Good morning and welcome to the Eversource Energy fourth quarter and year-end 2020 results conference. My name is Brandon and I’ll be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session, during which you may dial star, one if you have a question. Please note this conference is being recorded. I will now turn it over to Jeffrey Kotkin. You may begin, sir.

Thank you Brandon. Good morning and thank you for joining us. I’m Jeff Kotkin, Eversource Energy’s Vice President for Investor Relations. During this call, we’ll be referencing slides that we posted last night on our website to be forward-looking as defined within the meaning of the Safe Harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on management’s current expectations and are subject to risks and uncertainty which may cause the actual results to differ materially from forecasts and projections. These factors are set forth in the news release issued yesterday. Additional information about the various factors that may cause actual results to differ can be found in our annual report on Form 10-K for the year ended December 31, 2019 and our Form 10-Q for the three months ended September 30, 2020. Additionally, our explanation of how and why we use certain non-GAAP measures and how those measures reconcile to GAAP results is contained within our news release and the slides we posted last night, and in our most recent 10-K. Speaking today will be Jim Judge, our Chairman, President and CEO, and Phil Lembo, our Executive Vice President and CFO. Also joining us today are Werner Schweiger, our EVP and Chief Operating Officer; Joe Nolan, our EVP for Strategy and Customer and Corporate Relations; John Moreira, our Treasurer and Senior VP for Finance and Regulatory; and Jay Booth, our VP and Controller. Now I will turn to Slide 2 and turn over the call to Jim.

Thank you Jeff, and thank you everyone for joining us today for our review of 2020 results and our updated long-term outlook. First, let me say I hope that all is well with you and your families in what’s been a challenging year for everyone. I’ll start my comments by thanking our more than 9,000 Eversource Energy colleagues for their exceedingly hard work in extraordinarily difficult circumstances in 2020. Not only did they have to deal with the first pandemic to strike the country in more than a century but they also had to address the highest level of storm activity ever for our company, as well as the hottest summer on record in large parts of our service territory. Through it all, they worked safely and professionally, keeping their fellow workers and our customers first in mind. As you can see on Slide 4, despite 107 major and minor storms that struck our service territory in 2020, we successfully executed our $3 billion capital program. These expenditures are critical to enhance the resilience of our energy and water delivery systems as well as to connect new customers and to support safe, clean energy initiatives. 2020 was also a year during which we advanced a number of our strategic initiatives. At the end of February, we executed an agreement with NiSource to buy its Columbia Gas and Massachusetts assets, and we closed on that acquisition in early October, just seven months later. The acquisition added about 5% to our regulated business and has been extremely well received by state policymakers and by the more than 330,000 customers that Eversource Gas Company of Massachusetts now serves. We continue to expect the transaction to be accretive in 2021 and progressively more accretive in the years ahead as we steadily increase our level…

Thank you Jim. Good morning everyone. I’ll be covering several topics: our 2020 financial results, I’ll be discussing our 2021 guidance, our long-term growth rate, our capital investment plan, and recent regulatory developments. Starting with a quick review of our full year results, our GAAP earnings were $3.55 per share, excluding $0.09 per share of transaction costs associated with our October purchase of assets of Columbia Gas - I should say, that’s including the $0.09 of transaction costs. Excluding those costs, we earned $3.64 per share in 2020, consistent with consensus and with guidance we gave you a year ago. Slide 16 summarizes both the year and fourth quarter. Electric distribution earnings totaled $1.60 per share in 2020, up a penny per share from 2019. High distribution revenues were largely offset by higher O&M, depreciation, property tax expense, interest costs, and dilution. The higher O&M was primarily attributable to record storm expense as a result of more than 100 major and minor storm events that affected our three electric service territories last year. Non-deferred storm expense totaled nearly $77 million and was the highest level we’ve experienced in recent years in each of the three states we serve. These non-deferrable storm costs totaled $0.17 per share in 2020 compared with an average of about $0.10 per share if you look at the years 2016 through 2019 averaged. It particularly impacted the fourth quarter of 2020 when it was responsible for an incremental $0.05 per share in O&M compared with the fourth quarter of 2019. Electric transmission earnings totaled $1.48 per share in 2020, up from $1.43 per share in 2019 excluding the Northern Pass charge. The benefit of increased investment in our transmission system was partially offset by dilution there. I should note that 2020 was a very successful year…

Thank you Phil. I’m going to return the call to Brandon just to remind you how to ask questions. Brandon?

