This conference call transcript was computer generated and almost certianly contains errors. This transcript is provided for information purposes only.EarningsCall, LLC makes no representation about the accuracy of the aforementioned transcript, and you are cautioned not to place undue reliance on the information provided by the transcript.
spk08: Ladies and gentlemen, thank you for standing by. Welcome to this Northland Power conference call to discuss the 2020 fourth quarter results. During the presentation, all participants will be in a listen-only mode. Afterwards, we will conduct a question and answer session. At that time, if you have a question, please press star one on your telephone. If at any time during the conference you need to reach an operator, please press star zero. As a reminder, this conference is being recorded Tuesday, February 23, 2021, 10 a.m. Conducting this call for Northland Power are Mike Crawley, President and Chief Executive Officer, Pauline Alimchandani, Chief Financial Officer, and Waseem Khalil, Senior Director of Investor Relations and Strategy. Before we begin, Northland's management has asked me to remind listeners that all figures presented are in Canadian dollars and to caution that certain information presented and responses to questions may contain forward-looking statements that include assumptions and are subject to various risks. Actual results may differ maturely from management's expected or forecasted results. Please read the forward-looking statements section in yesterday's news release announcing Northland Power's results and be guided by its contents in making investment decisions or recommendations. The release is available at www.larklandpower.com. I will now turn the call over to Mike Crawley. Please go ahead.
spk09: Thank you, operator, and good morning, everyone. Thanks for joining us today. This morning, we will review our fourth quarter and full year 2020 financial and operating results. Following our remarks, we'll look forward to addressing your questions. Since the emergence of COVID last year, we have put the health and safety of our employees and stakeholders first. Through diligent planning and rigorous adherence to health protocols, we have maintained high levels of facility availability, delivering essential supply of energy to consumers and industry in Europe, Canada, and Colombia. We remain steadfast in our resolve and continue to deliver on our objectives despite the challenges we faced in the year. We finished the year on a very positive note, posting solid year-over-year growth in our operating and financial results, and we also significantly expanded our development portfolio. I'll have more to say on that shortly. First, looking at the financial results for the year, we reported adjusted EBITDA of $1.17 billion compared to $985 million in 2019, representing a 19% increase. A free cash flow of $344 million was 8% higher compared to the $318 million in 2019. On a per share basis, We achieved $1.73 in 2020, which was a small decline from the $1.77 per share in 2019. Pauline will provide a more detailed look into the financials later in the call. As we've seen, the direction of travel for power generation grids globally is now unmistakable. Carbon-intensive generation will largely be replaced with new renewable power capacity. Northland has a growing footprint globally with positions in key target markets to participate in this growth. As we outlined at our Investor Day held on February 4th of this year, Northland is very well positioned in renewables in general, but specifically in offshore wind. The opportunities that we have ahead of us are, of course, very exciting. We have a big growth pipeline already, and we intend to add more to this. By the end of the decade, We have a strategy that aims to more than double the size of the company in terms of our operating capacity and our adjusted EBITDA. We have identified development projects with the potential to add four to five gigawatts of capacity, and our development teams are advancing these projects forward. These opportunities represent $15 billion to $20 billion in overall investments on a gross basis. Once operational by the latter half of the decade, these projects are expected to more than double our adjusted EBITDA at our ownership space share. At the heart of this strategy is our focus on offshore wind. We already have an established operating portfolio in Europe, and leveraging this position and expertise, we are now expanding from this critical mass and base for further offshore wind growth in both Europe and Asia. The latest example of this is our partnership with PKN Orlin announced on January 29th for the Baltic Power Offshore Wind Project. Now, just to frame the transaction, Northland acquired a 49% position in Baltic Power, a mid-stage offshore wind development project with the potential for up to 1,200 megawatts of capacity to be built in the Polish Baltic Sea in the middle of this decade. Poland offers an attractive investment destination with an emerging offshore wind market. It is a sizable country with an investment-grade credit rating and a growing economy with increasing electricity demand. It has a clear energy policy that foresees a lot of renewable investment with a clear emphasis on offshore wind. We will be in a joint venture partnership with PKN Orland, the Polish oil and gas company, and a very strong and influential local partner in that country. They selected Northland based on our top 10 global position in offshore wind but they also wanted a true partner, one with whom they could work on an equal footing in an open and collaborative framework. It is this knowledge and expertise that local developers like PK and Orland value and the reason why they choose Northland to help them develop offshore wind in their domestic markets. Baltic Power provides Northland with a number of advantages and benefits. It gives us a scale entry into a new market alongside a very strong and influential local partner. It is a mid-stage development project, which gives us a healthy balance between reducing the risks of new market entry on the one hand and still leaving development to be done and value to be extracted on the other hand. The project will also benefit from the first round of revenue support, which will not be competitively tendered, but instead is expected to secure a 25-year revenue support agreement, a tenor difficult to find in power generation these days. We expect to reach financial close in 2023 and commercial operations in 2026, which fits nicely with our other offshore wind projects in Asia. While offshore wind will provide us the longer-term growth, we are also enhancing our near-term development pipeline. This past year, we marked our entry into the