Eversource Energy (ES) — Q3 2019 Earnings Call Transcript

Thank you very much, John. 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. As you can see on slide 1, some of the statements made during this investor call may be forward-looking as defined within the meaning of the Safe Harbor provisions of the US 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, 2018, and our Form 10-Q for the three months ended June 30, 2019. Additionally, our explanation of how and why we use certain non-GAAP measures is contained within our news release and the slides we posted last night and in our most recent 10-K. Speaking today will be Phil Lembo, our Executive Vice President and CFO. Also joining us today are Leon Olivier, our Executive Vice President for Enterprise Energy Strategy and Business Development; John Moreira, our Treasurer and Senior VP for Finance and Regulatory; and Mike Ausere, our VP for Business Development. Now, I will turn to slide 2 and turn over the call to Phil.

Thank you, Jeff. And today I will cover the third quarter 2019 financial results. I’ll provide an update on our key regulatory dockets. Also, discuss our region's offshore wind development efforts and some recent financing activities we’ve had. We’re $0.98 per share in the quarter compared to $0.91 per share in the third quarter of 2018. Electric Distribution earnings totaled $0.61 per share in the third quarter of 2019 compared with earnings of $0.55 per share in 2018. High distribution revenues which resulted mostly from base rate changes implemented earlier in the year as well as lower operations and maintenance expenses were partially offset by higher depreciation and interest expenses. Our Electric Transmission segment earned $0.33 per share in the third quarter of 2019 compared with earnings of $0.34 per share in 2018. The decline was primarily due to no longer recognizing AFUDC earnings on the Northern Pass transmission project effective July 1, 2019. Our Natural Gas Distribution segment lost $0.05 per share in the third quarter of 2019 compared with a loss of $0.04 per share in 2018. The decline was expected and was due to the implementation of gradual revenue decoupling at Yankee Gas late last year. As I've discussed on earlier earnings calls, the decoupling boosted revenues in the first quarter but lowered second and third quarter revenues when customer demand is at its lowest. The impact of revenue decoupling in the fourth quarter will be fairly neutral compared to last year. Our Water Distribution segment earned $0.06 per share in the third quarter of 2019 the same as last year as higher revenues and lower depreciation expense were offset by the absence of a small gain on a land sale that we recognized during the third quarter of 2018. Our Parent of Other Segment earned $0.03 per share in the third quarter of 2019 compared with nearly flat results last year. The improvement was largely due to the absence in 2019 of last year's write-off of an investment in Access Northeast natural gas transmission project and certain benefits we recorded in the third quarter of 2018 related to tax reform. Overall, we are at $2.69 per share in the first nine months of the year, excluding the Northern Pass charge we discussed last quarter compared with earnings of $2.52 per share in the first nine months of 2018. Excluding the charge, we remain very comfortable with our ability to earn around the midpoint of our $3.40 to $3.50 per share range that we first announced in February. While we continue to experience much higher than normal storm expenses, we thus far have been able to offset that impact elsewhere to remain within our guidance, but it's something we'll need to keep an eye on as we close out the year. The midpoint of that guidance range is consistent with our long-term earnings growth rate of 5% to 7%. Moving from our earnings discussion to key operating performance results. Our continued intense focus and emphasis on safety continues to produce strong results, our best ever as a company. Our electric reliability continues to trend very strong with months between interruptions at 22.2 months through September this year versus 17.4 months during the same nine-month period last year. Our reliability continues to be at a level that is among the very best in the industry. Also, our ability to respond effectively to weather-related emergency conditions at our systems continues to receive favorable reviews from our customers and policymakers. In late July, we responded to extensive damage on Cape Cod caused by a rare set of three tornadoes. About three weeks ago, a nor'easter with winds of up to 90 miles an hour also impacted Cape Cod causing significant damage not only in Southeastern Massachusetts but in Eastern Connecticut and Coastal New Hampshire as well. Our crews organized quickly around last month's storms and, with the aid of significant outside resources, we restored power to nearly every one of about 475,000 outages in about two days. Another storm on Halloween night resulted in significant tree-related outages up and down the East Coast. That storm caused more than 250,000 customer outages with the worst damage in Connecticut and New Hampshire. Thousands of our employees and outside line and tree workers contributed to a very strong restoration effort. Turning from operations to some regulatory items. Our New Hampshire electric rate review continues through the discovery process with intervenor testimony due next month and a final decision expected in May of next year, 2020. You'll recall that on June 27, regulators approved the settlement we reached with public utilities Commission’s staff and the Office of Consumer Advocate to implement an annualized $28.3 million temporary increase in base rates. The temporary increase was effective July 1 and will remain in effect until permanent rates take effect in the middle of next year. On the rate reviews, I'll turn to slide 3 in PURA’s recent decision in Connecticut's grid modernization docket. In early October, PURA issued an order in which it divided 11 different topics related to grid modernization into two separate dockets, and then promptly initiated reviews on six of them. So, those six include items such as advanced metering infrastructure or AMI, electric storage and zero emissions vehicles. There will be a second and third round for this docket, which will cover five other topics ranging from resiliency standards to new rate designs. The process for reviewing each topic will include public forums, requests for different proposals, and hearings leading up to a draft and final decision. Although PURA found these topics to be potentially very beneficial to customers, it’s not yet known when they will result in meaningful investments related to these grid technologies. We will update you on the processes in both Connecticut and