[Operator instructions]

Okay, thank you Brandon. Our first question this morning is from Shahriar Pourreza from Guggenheim. Good morning, Shahriar.

Good morning Jeff, good morning guys. Just a couple questions to start off. Just one clarifying question on the growth rate on Slide 8, when the larger offshore wind projects start to kick in. Obviously you state higher than 5% to 7% growth. Are we inferring that we could see a step change in the growth rate to, maybe let’s say 6% to 8%, or simply a higher rebased that year and you would retain your 5% to 7%, and do you have any sense on when you might be adding these projects to your plan? I think you’re obviously waiting for the review schedules from BOEM to solidify the CODs.

Yes Shahriar, the review schedule will obviously give us some certainty and definition in terms of the spending profile and the earnings profile, but yes, the expectation is that we will have higher growth as those projects kick in beyond 2025. We’re not resetting or providing guidance as to what that looks like right now, but it clearly will be an incremental contributor to our earnings growth in the late ‘20s.

Got it, so basically a step change in the growth rate? Okay, got it. Then just taking a look at your planned investments at EGMA, you point to $270 million in capex annually there, which is, I think, more than double the amount of capital that NiSource was investing in the system. What’s driving the increased capex - is it just more safety and reliability, and just remind us if you need any sort of regulatory approvals for this spend.

The regulatory approval to the extent that capital cap is in place is the norm, but the spending level is more than historically has been spent there, but it’s our assessment that to bring the safety and performance of that infrastructure to the standards that the other Eversource gas companies are able to achieve will require that type of investment in the systems.

Got it.

I could add just a couple--just a little color there, too, is that as you know, that was an asset purchase, not a purchase of the company, so some of the things we’re--we do have some incremental, maybe IT technology types of spend to move over to Eversource systems in the past, and we certainly spend and continue to spend on our gas safety enhancement program. That’s the largest category of spending in that business.

Got it, thank you for that, Phil. Just lastly for me, obviously you highlight there’s a couple more RFPs coming this year, rely on Massachusetts and New York. Just given the bids we’ve seen from obviously some of the oil majors, it may be difficult to be successful, so--but you still do have a lot of excess lease capacity, so you can maybe just elaborate a little bit more on your strategy with the lease areas? Do you see on your leases until the other leases are filled, which could take years, or would you look to potentially monetize some of the space there? Maybe Jim, if you could just elaborate a little bit more on the strategy around those leases.

Yes, the strategy has been consistently one of financial discipline. As I’ve told my board and I’ve actually presented to the Ørsted board in the past, you should expect us to lose as many RFPs as we win because we’re intent on having these awards be profitable. We’re excited about the increasing demand, and it seems like every couple of months the numbers go up in terms of the states’ appetite for this. When we look at our situation, there’s plenty of dry powder for those bids. I could be wrong, but I think our leases are under-subscribed compared to the others that are starting to fill up with the existing portfolio of contracts. We will continue to be disciplined and we’re optimistic that the appetite is there for significant build-out of offshore wind, so I think we’re in a very good position.

Terrific, thank you guys. I’ll jump back in the queue. Congrats.

Great, thank you Shahr. Next question this morning is from Jeremy Tonet from JP Morgan. Good morning, Jeremy.

Hi, good morning. Wanted to start off with offshore wind here, and wanted to see if you might be able to help us. How much offshore wind can you fit on the leases using the new 13-megawatt turbines versus the 8-megawatt turbines originally discussed? Thanks.

Yes, I’ll take a shot at that and others could add. Fundamentally, we’ve been talking about the lease capacity as being 4,000 megawatts historically. When you increase the capacity of the turbines from what was an 8-megawatt turbine to an 11, and as you mentioned potentially 13 going forward, obviously that increases your capacity. At the same time, we have agreed to spacing of the turbines as part of the compromises to get the approval process at BOEM - we’ll be spacing them a mile between each turbine, so that actually reduces your potential capacity. Net-net, we are saying it’s at least 4,000 megawatts and we expect it to--we expect [indiscernible]. More than 4,000 megawatts is the guidance that we’re giving.

Got it, understood - at least 4,000. That’s helpful, thanks. Just wanted to turn it over to COP for a quick minute here. The COP rate case reopening appears really focused on low income rate structures from what we can see, kind of a very low risk event in our minds. Does it look like this to you, or are we missing something here? Just any color you could provide would be great.