U.S. market with the acquisition of three onshore wind assets in New York State. These projects provide a total of 300 megawatts of onshore wind capacity. We really see this as an opportunity to leverage this presence, build a platform, and potentially expand it to solar and storage in that space. The projects are progressing, and in late November, we received confirmation for the conversion of the fixed REC offtake agreements into index REC offtake agreements, effectively 20-year all-in offtake agreements for the three projects. Late last week, we received the contract price offers from NYSERDA, and our teams are currently analyzing them. This is a key milestone in the development of the projects and moves the projects closer towards financial close, which we expect to execute for two of the three projects later this year, with one following in 2022. Commercial operations for the first two are expected by late 2022, and the last one follows in 2023. Turning to our construction activities, construction of La Lucha, which commenced in May 2019, with planned completion scheduled in the second half of 2020, has been delayed. Mexico, as you may know, has been severely struck by the pandemic, and this has had an impact on the timing of the schedule of this project. Activities have been affected by COVID, requiring additional precautions, including coordination of communications protocols with contractors, subcontractors, and added safety measures intended to minimize the potential transmission of the virus. Government offices have also been working at a lower level of capacity in terms of processing permits. The project is largely complete. We expect it to begin producing power in the next two to three months with official commercial operations to follow later in the year. Work also continues on securing offtake agreements for La Lucha. However, it is taking longer for them to migrate end users from the regulated tariff regime to the qualified supplier, the open market. Delay is mainly due to COVID as government agencies are either officially closed or operating with very limited resources. Until they have more certainty on timing, we are unable to finalize agreements because that implies a commitment to start taking energy from Alucha at an agreed date. At our Heilong offshore wind project in Taiwan, the team continues to make progress towards securing corporate offtake power purchase payments for the remaining 744 megawatt of allocation that was secured under the auction process. We are also happy to report that that Northland recently made its intention to begin developing additional offshore wind projects in Taiwan, which we plan on bidding into the upcoming third round of tenders, which starts in 2022. The additional projects would have a combined capacity of about 1.8 gigawatts. Now, the development of all of these onshore and offshore renewable power projects, which I've referenced, will create huge value for Northland's shareholders, I will now turn the call over to Pauline for a more detailed review of our financial results.
spk01: Thank you, Mike, and good morning, everyone. Last night, Northland Tower released operating and financial results for the fourth quarter and full year 2020. These results showcase the continued strength and resilience of our financial performance despite the challenges we face this year amidst the pandemic. We did face some challenges in the year that were outside of our control and did impact our financial results. As disclosed in our MD&A, our German wind facilities incurred higher unpaid curtailments due to periods of negative prices, as well as grid repairs by the German system operator at both the North Sea One and Dubu facilities over the course of the year. North Sea One was particularly affected by these grid outages and repairs during the fourth quarter. These outages are not expected to be recurring in nature. In total, due to lower Dutch market prices, negative prices, and grid outages, we incurred approximately $87 million of lost revenue during the year. This was significantly higher than the $24 million of lost revenue in the prior year period. In the fourth quarter, we generated adjusted EBITDA of approximately $269 million, which was a slight decrease from the $273 million we generated a year ago. The main factor is leading to the slight drop year-over-year related primarily to lower wholesale market pricing at Gemini and unpaid curtailments at North Say One mentioned earlier, which resulted in a $28 million loss in the quarter. In addition, higher costs and growth expenditures further affected results by $11 million compared to the fourth quarter of 2019, though the expenses were in line with management's expectations. These events were partially offset by the positive contributions from EBSA, which added approximately $23 million to EBITDA for the quarter. On a full-year basis, adjusted EBITDA was approximately $1.17 billion, which was the higher end of our guidance of $1.1 to $1.2 billion, a strong result despite the lost revenues we incurred during the year. Year over year, adjusted EBITDA increased 19% from the same period a year ago due to contributions from DEBU and EPSA of approximately $138 million and $90 million, respectively. These positive contributions were offset by $28 million of higher growth expenditures and $62 million of lost revenue due to the factors I previously discussed. With respect to free cash flow, Northland generated approximately $56 million in the fourth quarter. This was a decrease of approximately $11 million, or 16%, compared to the prior year. In addition to the factors affecting adjusted EBITDA, the single largest driver behind the year-over-year decrease in free cash flow was the $43 million scheduled principal repayment at DEBU, which we previously communicated in our third quarter results upon revising our guidance range. Also contributing to the decrease were higher expenses related to an increasing level of development activity, as well as higher interest costs and non-expansionary capital expenditures relating to EPSA. On a full-year basis, free cash flow in 2020 was $344 million, up from $318 million in the prior year, representing an increase of $25 million, or 8%, year-over-year. The main driver behind the year-over-year increase in free cash flow were contributions from DEBU and EBSA. These increases were partially offset by $164 million of scheduled principal repayments, $38 million increase in current tax expense as a result of the acquisition of EBSA and increased taxes at Gemini and Dibu, which were in line with our expectations. In addition, there was $54 million of higher interest expense and non-expansionary capital expenditures associated with EBSA. On a per share basis, these figures translated into $0.28 