analyst
Got it. Got it. And then last one. In the Northeast, Sheffield in Vermont and also Stetson, those also seems to have capacity factor, maybe a little better than New York. But would there be any opportunity there? I know it's a bit ahead, thinking a bit ahead of New York. But is there any opportunity -- maybe you don't have some safe harboring there, but maybe is that -- would that be economic further down the road, too?
John Stinebaugh -- Chief Executive Officer
Yeah, we do think that, that is a repowering candidate. The Northeast projects, for sure, the remainder of the wind projects, those are the ones that we've included in the corporate profile, the repowering megawatts that we've identified where the repowering capital cost that we've identified. We have focused on the two New York projects and the one Hawaii project that are currently operating Clipper turbines as our top priority because the economics of repowering Clipper turbines are particularly compelling.
First of all, we've done preliminary engineering and we are confident that we can utilize existing towers to deploy the new turbines with a greater rotor diameter, so that will help us reduce the capital cost significantly compared to greenfield. And the other thing that's compelling about repowering the Clippers is they've got higher O&M and maintenance CapEx cost, and they are going to further derate over time. So if you think about the incremental cash flow that we will get by repowering relative to the status quo case, it's particularly compelling. And as a result of that, that's why we are focusing on those three projects.
Moses Sutton -- Barclays -- Analyst
That's very, very helpful. And rather than repowering, any color you can give on how downtime -- how much downtime you would have? And just if we're thinking of modeling this in some out year, trying to figure out what the interim effect would be as you do repowerings?
John Stinebaugh -- Chief Executive Officer
Yeah. In terms of how we will do the repowerings, the thing to bear in mind is, it's going to be done really on a tower-by-tower basis. So, it's not going to be a situation where we shut down the wind farm, and then end up deploying the new turbines. So, there'd be significant downtime for a considerable period of time -- of the entire wind farm, rather what it's going to be is, we basically will shut down individual turbines and replace the existing Clipper turbines with the larger rotor diameter turbines on a tower-by-tower basis. So, that will significantly mitigate the downtime.
Moses Sutton -- Barclays -- Analyst
Great. That's very helpful. And last question for me and I'll jump in the queue. You signed the LTSAs on 10 out of 16 of the wind projects with GE, where are the other six? Is that Hawaii, New York? What are the -- and just if you could provide where the six are.
John Stinebaugh -- Chief Executive Officer
We've turned over operations of a couple of the Clipper sides, then it is largely going to be the ones in the Northeast, I believe, the ones in Hawaii. And beyond that, I'll have to get back to you with further detail on. But it's the ones that were operated by GE. It's the ones that were operated by GE -- I'm sorry, that were operated by GE as well as the Clippers, which we were self performing.
Moses Sutton -- Barclays -- Analyst
Great. Thank you. Appreciate it.
Operator
And our next question comes from the line of Colin Rusch from Oppenheimer. You may begin.
Colin Rusch -- Oppenheimer & Company -- Analyst
Thanks so much, guys. Could you talk about what you're seeing on the distributed power side? And is there a strategic move for you guys to make either in terms of adding a subtraction to portfolio there.
John Stinebaugh -- Chief Executive Officer
Yeah. Distributor side is something we're very interested in. So, we are looking to add to the portfolio. We have brought on a team within Brookfield. It would provide benefits to TerraForm as part of the master services agreement of -- on the DG development side. And the opportunity that we're going to pursue is, first of all, to try to expand deployed batteries to the existing 400 megawatts that we've got. We also think that there is a potential opportunity working with Brookfield, where we've got sites within the real estate business as well as our infrastructure business, better potential candidates for repowering. We're deploying distributed generation and/or batteries. So, we'll look at that as well.
But we are -- also, in addition to that, looking to acquire additional DG projects from developers. And so we are building relationships and in fact, the team that we brought on board has significant relationships with a lot of the small private DG developers out there.
So, we're going to look to procure projects from them as they look to monetize projects and reinvest in their pipeline. So, that's something that, overtime, we'll provide more disclosure on as we ramp up that effort. But that's sort of nutshell in terms of what we're looking to do.
Colin Rusch -- Oppenheimer & Company -- Analyst
Okay. And then just in terms of access to battery supply, can you talk a little bit about what the supply chain looks like for you guys right now and lead times for actually integrating storage into various systems?
John Stinebaugh -- Chief Executive Officer
I can't comment a whole lot on that, Colin. We did end up procuring batteries for the battery energy storage system in Hawaii and that would have been last year. We didn't really have any delays in terms of being able to procure batteries because of any source supply chain issues. Beyond that, I can't really give you any additional color at this time.
Colin Rusch -- Oppenheimer & Company -- Analyst
Okay. Awesome. Thanks so much, guys.
Operator
Thank you. And our next question comes from the line of Rachel Lei from Deutsche Bank. You may begin.
Rachel Lei -- Deutsche Bank -- Analyst
Hi, guys. Thank you for taking our questions. So, the first one is about, John, do you see any additional organic growth opportunities in the near term? Are they mainly from the European platform or are there other avenues like smaller ROFOs and tax equity buyouts like last year? Thank you.
John Stinebaugh -- Chief Executive Officer
Yeah. It's really across three categories. First of all, the biggest is going to be the repowerings. If we look at the New York sites as well as the Hawaiian project, we think that we have an opportunity to invest around $70 million of equity. If we put leverage on the portfolio, it might be a little bit less than that, maybe in the mid to high $50 million range. We do have some legacy ROFO opportunities that we're working on, that we are hoping to convert into acquisitions. And in addition to that, we are going to continue to work on the NCI buyouts. So, I think, if you look, in total, at the opportunity to, what we would classify organic growth opportunity, it's over $450 million.