Yes, the guidance that we’ve seen is that [indiscernible] will be looking at new rate designs, including possible low income or economic development rates, and may require a possible interim rate reduction. I think it’s important to recognize that we’re not earning our allowed return in that franchise, and we’re mandated and required to come in with a full rate review actually within the next 12 months, I think as Phil mentioned, the first quarter of 2022 a full review is needed. Our understanding or expectation is that any rate design changes that come out there would not necessarily be punitive to the company, especially as we continue to under-earn.

That’s very helpful. That’s it for me. Thanks.

Thank you very much. Our next question is from Steve Fleishman from Wolfe. Morning, Steve.

Hey, good morning, and I apologize in advance if I missed some comments related to my questions. I think one of the first questions asked about the long-term growth rate with the offshore wind, and I think you said, Jim, higher into the late ‘20s. Not to be too picky, but is that suggesting that you’re not really expecting the projects to fully come on until after mid-decade? Should these projects essentially be on for 2025, I guess is my question?

Yes, again we’re very hesitant, Steve, to commit to changing dates, especially since we think that we’ll shortly have guidance from the administration in terms of expected timelines. But what we’ve said and continue to say is that South Fork, we expect to be in by the end of 2023, but it’s clear that Revolution wind will not be in by the end of ’23 and Sunrise wind is not expected to be in by the end of ’24, so there’s some slippage there. The full impact of the offshore wind projects, especially the big ones, is clearly a mid-‘20s event, and ITC kicks in there as well, so we’re not talking about the [indiscernible] here, it’s just a map of a project that comes in during the year. You don’t get the full benefit of it until a full calendar year the next year, so I don’t want you to read more into my comments than that, but it’s a step up.

Yes, okay. No worries on that. I guess it doesn’t matter as much anyway, given the ITC extension and Safe Harbors and stuff. Just maybe on that, is there--I know there’s a lot of moving parts when you look at the economics of the projects you’ve done, but would you characterize the ITC order as improving the economics overall from what you had expected before?

Yes, certainly it significantly improves based upon what we were assuming for ITC at the time of our bids. As you mentioned, there’s a lot of puts and takes - costs go up and down, and so we’re encouraged that the ITC amount is the level that it’s at now, and more importantly the 10-year window, I think de-risks quite a bit the fear that some might have that our ITC level was vulnerable. We see it certainly as a major positive.

Great, and then lastly on the Connecticut rate review that’s going on, I recognize that it’s not full rates and the like. I don’t really know how to size these issues, like what the basis would be to set any of these interim rates or other things, so do you have any idea how they would even calculate what to do, what the basis would be?

I don’t. There’s probably examples of low income rates or economic development rates that other states have implemented that they could look at as models. What I would say, Steve, is that we’re very early on, early stages of this process, so it’s hard for me to add any certainty there, other than as I mentioned earlier, that we clearly are not earning our allowed return that we have agreed to under a settlement that’s been in place for three years now.

Yes, okay. Thanks so much.

Thanks Steve. Our next question this morning is from Ryan Greenwald from Bank of America. Good morning Ryan.

Hey, it’s Julien here. Thanks for taking my question. Maybe to follow up in order here, can you talk about the run rate level of contribution from the offshore projects? I know the timing is obviously moving around, and I know you just said that there’s lots of puts and takes, but in an effort to sidestep some of that debate, as best you see it today including the latest update to the ITC, how would you characterize that run rate level of net income contribution, if you will?

Yes, again it’s another way, Julien, I guess, of asking the question of providing guidance beyond our forecast horizon here, so I don’t want to publish a number until we have pretty good visibility into the annual cash flows and profile of each of the projects.

Got it, understood.

What we have said and we’re consistent on is that we anticipate these projects to provide mid-teens ROEs, which should be the highest of our business segments, which we feel is appropriate because they are the riskier of the business segments in our portfolio.

Got it, I appreciate the re-affirmation. On the balance sheet and equity, I just to want make sure I heard you right because you made a couple comments, and I think you didn’t say specifically over what period of time. I think you said $700 million over the next several years. I just want to make sure I’m hearing very clearly about your equity needs and where this positions your balance sheet over the full five-year period, if I can’t ask more directly.

Yes, I’ll let Phil answer that for you.