Massachusetts as we move forward. While we have not yet included any grid modernization expenditures in our capital forecast for CL&P in Massachusetts, we expect NTAR Electric to complete the $233 million of investments previously approved by the Department of Public Utilities by the end of next year. An updated grid modernization proposal covering the years 2021 through 2023 is due to the Massachusetts regulator by the middle of next year. Many of you have asked us recently when we will provide a comprehensive update on our capital investment plans. So, I'll just say, as we've done in each of the past six years, we'll provide you with the update when we release our year-end results, which we expect to do in the second half of February. Turning to offshore wind in slide 4. Massachusetts announced the results of its second offshore wind solicitation last week in which Mayflower Wind was selected as the winning bidder. Mayflower’s pricing is expected to become public in January when that contract is due to be filed with the state regulators for approval. Based on public statements made to date, we believe that Mayflower bid a price that would not have allowed us to earn the returns that we consider adequate as we did at the same level. In Connecticut, bids were submitted at the end of September following up on a 2,000 megawatt offshore wind authorization that the legislature approved in June. Three parties submitted bids for these 400 megawatts each. We submitted one bid for 400 megawatts and other bids for other levels of capacity. Later this month, we expect the decision on this RFP in Connecticut. In New York, we and Ørsted signed a 25-year contract last month with the New York State Energy Research & Development Authority relating to the supply of 880 megawatts of offshore wind into the New York market. The pricing is disclosed and it is $110.37 per megawatt hour flat for 25 years. It was made public when the contract was signed two weeks ago. That pricing and the pricing of the other power purchase agreements we have secured in Connecticut, Rhode Island and Long Island, each of which is 20 years, will support the mid-teen returns on equity that we expect and that we have been discussing with you on prior earnings calls. We expect these returns will significantly exceed those of any of our regulated segments. Several analysts on this call have asked us over the past week or so whether the mid-teen returns are still applicable given Ørsted’s statement last week that it expects unlevered returns across its global portfolio to be in the 7% to 8% range going forward, down 50 basis points from its previous range. Ørsted also indicated that for the project they are now anticipating an average capacity factor of 48% rather than 48% to 50% due to new understandings of wind dynamics around large offshore wind farms. Additionally, on projects that acquired from Deepwater, Ørsted indicated that certain transmission cost estimates have increased. As Ørsted’s partner on some of the former Deepwater projects, we have been jointly developing some of the US cost estimates Ørsted decided. There are several factors that support our continued expectation that we will be able to earn in the mid-teens on these three projects noted on the slide in front of you. First, the transmission cost estimates that we've been assuming this year in our discussions with investors have not changed. They are consistent with Ørsted’s current expectations but are of more recent vintage and higher than the cost estimates available to Ørsted shortly after we closed this Deepwater acquisition last fall. Also, our assumed returns for offshore wind investments are consistent with Ørsted’s current 7% to 8% range. Just a takeaway here is our guidance remains in place. We expect our offshore wind investments to produce returns on equity in the mid-teens. Our mid-teens ROE expectations are based on our current enterprise-wide capitalization and capacity factors in the 48% to 50% range across our portfolio of wind turbines in the US. We continue to be very encouraged by the knowledge and experience of our partner and by the interactions that we've all had with federal and state regulators. Turning to financing on slide 5. We essentially ramped up our 2019 financing program in the third quarter with nearly $500 million of long-term debt issuances across Connecticut Light and Power, Yankee Gas and NSTAR Gas. We expect to close on a small debt issuance at Aquarion Connecticut before year-end, but that's the only remaining financing in 2019. The decline in interest rates this year is certainly resulting in interest savings not only in the long-term debt issuances shown on this slide but also on our commercial paper borrowings where rates are down by more than 50 basis points compared with the end of 2018. Moreover, interest rate benefits our customers and our shareholders. You recall that we sold $1.3 billion of new common shares in June with about 12 million of the 18 million shares subject to a forward sale arrangement that will settle before the end of May 2020. To date, we have not settled any of the forward sale arrangements. Additionally, as we've discussed earlier in the year, we also expect to utilize approximately $100 million of treasury shares each year through 2023 to meet our dividend, reinvestment, and employee retirement plan requirements. Through October of this year, we have distributed approximately 900,000 treasury shares to meet those planned requirements at a rate of just under 300,000 shares a quarter. Before I turn the call back over to Jeff, I just wanted to take a minute, I'm sure you've heard that Lee Olivier recently announced his decision to retire at the end of the year. I want to extend my thanks and appreciation to Lee for a tremendous amount of work he has done for nearly a 50-year utility career to make our company and our industry much better off. After a highly successful career as a senior nuclear officer, Lee arrived at Northeast Utilities nearly two decades ago and led one of the most successful build-outs of an electric transmission system anywhere in the country. He later moved on to the position of Chief Operating Officer at NU, and then at the merged Eversource, before beginning what may be his favorite position, which is overseeing our enterprise-wide strategy and business development efforts. I'm sure, a decade from now, I'm convinced Lee will be known as one of the fathers of a thriving US offshore wind business. Lee and I have worked together for more than 20 years. And so, we’ve seen the front-end and back-end. He is an outstanding leader and just a wonderful person to work with. All of us wish Lee a wonderful retirement commencing at the end of next month, and I want to thank him for his advice and counsel and for joining us on his last major call. So, thank you, Lee.