in the fourth quarter and $1.73 for full year 2020. These were 24% and 2% lower, respectively, compared to the same periods in 2019, but were in line with our expectations. Our rolling four-quarter free cash flow payout ratio, calculated on a cash dividend basis for the year ended December 31, improved to 63%, down from 68% last year. As communicated at our Investor Day held on February 4th, and commencing with our fourth quarter results, Northland reported a new supplementary non-IFRS cash flow measure, adjusted free cash flow, which is now disclosed in our MD&A. This measure is calculated by excluding growth-related expenditures from free cash flow. Management believes this measure provides a relevant presentation of Northland's ability to generate cash flow after ongoing obligations to reinvest in growth and fund dividend payments. Reinvesting in growth is a key part of Northland's long-term strategy. Accounting for these adjustments, our adjusted free cash flow for the fourth quarter was $79 million and $415 million on a full-year basis for 2020. The level of adjusted free cash flow would result in a rolling four-quarter payout ratio of 53%. Expanding a little on growth expenditures, you will note the change in presentation of growth expenditures in our annual report, which we believe will present with more transparency the nature of these expenditures. We have now distinguished between business development and project development expenses. Business development expenses are incurred to identify and secure prospective business and development opportunities. These are ultimately expected to result in identifiable development projects intended to be pursued to completion and include costs for transactions not ultimately pursued to acquisition. On the other hand, project development expenditures are attributable to certain early to mid-stage development projects under active development that we have identified to the market in current or previous disclosures and are likely to generate cash flow in future periods. In 2020, project development costs were primarily attributable to Heilong and to New York Wind prior to the commencement of their respective capitalization dates under IFRS, as well as DataOcean, Chiba, and BalticPower, compared to primarily just Heilong in 2019. More information is provided in our MD&A. Also in the quarter, as a result of achieving certain milestones, Northland commenced the capitalization of development costs attributable to our New York Wind project in accordance with IFRS. As a reminder, financial close for New York Wind is expected in 2021 with commercial operation dates in 2022 and 2023 across three projects. In addition to free cash flow generated, Northland utilizes additional sources of liquidity to fund growth expenses and capital investments. For the year ended December 31, 2020, as now included in our disclosures, we sourced additional liquidity through net proceeds from the EBSA non-recourse financing, proceeds from up-financing of North Battleford's non-recourse debt issuance, release of funds from Gemini's debt service reserve facility, as well as cash conservation from reinstating the DRIP. Altogether, these initiatives generated additional proceeds of approximately $280 million, which were primarily used to fund growth and repay corporate debt on optimal terms. With respect to our balance sheet and liquidity, Northland remains in a very strong position with ample liquidity to help fund our development initiatives. As of December 31st, Northland had access to $559 million of cash and liquidity, comprising of $491 million of liquidity available on our revolver and $68 million of corporate cash on hand to help us fund growth. Looking ahead, as we announced at our Investor Day in February, our green financing strategy will enable us to green and optimize our balance sheet in the future while benefiting from the growing demand for green issuances. Our plan is to secure either or both green corporate and project financing starting in 2021 that are expected to result in a number of benefits, including allowing us to diversify our funding sources, reduce our cost of financing, and optimize our liquidity. Turning to our 2021 financial outlook, as we noted in our press release, for our adjusted EBITDA, we expect to generate between $1.1 to $1.2 billion this year, This level is expected to remain consistent relative to our 2020 guidance levels. 2021 free cash flow per share of $1.30 to $1.50 is expected to be lower than the 2020 free cash flow per share of $1.73. This is primarily due to increased growth expenditures and higher corporate costs in pursuit of the company's continued execution of its global growth strategy, including project spend. These increased expenditures relate to the development and advancement of Baltic Power in Poland, Chiba in Japan, NATO Ocean in South Korea, and other offshore wind projects. 2021 growth expenditures are expected to total approximately $100 million, or 50 cents per share, of 2021 free cash flow. In addition to growth expenditures, the company expects to incur capital investments of approximately $100 million in 2021 to advance high-long-term New York Wind, and other projects. Capital investments are largely expected to be funded through cash on hand and through Northlands corporate credit facilities and do not impact free cash flow. Northlands adjusted free cash flow for 2021 is expected to be in the range of $1.80 to $2 per share, adjusting for growth expenditures noted above. This compares with adjusted free cash flow of $2.01 for 2019. Overall, Despite all the puts and takes, it was a solid financial year for the company. We also took meaningful steps to increase our liquidity position in 2020, at first to be in a position of defense through the early months of the COVID-19 pandemic and the related uncertainties, and then to be in a position of offense as we ended the year in a solid position to accelerate our spending on growth. All in all, it was a productive year for the company, and we look forward to delivering on our objectives in 2021. With that, I will now turn the call back over to Mike for his concluding remarks.
spk09: Thank you, Pauline. We have a big opportunity ahead of us. This decade will see global decarbonization efforts accelerated, creating a huge need for new renewable power capacity. The growth in offshore wind in particular is expected to outstrip onshore wind and solar during this period. Northland has the market position, the growth pipeline, the talent, and the balance sheet to seize the opportunity and create huge value for our shareholders and be a global leader in fighting climate change. This concludes our prepared remarks. We'd now be happy to take your questions. Operator, please open the lines.