Great, I was going to jump in there, Jim. Julien, for the plan that we’ve put out in terms of the $17 billion capital forecast over the five years, the $700 million supports that plan along with the $100 million a year that we do through the dividend reinvestment in DRIP, so if you add that up, that’s $100 million a year through that and then $700 million through a periodic at-the-market type program. What I suggested was that that would be based upon what market conditions look like, what our metrics are looking like, if there’s changes in terms of puts and takes, in terms of the timing of the investment profile, so those would be the considerations. It would be sometime over the five-year horizon. I don’t expect that it would be in 2021. I would expect that it would be in years other than 2021 in terms of the $700 million. Obviously we’re doing the dividend reinvestment every year, so we’d have that number. Does that clarify it for you?

Maybe you can say it slightly more definitively. This puts your metrics where from an equity to debt perspective, i.e. this should suffice to maintain your metrics at roughly the same level through the five-year outlook at that equity level, or you’re not ready to make that statement?

That is correct. We would be looking to target the metrics to support the current ratings where they are today.

Okay, with the 700? All right, sorry. I don’t mean to over-emphasize that, I just want to make sure it’s clear. Thank you.

No, that’s fine. You’re welcome.

Okay, our next question this morning is from Angie Storozynski. Good morning, Angie.

Good morning. I just wanted to follow up on the equity needs. The delta between the rate base growth and the earnings growth, that’s purely about the equity dilution or are there some changes in realized ROEs as well?

Say that again, Angie?

Well because you’re saying that the rate base is growing at 8%, right, and then you’re saying the earnings growth is after half of the 5% to 7%, right, so let’s just say--let’s just say 6.5%. I’m trying to understand if the delta between 8% and then, say, 6.5% is solely assumption of the equity dilution, or is it some assumed lower ROE or something to that effect?

No, it’s primarily the equity issuance, would be the driver there. Even for 2021, you have to keep in mind that, as I mentioned in my comments, we closed out a forward contract in March and then we had additional shares that we issued in June, so all of those now get into a full year of 2021 that didn’t impact us in 2020, and then as we do the treasury shares and move in the $700 million that I discussed, that would be the primary mechanism that would be causing the difference.

Okay, thank you. Then on the Columbia Gas - I’m sorry, I’m just going to keep calling it like that for now, is it--the $275 million of capex, I understand that this is your current assessment and that you’re going to be working on incremental capex updates, but can you give us a sense of how big of a delta we could see there? Is it doubling of the $275 million a year? Is it just some tweak to the current capex estimate that you’d expect?

Well, that process, as I said, as part of the rate agreement that we had with Massachusetts when the deal got approved, in September of this year we’ll be filing a report that identifies that, so I’d say it’s a little premature to speculate on what that might look like in terms of sizing. We’re certainly active in terms of looking at that right now. I’d say that we’ve not been--there’s been no surprises in terms of taking the keys. We did it all remotely in a COVID environment, but we did a very in-depth due diligence job, so no surprises there. But I’d say we’re just not at the final stages of that assessment so that I could give you a good answer.

Okay.

Angie, the only thing I’d add is that, as Phil mentioned earlier, in that $275 million, we have some one-time items over the next couple years to fully integrate the shared service functions that are currently being supported by NiSource through a transmission services agreement, so some of that spend in the next two years in particular is really merger integration related.

Great, and if I may, just one last question. In the climate bill in Massachusetts, the latest version of it at least, it still talks about conversion of numerous houses to electric heat and then maybe less aggressive but still electric-driven construction in the state. How do you see it impacting both your electric utility and gas utility in the state? I mean, it is a Republican governor who seems to be pushing for less natural gas connections for new builds, new construction.

Well, I think first of all, both our gas and our electric business in the State of Massachusetts operate under a decoupled rate regime, so the extent volume goes up or down [indiscernible] to an approved revenue level. The biggest opportunity that we have in the State of Massachusetts is in the areas of transportation and home heating oil. More than 50% of the businesses and homes in Massachusetts heat with oil, and there’s significant improvement if you don’t go to electric or you even go to gas, the emissions uptick on improvement, if you will, is significant. I think we’ll work with the State, as we will the other states to make sure that we can aggressively de-carbonize the supplies, but we’re comfortable with where that legislation is and, as Phil mentioned, one of the components allows utility-scale solar build-out and we’re confident enough in it being there in that we’re putting it into our base forecast here for this guidance.

Good, thank you.

Thank you Angie. Next question this morning is from Durgesh Chopra from Evercore. Good morning Durgesh.