Well, thank you very much, Phil. I really appreciate it – appreciate those remarks, and it’s been great to work with you for all of these years.

Thanks.

You're a great leader and a financial engineer yourself. Thank you.

Thanks. Well, I’ll turn the call back over to Jeff.

All right. Thank you, Phil, and I'm going to turn the call back to John just to remind you how to enter your questions. John?

Good morning, Mike.

Hey. Good morning. I believe this is quite a move. Congratulations and we're all going to miss you I think. It's been a long time ever since the news projects. That's kind of the earliest thing I remember you famous for.

Well, thank you very much.

Well, congratulations again.

You too.

Hey. My question is about the upcoming NSTAR gas filing and what – maybe you could shed some light on what that's going to entail and also whether you think there's going to be any additional work that might be necessary on the gas utilities as a result of the Merrimack Valley incident from last year?

Yes, Mike. This is Phil. We’ll notify the department that we would be in soon for filing and we expect to make that filing shortly here in the next days or weeks. So I say there are a few nuances to the filing that do address some of the issues that we know of and that could potentially come out of additional work efforts and requirements from the Merrimack Valley incident. So I think you will see, when we do a filing in this area, creative ways that we want to address and get ahead on. You know, certainly, costs that would be moving up in terms of safety and engineering, professional engineering requirements that are now in effect that weren't necessarily in effect during our testier period. So, I think you're right that it will be, in some respects, sort of a basic filing, but there will be some creative ways that we can address some of the issues that have come up thus far and provide placeholders for things to come up in the future.