spk08: Thank you. Ladies and gentlemen, if you would like to register a question, please press star 1 on your telephone. Again, that is star 1 on your telephone. If your question has been answered or you would like to withdraw the question, please press the pound key. If you're using speakerphone, please lift your handset before entering your request. One moment, please, for the first question. Our first question comes from the line of Sean Stewart from TD Securities. Your line is now open.
spk11: Thank you. Good morning. A couple of questions. Mike, can you give us any detail on the indexed REC terms for the New York wind projects that you had clarity on last week, I guess?
spk09: Yes, the team is working through that this week, just looking at the proposal that was delivered. It's certainly within the range of expectations, and they're just digging into it a bit further, and they've got some questions, I think, for NYSERDA to clarify some points in there. But otherwise, it's within the range of outcomes that we expected.
spk11: Okay. And with respect to broader U.S. growth ambitions beyond New York, I know you guys didn't have anything specific in Texas, but do last week's events inform your thinking on future growth, either with respect to contract structures that you're comfortable with or technology going forward?
spk09: That's a good question, Sean. I think we've spoken about this before. I mean, we've generally avoided Uruk-Hata. I'm not going to claim to... I've been prescient about what was going to happen, but we generally avoided Uricon mostly because of the contract structures, and they just didn't work for Northland as a dividend-paying stock. Relatively skinny cash flows up until the post-hedge period typically is what we've seen on those projects. I think what our strategy has been is to look for high-quality off-take projects long-term off-state contracts to the extent that they're available. So that's one of the reasons why we focus on offshore wind in new markets where you can still get, in this case of Baltic Power, a 25-year sovereign-backed off-take agreement. And as well as one of the reasons why we were interested in New York for onshore renewables is the IREC structure, which is effectively a 20-year off-take agreement, sovereign-backed off-take agreement, So that continues to be kind of our priority. That's the foundation of our cash flows. We recognize that in certain markets those will not be always available and that we'll have to look for commercial offtake agreements, such as what we're doing in Mexico. But the priority or the foundation of our revenue is always going to be those longer-term investments. a longer tenor, fixed price PPAs where we can secure them. So that's, I guess it kind of reconfirms in a manner that approach. And it also, I think what you saw a bit in terms of in Texas, not to get too far into it, but as the market for onshore renewables in particular gets more competitive, developers and IPPs are looking for ways to take costs out to be more competitive. We've always been fairly conservative in that regard, and if we sometimes lose the tender as a result, so be it, I guess, because there is consequence to cutting all the costs out and running so building a plant as skinny as you can because I think some of the consequences of that was seen in Texas where plants just weren't properly, facilities weren't properly winterized.
spk11: That's useful detail. That's all I have for now. Thank you. Okay.
spk08: Our next question comes from the line of David Quesada with Raymond James. Your line is now open. Please proceed with your question.
spk03: Thanks. Morning, everyone. My first question here is just on South Korea. I understand the government has recently come out with plans to build quite a large offshore wind facility there. I believe it's 8 gigawatts, and I know that that's a significant chunk of the company's 2030 target. Just curious what your thoughts are on the plans related to that project and how that maybe in any way affects your view of the market there.
spk09: Yeah, you can imagine when we saw that announcement, we dug into it and our team on the ground looked into it further. I think our conclusion is that it ends up being an enabler for offshore wind development across Korea. We've got significant projects that we're building, but we're certainly not going to be able to meet the entire country's objectives for offshore wind, which are substantial with our projects alone, so I think it's a signal of the country's intent to be serious about offshore wind and that their need to go offshore to get renewable power capacity over the next decade. So I think in the end it will end up being an enabler because they'll have to put in place the same permitting structures and the same mechanisms to support that project, however big it ends up being. as our projects, which are at this stage more advanced and would be coming online sooner.
spk03: Okay, great. That's good color. Thank you. Maybe just one more for me, just I guess on the unpaid curtailments that you've seen in the North Sea, and I think the comment was that you don't necessarily expect those to recur, or at least the grid maintenance is not expected to recur. I'm just wondering how you expect that I guess, to develop over 2021? Do you expect it to, I guess, diminish throughout the year? Just any thoughts around that general topic?
spk09: Well, certainly, I mean, when we look at the last three years' experience in the North Sea, it was certainly anomalous, right? It was an order of magnitude greater in terms of curtailments by the transmitter. Our understanding is that the repairs were made that prompted the for the failure that prompted the curtailments and that those problems should not reoccur and we would expect to go back to a more normal period as we had in our first couple of years in the North Sea. Okay, great. Thank you very much for that.
spk08: I'll get back in the queue. Our next question comes from the line of Rupert Murr with National Bank. Your line is now open. Please proceed with your questions.
spk13: Good morning, everyone. Good morning. Mike, you mentioned 1.8 gigawatts of new projects in development in Taiwan. I was wondering if you could give us a little more color on that, maybe talk about how attractive these sites are relative to your existing sites and if you plan to build them in partnership.