Good morning Jeff, thanks. Two quick ones. First, maybe can you--what milestones should we watch for in terms of this rate review in Connecticut, the low income tariff that you mentioned? What is the timeline and what should we be looking for in terms of calendar?

Jeff, do you have any specifics of the calendar on that proceeding? I know we’re early on in the process.

Yes, we put the docket up. I don’t think there’s really any--I mean, it’s open-ended right now.

Got it, okay. Perfect. Then just one quick clarification in terms of the--I believe the decision is in April on the storm investigation. Just what do you expect there, and how are you accounting for that in your 2021 guidance numbers? Thank you.

Sure, the remaining schedule there is I think [indiscernible] are actually due this week. I think you’d expect a tentative decision about a month later, say mid-March. Written exceptions would probably follow that a few weeks later, and then oral arguments maybe mid-April with a final decision on the 28th. I think PURA is investigating the prudence of the costs. We’re confident that we assembled the largest workforce ever in the State of Connecticut for that storm response, and the vast majority of the costs that are being reviewed have to do with bringing in those external resources, either from other utilities or from contractors. We expect, as we have in the past, that cost recovery would be allowed for these costs, as they were prudent.

Understood, thanks guys. Much appreciate the time.

All right, appreciate it, Durgesh. Next question is from Ryan Levine from Citi. Good morning Ryan.

Good morning Jeff. A couple questions. What percentage of the offshore wind capex do you expect to qualify for the IPC, and are there any steps that the company can take to increase those in the coming months or years? Then I guess the follow-up related to that is how does that differ for some of the prospective projects that you’re looking to bid on?

I’d ask Phil or John to provide any insights on that question.

Yes, effectively we would expect all or a majority of the spending to qualify under the ITC provisions.

Okay. I thought there was some component of the portion that’s not considered offshore that may not qualify in terms of the total capex deployed for the project. Are you saying that 100% of the capex is?

No, it’s roughly about an 80-20 split, so if you look at the total capex, about 80% of that will be the offshore piece that would qualify for the ITC.

Okay, and there’s no opportunity to move that 80% closer to 100%?

No, the rules are pretty clear in terms of what would qualify and what wouldn’t. What it ties to is the onshore piece obviously wouldn’t qualify, and so tying to that onshore piece, that’s deemed onshore.

Does that 80% statistic roughly apply to the prospective projects that you’re looking to bid in the various states?

I think for a rule of thumb, it’s probably safe; but again, it all depends on how we look at where we’re going to land and how do we look at the profile that’s out there with what we build in the lease area.

Okay, thank you.

Thank you Jay, and thank you Ryan. Next question is from Nick Lubrano from BMO Capital. Good morning Nick.

Hey guys, it’s James Thalacker actually.

Hi James.

Hey Jeff. A real question, just confirming--you know, it doesn’t sound like the equity needs that you are forecasting, the $100 million of treasury shares and then the $700 million of incremental equity, has really changed. As we think about the--you know, you’ve got pretty large rate base growth at the Columbia Gas business right now. Is part of the reason that your equity needs aren’t going up materially is because of the rider treatment you have there, as well as the fixed rate increase that you have embedded in the settlement?

Yes, I’d say we do have a number of, I’d call them timely recovery tracker programs, not just at Eversource Gas of Massachusetts but throughout the various subsidiaries, whether they be for accelerated pipe replacement, for safety and pole replacements, things like that, so because of the timely tracker cash recovery, that is very beneficial.

Okay, great. Thank you very much, Phil.

All right, thanks James. Next question is from David Arcaro from Morgan Stanley. Good morning David.

Hey, good morning. Thanks so much for taking my question. A couple quick ones. I was just curious, on offshore wind, to the extent there are items that improve the economics, like the higher ITC level or longer wind blades, would those benefits accrue to yourselves or are there opportunities or chances that you would pass any of those back, like in lower rates within the contract mechanism, or anything like that?

The contracts don’t call for adjusting the pricing based upon changes like that.

Okay, got it. Understood. Then separate topic, I was curious, do you see any prospects for improved acceleration in heat pump use in your states, anything that’s on the horizon that might change the economics or be in favor of using more heat pumps to electrify space heating and potentially increase the electric load going forward?

We do have a pilot program that was approved in our NSTAR gas rate case, and so at this stage, I think we’re exploring what those pilots will tell us in terms of the long-term prospects in that geography for that technology.