And then maybe just with that same line of thought, maybe you could just give a broad overview of the categories of updates that might be coming in February? You know, not necessarily the numbers so much.

Well, in categories, it would be the long-term earnings guidance. And as we've done for many years now, we would adjust that moving forward, you know, add a year onto that. So, less year or add a year so that the long-term earnings guidance will have our guidance for the current year period. We’ll give a capital forecast by category, you know, showing, you know, what capital spending looks like over that five-year period. We'll provide, as we’ve talked about, a little bit more detail now that the bids will be all-in and developed and pricing known and probably all public by that time. You know, more information sort of on the offshore wind side of things. And then any current regulatory or other matters we see out there. Mike, any other questions?

Yes. Sorry. Just one last question. On the Ørsted, I guess the Ørsted guidance, it sounds like that was – basically what they've been saying is already baked into your mid-teens assumption that that's why there's no change, right? I just want to just confirm I understood that correctly.

Yes, I think it's important, Mike, to just note that I think Ørsted’s updates were to reconcile back to a Capital Markets Day from about a year ago last November. Our guidance is really based on current information, and all of our disclosed items have already been considered in the guidance and expectations. So we continue to be comfortable providing forecasts in the mid-teens on ROEs. And we continue to look at those costs and schedule estimates as we go forward.

Great. Terrific. Thank you.

All right. Thanks, Mike.

Hey. Good morning, guys. Can you hear me?

Yes.

Yes, we can hear you.

Okay. Great. Let me just on – just on the rate cases, could we just get a quick update on New Hampshire's proceedings? Is there – I guess is there any opportunity to settle after discovery, how we start a discussion that’s going with them?

Yes, Shahriar. This is Phil. There's absolutely an opportunity...

Hey, Phil.

To do that, to settle. In fact, on the official schedule, there's time allocated for settlement conference. So that is really the way that things proceed in New Hampshire. So there is an ability to get to that settlement. And then there is a conclusion. I mentioned in May. That’s in the – on the docket, so I would expect that once we go through all the discovery and all the data that it provides a better basis for having some meaningful settlement discussions.

Got it. And, Phil, you mentioned placeholder items and the NSTAR gasoline. Can you just elaborate on what you will do there?

Yes. Sure. And this is true for some of our other filings in other states where we might have an approval for a tracker that is approved and had a rate case. But there – how much is in that category would have to be defined in a future filing. So for example, we have these safety and reliability filings that are approved trackers, how the recovery works, what the procedures will be. And then periodically, we go in with a plan for this is what the spending will be for the next year or the next few years. We have the same thing like on energy efficiency. We have an approved method for collecting it, but then we have a plan that goes in each year. So that's what I'm referring to is that our mechanisms would be established and then as resources come up. So you wouldn't have to go back in for a base rate type of filing; you'd have the mechanism there.

Got it. Got it. And then just lastly, I know past discussions seemed to point to potentially getting a CapEx update at EEI not necessarily rolling you forward and – but more of a CapEx update around your base business, right? Is that the rationale to not providing an update, is it a function because of the New Hampshire case is taking longer than maybe you anticipated, so I'm kind of curious in why not on the base business without having a roll forward, could it seem like maybe past discussions centered on the potential update at EEI?

Sure. I will maybe make a point there, Shahriar. We have never really provided an indication that there would be an update. We've always pointed to the February year-end call as being the time we would do the update. So, what our statements are and what our plans are now are very consistent with what our thinking has been all along. We will plan to and we will do an update in February. So, I’m not just to be clear, we are not changing anything as a result of any proceeding. It's really that's been our plan all along.

Got it. Thanks. And, Lee, congratulations, you're definitely going to be missed.

Well, really, thank you. Thank you very much, Shahriar. It's been – it’s been a lot of fun working with you over the years.

We’ll stop to take you out for a nice steak dinner, though…

Give it a go.

...and Jack.

Give it a go – and Jerry. Why not? Why not?

You got it.

All right. All right. Thanks. Thanks, Shahriar.