spk09: Yeah, so currently Northland is developing them on our own. I think one of the options we look at is bringing in a partner at some stage of development of those projects. I wouldn't be surprised if we do something like that. There's nothing imminent, to be clear. But they are large-scale projects, and we do have already a significant presence in Taiwan, so that may make some sense going forward. We believe the projects will be competitive. But, I mean, Rupert, just to manage expectations, we also believe that the procurements will be competitive, too, coming up. When we came into Taiwan, there was not a lot of people there. I think we were there and Orsted had just arrived. WPD had been there for a few years onshore. But now everybody knows about Taiwan and a lot of the major offshore wind. developers are present there. So it will be a competitive process. So we're looking at ways to identify potential synergies with the high long projects, which of course we have partners on too. So we'd have to work through that. And just to leverage our market knowledge to see if that can be an advantage in the procurement. But we do believe the sites specifically, which is why we've selected them, should be competitive in and of themselves.
spk13: Okay, great. Thank you. And secondly, we had a departure of the COO. Can you give us a sense of what you plan to do there to replace him and maybe any impact on your operations? Maybe discuss how your operations work across your various geographies?
spk09: For sure. So there's a strong leadership team within operations. We've got a vice president who heads up all of the onshore generation throughout Canada and also is quite involved in La Lucha. Once it will come online, we'll be quite involved in that as well. EBSA operates as a standalone business but with significant oversight from Northland. And then our offshore facilities in Europe operate through two hubs essentially, one through the German Hamburg Asset Management Office, which oversees the Deutsche Buch project and the Nord C1 project and leverages some synergies, obviously, between the two. And then we have a 60% interest in Gemini, which has its own project team, which are employees of Gemini. We're the chairman of the board that we hold that seat. and we also have regular contact with the CEO and the CFO of Gemini on the day-to-day operations of that facility, even though they're not direct employees of Northland. So that second layer, and there's also an asset management group as well and an investment management group which are involved in our facilities. So that team is strong, and certainly on an interim basis, we'll be able to maintain the high availability that we have enjoyed from our facilities over the last several years. And then we would expect to have announcements in the coming months in terms of what we would do in terms of leadership overall of operations and asset management.
spk13: Great. Well, thanks for the color. I'll leave it there.
spk08: Our next question comes from the line of Nelson Ng from RBC Capital Markets. Your line is now open. Please proceed with your question.
spk12: Great, thanks. The first question relates to just a follow-up on one of Sean's questions. In terms of the New York IREC contract offers, can you give a bit of color in terms of how many projects similar to yours were offered? IREC's Or were yours a bit of a one-off? And then the other thing is, does everyone get the same price? And is it a take-it-or-leave-it situation in terms of if, for whatever reason, the price or the terms don't make sense?
spk09: So, certainly... Everybody doesn't get the same price as the formula that's used. So the same formula is used for all sites to convert the REC to an IREC, so a renewable attribute contract to a contract that covers renewable attributes and energy, so all revenue. Same formula. And so... All of the developers, including Northland, had reasonable insight into where the range of prices would come out because they knew what the formula was. There's always obviously some difference in terms of discount rates and stuff like that that you've got to figure out and estimate, but everybody had a pretty good understanding of the range of outcomes that would come. I think most of the developers there, as we understand it, saw that the outcomes were within a range, maybe not exactly what they expected to come out at, but within a range of what they expected to end up with. Off the top of my head, I don't know how many other developers there are. Nelson, it's a little bit like old home week for anyone who's developed renewable power projects in Ontario and Quebec. There are quite a few Canadian developers down there, as you know, who are also, I think, recipients of the IREC conversions. But I don't know how many projects off the top of my head. We could follow up with that. It's a known number.
spk12: Okay, thanks. And then another question. It relates to interest rates. I know it's been creeping higher over the past six months. And for your existing projects, I know that the debt is swapped or hedged long-term. But I was just wondering about your projects under construction, like La Lucha. Have you hedged the interest rates in advance or prior to raising long-term debt? And then also kind of looking forward for projects in, I guess, advanced development, Are you looking to hedge somehow, whether it's interest rate forwards or other financial products? Are you looking to hedge interest rates in any way for those types of projects?
spk01: Yeah, so to answer your first question, yes, we have hedged the interest rate on La Lucha, particularly given that we have... we have, you know, drawings and the timing of the project finance is something that's in sight. So, you know, as we have a site to completion, COD, and we understand the dynamics around, you know, the terms, then we will head. So that is something we did a few months ago. And then with respect to hedging going forward, we hedge when, you know, closer to knowing when the cash flows from the project will be received. So, you know, for example, Heilong is a few years away, but, you know, given the significance of the project, we would be working on our strategy today with respect to our hedging program. And then typically, as you know, for every single project where it's economical, we always hedge. And so that will mean different things in different markets. For Europe, we have long-term hedges that go up for the term of the PPA. For Colombia, it's a rolling head strategy. So we're always looking at things on an individual project level and also at a portfolio level because sometimes the decision to hedge will be what other projects we have in the same jurisdiction that require funding.
spk12: Okay, thanks, Pauline. And then just one last question, more housekeeping questions. What's the timing of the North Battleford outage?