Okay, got it. We’ll watch that. Thanks so much.

All right, thank you David. Our next question is from Travis Miller from Morningstar. Good morning Travis.

Good morning everyone. Thanks. I just wanted to follow up on an earlier question, I think it was Andy’s question about that 8% rate base CAGR, and then the earnings guidance, the 5% to 7%. Understand the equity component. It seems like you’ve got good long-term rate plans in place, not a whole lot of regulatory risk on the other side. Just wondering if you could take us through some variables that might get you to the lower end of that range.

Thanks Travis for your question. We talk about--you know, we’re a regulated business, so certainly regulatory outcomes have an impact on where you end up in any kind of earnings growth or annual range, so outcomes of regulatory cases could move you higher or keep you in the middle, or move you to a different end of the range. Certainly incremental investment opportunities, we’ve identified several of them that are active now in terms of AMI or additional grid modernization, and those are more things that can take you to the higher end of the range. Certainly how you do as a company, any company does on their O&M management is important, and I think you might agree that you can’t really find anybody better than Eversource in controlling costs. Now certainly if there’s cost O&M pressure, that could move you around in the range, so I think those are some of the bigger variables that could move you into different parts of the range. But we’re confident in where we are guiding to, we’re confident in our ability to execute on our investment plans, and as well as run the business in a safe, efficient and effective manner.

Great, that’s helpful. Thanks. Then real quick on the electric vehicle charging, if you look out over the five years, you’d mentioned the relatively small program you have now. What do you think about the upside potential in terms of capex, and would we see that more in distribution or is there an opportunity to add transmission in terms of large substations, etc. that would support EV?

I think the benchmark, Travis, I mentioned is I think there were only 1,400 chargers in the State of Massachusetts, and we’re finishing up a three-year program that brings that number up to 5,200. But the tie is Connecticut and Massachusetts both have electric vehicles - they’re quite ambitious, we have a slide in here that shows that, so my expectation is that the investments will largely be in the distribution system. I think we’ll be mindful about any potential impacts on transmission needs, but I think that we’d be focused on distribution build-out for these chargers and I wouldn’t expect any near term transmission needs [indiscernible].

Okay, great. I appreciate it.

Thank you Travis. Next question is from Paul Patterson from Glenrock. Good morning Paul.

Good morning guys, how are you doing?

All right, how are you?

I’m managing. Really quickly on the Connecticut, you guys mentioned that you don’t think you’re earning your ROE and stuff, and I was just wondering, I know last year you guys obviously had challenges with the storms and stuff, but if we were to look on this level, 2021, I know you’re not giving guidance [indiscernible], but just roughly speaking, what kind of ROE or return range do you guy expect to be in for 2021 in Connecticut?

Paul, this is Phil. Our last file we filed on the quarters in Connecticut was about 8.6%, and we’re allowed 9.25%, so it was certainly below the allowed return in the settlement that we had. We’ll be finalizing the year. I don’t expect it to change dramatically, but that was our last filed number in Connecticut.

Does that have the storms and stuff in there, or is that sort of a normalized number?

Well as you probably know, most of the storm costs for Isaias were deferred because there’s triggers that if you’re above $4 million in Connecticut, you defer the cost, so we’ll be disclosing there was about $228 million of deferred storm costs. Those wouldn’t affect it, so it’s not an abnormally low number because of that. In addition, as I mentioned and Jim mentioned, we had 100-plus other storms and some of those don’t trigger a deferral, so those would impact all franchise--all electric franchise ROEs.

Okay, that’s great. That’s helpful. Then also, just on the COP transmission capex, 2021 and 2022 seem like they jumped a lot over your last forecast. I was just wondering if there’s anything to call out on that. You guys mentioned you’re not doing any large projects, really, or it’s mostly sort of nuts and bolts, it sounds like. I’m just wondering if there is anything in particular that--I mean, that seems to be one of the bigger moves in the slide deck.

I’m not--actually, I think the projected transmission capital is decreasing at--you know, there’s some large expenditures, or you could say larger in ’21, but then those sort of decline. Is that the chart you’re looking at, Paul?

Well, I think it’s on--when I looked at the chart, it looked to me when I was doing a comparison that from 2021, it went from 209 to 483, and for 2022 184 to 264. I can follow up later, I’m not trying to--

Okay.