Good morning. I mean, starting with the offshore wind, given your comments on the recent Massachusetts RFP results and the point that maybe the pricing didn’t – wouldn’t have met your return expectations, are you still of the mindset that the future – the current and future bids on future offshore wind projects will try to maintain your 7% to 8% unlevered IRRs or mid-teens ROE assumptions?

Yes, we are, and that is our plan.

Understood. And appreciating on the Connecticut grid mod side, it’ll probably be a lengthy process of discussing all those various items that you could potentially invest in. And, I think you've talked in the past about pieces of those and how much that could potentially be, for example, AMI in Connecticut and Massachusetts being a $1 billion opportunity, and as well. But just is there any way to frame what the total opportunity set longer term would be for the Connecticut portion of all these items? I’m assuming they won't really be in the base plan when you roll forward the CapEx plan in February.

That's correct, Insoo. Unless it's something that we have a clear line of sight for, it would not be. And just to be clear, it’s not in our plans now. So, we've always talked about Connecticut as a potential program that would require investments to modernize the grid into various categories. And in AMI, we've mentioned a number of $1 billion program, and that's really across Massachusetts and Connecticut. So, you know, the number of customers, you know, are fairly consistent across the two states. But you might have different vintages of meters. So, but, you know, it's probably 50/50 across the states I think is a good determination of that. But, again, we don't know, you know, what will come out of the proceeding that are going on. We feel that we have effective programs that can address all of the 11 categories that the Connecticut PURA has established and it's good to see sort of in the first six of them, they’re really, you know – half of them or more are already programs that we're working on in other states. So, we feel good about our ability to deliver effectively there. But the timing and how much will be will be determined going forward.

Understood. And, Lee, congratulations. I know you and I haven't really interacted much given my coverage, but I wish you all the best.

Well, thank you very much. I appreciate it. Good luck to you.

All right.

Hey, good morning and congrats, Lee. Wish you the best.

Thank you, Steve.

You bet. And so just maybe a little bit more color on the approvals and just the supplemental study and both timing of that as well as just what is the focus that you've seen so far of that study and just how do you feel about the overall timeline then of your projects?

Yes, Steve. This is Lee. I think that the indication that Bowman now given is that they all have a draft of the supplemental study in the first quarter of next year. And they're looking at the full array of issues as an example. When these leases were let some years ago, they really did not understand the scale or magnitude of the development across all of these areas. And at that time, I think it was just probably a bit of an oversight they didn't really understand what the fisheries – actually, how they work, how they fish, whether it's straddlers or crustacean fishermen and so forth. And then, there were issues that have arisen around the layouts and how mariners would be able to access to and from ports in the area, and also with the Coast Guard in terms of how they do their search and rescue operations. I think all of those are better understood now and those are the kinds of issues that will be factored into their analysis. I think we – the joint venture and feel very good about that. We’ve consistently in terms of our layouts and arrays have met with and got feedback from fisheries and mariners in the Coast Guard. So I think our arrays will be laid out as such there will be minimum issues in the industry, the offshore wind industry in the Northeast where our leases are all collaboratively working together to come up with a sub-common arrays and layouts such it will help facilitate the bulk process once they complete their supplemental EIS. And so we don't think there is any delays right now that we can forecast in any of our projects this time.

Thank you.

You’re welcome.

Hi, guys, and congratulations, Phil.

Thanks a million, Praful. Appreciate it.

Yes, so I just want to quickly follow up again, unfortunately, offshore wind. Was there a delay right now in the schedule for Revolution Wind? Did that get pushed out a little bit?

No. With this, it's pretty much on track. I think if there was a delay – because we have not filed – we have not filed our BOEM permit yet. And we expect to file with them in early 2020, probably by the end of the first quarter at BOEM at which point in time, we’ll have a clear understanding of where BOEM is going to be with their supplemental EIS. So right now I think would be premature to look at the delay in Revolution Wind. So, we're still looking at a commercial operation for Revolution Wind late in 2023.

Got you. And you didn't move out the construction – the start construction. I know it's got pushed hard but it's the same as you had before?