spk01: I believe it's the third quarter.
spk12: Okay, thanks. I'll leave it there. Thank you.
spk08: Our next question comes from the line of Mark Jarvey with CIBC. Please proceed with your question. Thanks.
spk05: Good morning, everyone. Maybe just with Poland, it looks like the contract for difference price or the cap at least came out. Can you maybe just give a bit more detail in terms of whether or not I think that's final or is that some, you know, could it move around between now and when it's finalized in mid-year? Also, we talked about clearance and capacity potentially in the contract for difference. Is it all or nothing or could you get some percentage of the 1.2 gigawatts with your partner or is it the expectation that if you do have everything lined up and meet the requirements that the entire 1.2 gigawatts would clear the contract awards.
spk09: The site is – you can't bifurcate the site insofar as we understand it. It's kind of binary whether you meet the requirements for this first round or not, and the The project, in our view, clearly meets the requirements. Our understanding is that you wouldn't be splitting it up, and that there's enough room in that overall envelope for all of the advanced projects that meet that delineation. So we wouldn't foresee the project being split up in any way. The final size of the project will depend on the design of the project, which is still being optimized. So you know with any design of a wind project, you're trading off how many turbines you can jam into a site and the efficiency of that turbine, and then you end up solving to the optimal energy yield and the optimal cost of energy, rather. So the exact size of the project will fall out of that design, but I wouldn't see the project getting bifurcated between this initial round and future auctions, for example.
spk05: And then, Mike, on the pricing, the CFD price that was put out publicly last week, is that, do you think, a finalized number or do you think it's subject to change? And can you just clarify whether or not You know, that's a flat fee across the whole 25 years or there's some sort of inflation escalator in that price mechanism?
spk09: I think there's more information that everybody wants to see, all the developers want to see in terms of kind of exactly that around what indexation there may be with that and to really understand what that price means. In terms of whether it's final or not, I think even in the release it explicitly said that it is subject to change. which is kind of how we understood the process working is that there's going to be, uh, a period of some negotiation, uh, back and forth. So I, I think, uh, I would take the, the information that we, that came out last week as it is, which is, uh, this is an initial, uh, proposed price, uh, but that it is indeed subject to change. Okay. Got it.
spk05: And then Pauline for you, just on La Lucha, you talked about putting the debt in place, um, uh, Just maybe the quantum, has it changed at all, pricing changed at all, and I guess underlying contracts in terms of the percent contracted and the price, whether or not that is as planned and whether it's changed at all, does that impact in terms of the total amount of debt or leverage on that asset?
spk01: Yeah, so I think that the regulatory and political environment does impact the sentiment and the quantum of lenders that, you know, can participate in that financing. So the terms have changed. It's probably too early to say, you know, quantum and cost, but those, you know, would be different than we were looking at beforehand. That being said, the overall project economics are still, you know, intact and will, you know, as we approach COD, we'll be able to provide some more information on final debt terms or getting closer to final debt terms as they're still under negotiation right now.
spk05: And just for sequencing, it would be COD and then finalized the debt after that?
spk01: Yeah, COD is the CP to getting the debt done.
spk08: Okay, perfect. That's all I have. Thank you. Our next question comes from the line of Ben Phan with BMO. Your line is now open. Please proceed with your question.
spk04: Okay, thanks. Good morning. I know you mentioned that your payout ratio is relatively low, whether it's adjusted or unadjusted. You also mentioned some huge growth plans ahead. How do you think about managing that payout the next couple of years, adding more development expense? Do you envision or are you comfortable moving that payout ratio above 100% like you saw in the last build cycle, or is there a point where you're in an uncomfortable position to message your development team and maybe slow down on development activities?
spk01: Yeah, so I think our payout ratio is at a comfortable level, and we look at things over a multi-year period, not just the current year, particularly as we set budgets and secure projects You're expecting to spend on those projects over the next few years, not just in the current year that you've secured it. So we definitely look at the overall quantum of the development budget as something that has to remain at a certain level to bring projects closer to an advanced stage where we would want to bring in partners. And so we have many levers to manage our payout ratio. We could bring in partners a lot earlier into our projects, and that's something that we would choose to do, we could choose to do. The other thing that we wanted to highlight in our results was just how much liquidity we generated this year outside of free cash flow and certain things that just don't get measured in free cash flow with respect to some of the non-recourse financings we did this year. You know, we have other levers to manage our liquidity to fund the DevEx budget. So hopefully that makes sense. I mean, we don't expect to get to 100% payout ratio or anything above that. We're working to manage the overall spend within our parameters of what's best for the company, both near-term and long-term.
spk09: And the only thing I'd add to that is, as you saw at Investor Day, we talked a bit about what we're doing in terms of near-term cash flow, right? So we referenced the New York wind projects, and we are looking at other onshore renewable developments that would deliver cash flow obviously much quicker than an offshore wind project, just given the shorter development cycle for onshore renewables. And we also outlined what we're doing with respect to M&A. You saw the first of that about a year and a half ago with the announcement of the EBSA acquisition. So an asset that not only created a development platform in Colombia, and we've got a solar project now being developed through the EBSA team in Colombia, and hopefully there will be many more But it also, importantly, gave us immediate cash flow and predictable cash flow, which helps fund the DevEx on these larger offshore wind projects going forward. So that, as we said, is part of the strategy as well with looking at the regulated transmission and distribution assets up to a cap of 15% of EBITDA. So it's not going to be a significant portion of the company, but it will be meaningful in terms of delivering near-term cash flow to the company, which helps address the point that you raised.