The largest of that would be repowerings, and then the legacy ROFO opportunities we've got, as well as a modest amount of NCI buyouts. But those are opportunities that we would consider part of the organic pool investments. And then obviously, we're looking at doing add-on acquisitions as part of the Spanish consolidation program, as well as what we're looking to do within DG and other acquisition opportunities that we regularly review.
Rachel Lei -- Deutsche Bank -- Analyst
Okay.
Operator
All right. (Operator Instructions) Our next question comes from the line of Praful Mehta from Citigroup. You may begin.
Praful Mehta -- Citigroup -- Analyst
Thanks so much. Hi, guys.
John Stinebaugh -- Chief Executive Officer
Hi.
Praful Mehta -- Citigroup -- Analyst
Hi. So firstly, maybe on the Spanish side and the acquisition. In terms of the returns, it sounds like you're kind of talking about a 7.1% on the lower end in terms of the threshold return that you can still achieve good returns on your acquisition.
Can you probably give us -- is that a fair way to think of it in terms of how you're looking at the lower end, potentially of the outcome from a return perspective in Spain? And what is the sensitivity, as in for every 50 basis points, let's say of an ROE degradation, what is the CAFD impact that you see?
John Stinebaugh -- Chief Executive Officer
Sure. It is unclear what the regulated rate of return is going to be, but we think a couple of the markers. And the regulated return is a return on assets. The 7.4% is the proposed law. 7.1% is the rate that was recommended by the CNMV. And I think that's a relevant marker from the standpoint, the CNMV is an unbiased regulatory agency.
And they published a whitepaper that had a buildup of what they thought was a fair cost of capital for renewable power facilities using a weighted average cost of capital type methodology. So, we think that, that is a pretty good marker in terms of the -- a fair rate of return, which is the standard for the law within Spain. To give you a sense in terms of sensitivity, every 100 basis points is $12 million of revenue for TerraForm.
Praful Mehta -- Citigroup -- Analyst
Got you. All right. Thank you. And that translates straight to CAFD effectively?
John Stinebaugh -- Chief Executive Officer
It won't translate straight to CAFD because there is the generation tax of 7%, but 93% of it would go down to CAFD.
Praful Mehta -- Citigroup -- Analyst
Got you. That's helpful. And then -- and you're trying to do these project financings when you have uncertainty on the return. So, I just want to understand, is there a timing element to that as in or you plan to do the financings after you have some clarity? Or are you going to effectively price in some uncertainty into the terms, you get in the project financing?
John Stinebaugh -- Chief Executive Officer
That's a great point. We think we can get optimal execution, once there is certainty regarding the regulated rate of return. So, what we will likely do is wait until there is certainty and then go out and execute the projects financings after that for the Spanish portfolio.
Praful Mehta -- Citigroup -- Analyst
Got you. So if that decision on the Spanish execute -- return gets delayed, then it could delay the benefits that you see on the project financing side?
John Stinebaugh -- Chief Executive Officer
Yeah, that's possible. We had execute now and look to structure so that we can upsize based upon a more favorable rate of return than what is forecasted in sort of a underwriting case from lenders' perspective. So, that's sort of the default.
The other point that I would mention is that if a new rate of return isn't passed (ph), the rate of return will stay at the 7.4%. So to the extent that there is not a royal decree, they can pass Parliament, then the rate of return will stay at the 7.4%.
Praful Mehta -- Citigroup -- Analyst
Got you. I understood. And then just finally, it was very helpful to get the perspective on all the different kind of avenues of growth that you are looking at, but I'm assuming the return thresholds probably vary by the asset class that you're considering. So for example, if you're looking at DG, which you talked about just briefly, is the return threshold for that different in your mind versus when you look at the Spanish assets or you looking at assets in the US at a utility scale, just to get a sense for how you're thinking about returns?
John Stinebaugh -- Chief Executive Officer
We look at everything on a risk-adjusted basis. So, we would factor in the revenue framework and the risk of one revenue framework versus another. In addition to that, we would factor in sovereign risk and political risk as part of that. So, we are targeting 9% to 11% overall with any individual investment we make.
We're going to look to price based on what we think is an appropriate risk-adjusted return. And I'd say, if I look at the Spanish regime, on the one hand, I'd say there's greater political risk but we think it's been largely mitigated because the system is in surplus now, and Spain is actively trying to encourage deployment of renewables to meet their targets.
On the regulatory -- on the revenue framework side, I'd say the revenue framework is more stable for that than for DG. So, you've got a couple of offsetting factors, but we would look at it, sort of on a relative basis one versus another and try to come up with what we think is an appropriate risk-adjusted return. And we tend to benchmark things against utility scale renewables in the United States.
Praful Mehta -- Citigroup -- Analyst
Right. So, maybe just to clarify on that, against utility scale renewables in the US, is DG a premium to that in terms of your return requirement?
John Stinebaugh -- Chief Executive Officer
It would be a premium because you have got revenues that are going to be indexed to tariffs. So, there's going to be more risk in terms of the price side of things. Depending on who your counterparties are, there maybe more credit risks associated with it. So, we would price that at a premium to utility scale with a long-term contract with an IG counter-party.
Praful Mehta -- Citigroup -- Analyst
Got you. Thanks so much. I'll get back in queue, guys. Thank you.
Operator
Thank you. And ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone have a great day.
Duration: 41 minutes
Call participants:
Chad Reed -- Director, Investor Relations
John Stinebaugh -- Chief Executive Officer
Michael Tebbutt -- Chief Financial Officer
Nelson Ng -- RBC Capital Markets -- Analyst
Moses Sutton -- Barclays -- Analyst
Colin Rusch -- Oppenheimer & Company -- Analyst
Rachel Lei -- Deutsche Bank -- Analyst
Praful Mehta -- Citigroup -- Analyst
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