Yes. It's pretty much the same as we've had before and we won't make any changes. We don't feel there is a need to make any changes until we understand if there is any impact with the supplemental EIS involve.

Got you. And then, just secondly in terms of all these projects and in the context of what Ørsted said, is there any incremental revenue that is assumed as part of these projects to achieve your IRRs? So, for example, capacity revenue or ancillary services, anything incremental that helps kind of achieve or get to your target returns?

Well, in the case of Sunrise Wind, there are pricing at $110.37 as predicated both on the energy, receiving energy revenue and capacity revenue inside of that market. And so we feel good about being able to achieve that.

Yes. So, I guess I'd add to that no other really – in the guidance we’ve given it's all based on the pricing that that’s under the contract there.

There is a move afoot here in New England for probably more ancillary kinds of services that was proposed. But that's – right now, it's all in concept mode. So, we would have to see what happens there.

Got you. And so just to confirm the Sunrise Wind has the capacity revenue component or that's already built into the price that you put here in terms of a final like locked in price?

Yes. That’s built into the price like a locked-in price.

Yes. That's built into the price.

The fixed price.

Okay. Perfect.

Yes.

Got you. Thanks so much, guys.

Thank you.

Thanks, Praful.

Good morning.

How are you doing?

All right.

Congratulations, Lee. And I wanted to follow up on just a few quick things. First of all, the Connecticut grid mod proceeding, it seemed like after quite a bit of a delay and a lot of time, they've now come up with a whole bunch of other proceedings, as you guys mentioned on your prepared remarks. Any sense as to how long all this might take? And is there any proceeding or any that the new proceedings that maybe are more of a priority or we should focus on more than the others? I mean, it just seems like quite a bit to cover if you thought what I’m saying.

Yes. So, I think, Paul, this is Phil, that you’re right. There's – there was a lot of time, but recall that the Connecticut PURA, there was a new Chair of the PURA. So, certainly, in that transition, the Chair of any authority wants to set a direction and have some influence over the proceedings. So, it probably shouldn't have been unexpected that it would be some modifications or time frame schedule that came out with – after the new Chair was appointed. But – so, I think, the way you could look at it is they set up 11 different topics and, if you were me, I’d look at the first six that they’ve done, right? So, the first six focus on AMI, storage, electric vehicles, and some technologies if there’s any change needed in interconnections, etcetera. So, the first one is I would think of as the most critical and the most priority to the chair. And we have done work in every one of those areas in multiple states so we think we already have good plans and good proposals that we’d be ready to move forward with. So, that’s kicking off right now. In terms of what the exact schedule will be, that is still to be determined. But the first – what happens next in the first half of 2020 is there's another set of three and then there's two more to happen sort of after that. So, just sort of the staging of the topics I think gives some indication of which ones would be the most important. But how those – what the time frame would be for a conclusion, I don't expect that we have any meaningful if there were investments to be made I think it’d be beyond 2020. You’d probably at best have the first set completed in 2020 with decisions made and then programs set up for possibly some spending in 2020 and then beyond that. So, I think that's the time frame we're looking at.

Okay. And then, there's also been some press coverage of, I guess, some proceeding in Connecticut on affordability and service terminations and what have you. And from what I can see, it seems like this is mostly associated sort of identifying people at risk for first service cutoffs. But is there anything else we should be thinking about with respect to this I mean or is that sort of what the focus is? Is there any other element of that or is there anything you'd like to add about it in terms of how that is unfolding, I guess?

So I think what you're referring to is – it’s separate from this proceeding for PURA that is going on.

Yes, yes. I didn’t mean to suggest this part of the stuff.

Yes. No, I don't know. No. There's no bigger agenda here for affordability. I think just affordability is on everybody's radar screen and we want to make sure that we deliver quality products at a price that is affordable for customers and that's what we do. That's how we design our rates. So there's really no specific agenda for that category yet and that will be decided as we move through.

Okay. Awesome. Thanks so much.

Thank you, Paul.