But that’s what I--it just looked like to me like there was a--it could be timing too, or something, I don’t know. Anyway, I was just wondering if there was anything in particular. Then finally, on the offshore wind, given what we’ve seen in Texas and what have you, and I apologize for not knowing this, but I was just wondering just in terms of how these contracts work, if there was some issue with not being able to provide power, is there--would you have to go in the spot market and make it up, or do you just simply not get paid for the power that you don’t deliver? I just wanted to get a sense as to how it works since basically--what made me think about this, of course, is what we’re seeing in the Midwest and stuff.

Yes, from what I understand about Texas and what they’re struggling with, I think the problems stem from the financial structure for power generation that really doesn’t offer any incentives for power plant operators to prepare for the winter. They have an electric grid, they’re putting emphasis on cheap prices over reliable service, and as you know, we have a robust capacity market where the ISO locks in adequate supplies, maybe four or five years out. In terms of the thing we’re talking about, wind, which from what I understand the impact on the thermal plant dwarfs the wind freeze-up that they’re dealing with. I think the nuclear unit went down, but the gas plants are probably five or six times the load that was lost in wind - I think wind’s only 10% of the load in Texas.

[Indiscernible.] I’m not suggesting that there’s some particular issue with that, I’m just wondering, though, if in terms of wind being an intermittent resource, I’m just wondering the way the contract works, if for some reason, whatever it may be, you don’t have the production that you expected, would that be something where you just simply don’t get paid if that production isn’t happening, or would you actually be short, so to speak, and have to make up the difference? My sense is it’s the former and not the latter, but I just want to make sure.

Yes, it’s the former. We get paid on a per-kilowatt basis, so if we don’t deliver, we don’t have the revenue stream coming in.

Okay, thanks so much. I really appreciate it, guys.

All right, thank you Paul. Next question is from Mike Weinstein from Credit Suisse. Good morning Mike.

Hey, good morning. One more question on offshore wind. The CEO of Total today came out and said that the IRRs on offshore wind are very competitive, the most competitive of the entire renewable industry, 2% to 3% IRRs. Is that something you guys are seeing as well in your analysis of the project opportunities for Ørsted? What do you see going forward?

Yes, clearly the competition has increased, and I think the latest evidence of that was the New York RFP that I mentioned in my comments. We continue to stay disciplined. I think people are bidding into this for multiple reasons - very small returns, but maybe some branding uplift, I think has appeal to some of the players in the business now, so as I mentioned, we’ll continue to participate in the RFPs. We will get creative about our cost structure going forward. More and more as the supply chain moves over to the U.S. from Europe, I think there are cost advantages there, so we’ll be continuing to be disciplined. Two to three percent IRR is not something that we would want to win, frankly, in an RFP. We’re still targeting that mid-teens ROE for our investments.

Great. For the BOEM review schedule, I think in the slide deck you said you expect it in 2021 for both Revolution and Sunrise. I think previously you had said early ’21 for Revolution, but it looks like maybe you took out the word early. Is that intentional?

Yes, I don’t think it’s intentional. I think it’s recognizing that we’re going to get more specifics on both of those projects as new leadership of BOEM and the Department of Interior settle into their roles. Clearly the Biden administration is supportive of offshore wind and accelerating the approval process, but the Department of Interior, I don’t believe the proposed secretary has been approved yet. We are encouraged by what we see as the new head of BOEM - she actually came out of the Cuomo administration and is very familiar with the offshore wind solicitations that New York has run, so I wouldn’t read much more into it other than new people in new roles. We’ll see what the schedule is.

Great, then for the EV and AMI dockets, is that--I think you guy are expecting some comments in March in those dockets, and also, is there any kind of interplay or are they dependent on getting this rate review docket done first, or are they completely independent?

They’re completely independent--oh, go ahead, Phil.

Go ahead, you finish.

Yes, I think the AMI is early on in the process in term of the calendar, but the electric vehicle deployment hearings are going to take place on [indiscernible] proposals at the end of February, and we would expect a decision in late March. I think they run totally separate from the other dockets that are on the table at PURA.

Okay, great. Thank you very much. Thanks.

All right, thank you Michael. That was the last question we had this morning, so thank you very much for joining us today. If you have any follow-up questions, please call or send an email and we’ll get back to you. Have a good day.

Thanks, stay well everybody.

Thank you.

Ladies and gentlemen, this concludes today’s conference. Thank you for joining. You may now disconnect.