spk04: Sounds like you're giving a lot of thought. Can I ask a couple of clarification questions on the derivatives you put on Gemini? Is that just simply taking or forecasting the production above the subsidy cap, and what you're doing is you're mitigating prices below $40, but you're given up on upside. So I wanted to clarify that's what you're doing. And then associated with that, is there a situation, I know you're not keen on taxes, but is there a risk of a Texas situation where you have issues of production falling behind and you have to match, deliver to the hedge, buy high-priced power? Is there some residual risk there to think about in Gemini?
spk09: No. I mean, you're right in terms of the point of this was to give some protection to against APX prices falling, which over the last couple of years they have fallen from when we initiated and when we COD'd the Gemini project. So that's a protection that we're seeking. But there isn't the same exposure that you described that those projects had in Texas. It's more of a risk management tool than a than what would in taxes, which is really their revenue mechanism.
spk04: Okay. So let's say hypothetically, Gemini is offline in Q4. I know that's not going to happen. You've got this hedge in there. You don't actually have to meet that $40 obligation.
spk09: Under the hedge?
spk04: Yeah, well, let's – Yeah, I mean, wouldn't you have to buy production in a market to deliver to that hedge, or is this just really a call option or a put option that you put on?
spk09: We can take this offline, but what it does is it gives you protection on the downside, and we'd have to get into the intricacies of how the STE works. But it's a hedge that would get settled at the end of every month as you move forward. and so there's a settlement that happens at the end of every month, and to the extent that the APX price moves up, there would be some modest cost, but it more than offsets the benefit of protecting on the downside.
spk04: Okay, I got you. It sounds like more financial hedge than a physical one. I'll check this. I'll find out if I need to clarify. Okay, thank you.
spk08: Our next question comes from the line of Andrew Kosky with Credit Suisse. The line is now open. Please proceed with your question.
spk07: Thanks. Good morning. I guess the question is for Mike, and it really just revolves around any signs of supply chain tightness you're seeing in the offshore wind segment. And I ask the question in part because if we go back in, I think it was around the 2005 to 2007 era, in the onshore wind, we had sort of a rush of development that happened. and things got tight in certain component parts. What are you seeing right now in the offshore? And maybe if you could just talk a little bit about Northland's positioning.
spk09: That's a great question. I remember that period in onshore wind really well. And as a developer, it wasn't a comfortable period. I would say this. We're not seeing the same dynamic in terms of... tightening supply and then the leverage that that gives the vendors, the OEMs, over their customers. So we're not seeing that dynamic. But what is certainly true is that developers that have pipeline get a lot more attention from the three main turbine vendors that you have. You have GE, now Vestas, used to be MVOW, now it's just Vestas Offshore, and SGRE, Siemens Gamesa. So those are the three main offshore wind suppliers, and they will focus their energies on the offshore wind developers that have the largest pipeline. So that's one of the advantages that we're enjoying now that we perhaps didn't two years ago, is we've got a much more defined pipeline between Heilong, now Baltic Power, Nord Stream 2, which is expansion on North Sea One, as you know, in the German offshore, which is where we have a step and right. And we've also got other developments, of course, in Japan and Korea. So that gives us more leverage and just gives us more attention from the turbine vendors. So I think that's a dynamic more so than what you described back in 2005 to 2008, is that given the scale of these projects and the scale of the orders, the OEMs are prioritizing those that have more significant and more advanced pipelines.
spk07: I appreciate that color. And then maybe just related to that, given the inherent long cycle nature of offshore wind, that probably relieves the kind of pressure that we saw on the onshore side, given it's a faster cycle time for those assets. But does that also give you a bit better positioning from your partnership discussions that you can have in the future with your pipelines?
spk09: The long cycle of offshore wind development, the longer cycle? Mm-hmm. Yeah, I think it does. I think the OEMs do take a longer-term view, and so they'll dig more into your pipeline than I think perhaps you'd see in the dynamic you described in 2005 to 2008. In fact, I don't know if you seem to remember it well, but the... I mean, some of the turbine vendors were pushing for these framework agreements, so they didn't really want to dig into your pipeline as much back then. They wanted to kind of force you to take on obligations to procure X number of megawatts of their turbines, and then a larger player like Nextera was able to play that game, but a lot of the smaller players were squeezed out back then because they just couldn't, because they didn't have... either the capacity to sign up for that or the line of sight on projects to be able to feel comfortable committing to that. But it's a bit different given the longer development cycles. But again, I think we're in a pretty good position given what we have of both near-term, mid-stage, and earlier stage, or near-term to construction, mid-stage, and earlier development stage offshore wind projects. We've got a pretty healthy pipeline.
spk07: That's great. I appreciate the call. Thanks.
spk08: Our next question comes from the line of Chris King with Morgan Meehan. Your line is now open. Please proceed with your question.
spk06: Thank you. Mike, I know I speak for a number of investors. We're rather unsettled by the departure of Troy Patton. Could we have a little bit more explanation given the operational excellence you guys have shown for the last little while? Your stock is down significantly. As a material event, why wasn't this disclosed last week?
spk09: This was disclosed with this release. What I would say is that Northland has a strong leadership team and we've got a strong senior operations team as well. and we are always looking at ways to ensure that we have a strong executive team that can deliver on the growth and the growth plan that we have going forward. That's certainly my responsibility to ensure that, and I can certainly give you the assurance that we will take steps in the weeks and months to come to ensure that we have a strong leader in charge of operations and asset management. But I would reassure you, as I did at the beginning of the call, that the next layer down, the senior leaders in that group, which I described in detail, are highly capable individuals who will maintain a high degree of availability of those facilities going forward.
spk06: Well, the stock isn't reflecting that confidence in you, but if there are no further details, maybe we can take this offline.
spk09: Happy to talk to you.
spk08: Our next question comes from the line Justin Strong with Scottier Bank. Please proceed with your question. Your line is now open.
spk10: Hey, guys. Thanks for taking my call. This one's probably more for Pauline. So just going through your release, just looking for a little bit of color on some of the numbers in there. So there is kind of a commitment for $100 million towards Baltic Power in 2021, and then also $100 million for growth expenditures over the year, and then finally a capital investment of $100 million across a number of projects. I'm just looking for clarity on these numbers between amounts capitalized and expensed, and just if anything has kind of changed in your messaging from the investor data.
spk01: Oh, okay, sure. I'm happy to provide that clarity. So we have $100 million of growth expenditures that are anticipated to be expensed in 2021. We have $100 million of capital expenditures on projects such as Heilong and New York that are expected to be incurred on balance sheet or outside of free cash flow. For Baltic Power, we expect closing to happen sometime in the spring, so we'll have a purchase price associated with that acquisition, which will be capitalized. Thereafter, until we achieve our capitalization milestones, there are expected to be some amounts expensed. And thereafter, as we achieve capitalization milestones under IFRS, it would be capitalized. So it's a bit of a mix. But overall, the numbers that we disclosed are still intact between DEVX and CAPEX.
spk10: That's great. Thank you.
spk08: Our last question comes from the line of Najee Baton with IA Capital Markets. Please proceed to your question. Your line is now open.
spk02: Hi, good morning. Just going back to the current events in Texas, I appreciate it might be early days, but I'm just wondering if these events have informed or changed your risk management approach, be it either on existing facilities or new projects, just learning how you're thinking about operating risk or asset management vis-à-vis extreme weather events.
spk09: It's an excellent question. I think, just to pick up on something I said earlier in the call, and to be candid, as the onshore renewables in particular, but renewables in general, gets more competitive, there is always pressure to try and see how you can lower your CAPEX, your construction costs, and how you can lower your operating costs. We do put a lot of focus on figuring out how we can be more efficient in both respects, look for synergies with existing operating assets to be more competitive. I think all of that is good. I think what you do see sometimes is developers and IPPs pushing the envelope further, both in terms of CapEx, OpEx optimizations, but also in terms of revenue structures and the risks that they're willing to take in those revenue structures. So we've explicitly avoided ERCOT because of our discomfort with the revenue structures in that market. And on CAPEX and OPEX, we have lost some tenders for offtake agreements, perhaps because others took more aggressive views than we did. In that regard, and I think to some extent it kind of confirms our approach, that optimizations are good but not up to the point where you're putting the facility at undue risk. And I think, I don't know all the details of it, but I think certainly in terms of winterization and anybody who's kind of built a wind project knows that there's certain decisions to be made around whether to take the winterization package or not and there's a cost involved in that. we've generally been fairly conservative in that regard.
spk02: Okay. Thanks for that. And just, I guess, some preliminary thoughts on annual growth expenditures going forward. You've very clearly outlined $100 million for this year. And just, you know, assuming there are no new major growth projects, is that a good run rate number for the next few years or, I guess, China? I'm trying to get a better sense of the cadence of those development expenditures from a longer-term perspective.
spk09: I think it's a fair rule of thumb, right? Because as projects move towards a revenue contract, a secure revenue contract, then they start being capitalized, so then that's no longer an expense running through the income statement. So I think that's a reasonable assumption going forward. And as we referenced before with respect to the payout ratio, there is also a relationship to our ability to – to secure near-term cash flow, either through M&A or through onshore renewable development that converts into cash flow quicker. So there's a management there, but I think that's kind of a general, that's not an unreasonable kind of assumption to take.
spk02: Okay. Thank you for those details.
spk09: Okay. Well, thanks to everybody for joining us today. We're going to hold our next call following the release of our first quarter 2021 results in May. In the meantime, we want to thank you for your continued confidence and support in Northland. Take care.
spk08: Ladies and gentlemen, that concludes our conference call today. Thank you for participating. You may have a pleasant day. Bye-bye.
Disclaimer