Hey. Good morning, Phil. Thank you. So perhaps when could you file the proposal in Connecticut just to follow up on Paul's question here? Can you – well are an open-ended just with respect again to the timeline you guys have articulated here?

Yes. I'd say for the first quarter – April would be a time frame for the first set of items.

Got it. And then still sort of broadly thinking the same timeline to start and spend in kind of a year plus?

Yes. As I said, I would expect that you'd have some decision in 2020 and you could have some spending in later 2020 for any of these programs into 2021 and beyond.

Right. Okay. Excellent. And then perhaps clean up here, apologies if I missed this, but commentary about how you think about expansion on gas and acquisitions on that front or more broadly acquisition strategy. I know that there's been some degree of media attention on this, perhaps it died down, but just want to come back just sort of the core thought process here. Just basically in Mass.

Yes. No. We did not – we hadn’t mentioned – we didn’t mention I think so you didn’t miss anything, Julien. And I think that we are focused on our core business and running our core business in an effective way. We've been able to deliver that core business growth and affordability and performance in a way that meets our customers and regulatory requirements. We've been able to do that and deliver in the middle of the 5% to 7% growth rate out of our core business. So, we’re focused on managing those core assets in an effective way and working effectively on our offshore wind business. So, that’s what we’re focused on. We certainly have enough on our plate to work on there. So – and that would be our continued focus going forward.

Got it. Sorry. One more cleanup item if you don’t mind. With respect to earnings recognition of tax credits, obviously, another quarter, getting a little bit closer and hoping getting some clarity here, how do you think about that contributing especially given the very specific timeline you articulated already for the in-service of all these different projects how do you think about the cadence of that and how do you think about that contributing to the long-term earnings CAGR or the consistency of long-term earnings sort of ex these credits?

I think our long-term earnings will continue to be primarily driven by our core business and I think you’ll see that our core business really is the driver for the 5% to 7% growth rate. And as we've said that the niche projects come into service, the offshore wind projects come into service in 2024 in terms of contributing to earnings. And beyond that, our growth rate will improve and increase.

Got it. Okay. Fair enough. I'll leave it there. Thank you, guys.

All right. Thanks, Julien.

Good morning, guys. Congrats on the quarter.

Thank you.

Got a question I wanted to follow up on Connecticut. It just seems to me, from looking at your slides, that they're kind of doing AMI and all this fun stuff first and then redesign later after all of that. So, is that the accurate read of the sequence of events here? And if so, is there any rate design changes that should be critical for the proposals that they're considering or can your existing rate design accommodate all of it or do you need any changes like what is your wish list there?

No. I think you're reading that correctly, Sophie, that sort of the later topics for some future period of time would include, you know, rate designs, etcetera. So, we don’t feel that there's any specific major, you know, changes in terms of rate design that would, you know, be impacted by any of the other categories that we're working on. There certainly would be no volumes impact, you know, for that. But, you know, I think we were able to – there may be some minor – you know, there may have to be a tracker or there may have to be some other category, but, you know, in terms of major rate design, you’re right that anything on that front would be, you know, later topics for discussion.

But just to be clear, you wouldn't be deploying any incremental capital until you're clear on their rate design and maybe additional trackers or things like that?

No. No. That’s not clear. We’re able to with our current rates and our current design be able to implement any of the categories that is currently under review. So we do have trackers. We do have sort of placeholders for future grid modernization items just to slide in there. So, no, we would not need to go through a rate design proceeding to be able to implement these items from the first wave.

Got it. All right. Thank you. That’s all I had.

All right. Thanks, Sophie.

Good morning. Thank you. I just wonder if you could give a quick update on the water business developments there, what you're looking at over the next kind of 9 to 12 months, and then related to that acquisition rollup, small acquisition opportunities.

Hi, Travis. How are you doing? This is Phil. I will start off by saying we're very pleased with the performance of our water business. It’s ahead of where we thought it would be at this time when Aquarion was brought into the Eversource family. We continue to look for opportunities to learn from each other and implement best practice or integration efforts there to improve operations on both sides of the ledger. We're looking at and continue to look at opportunities to grow that business in a financially disciplined way. And as opportunities present themselves, we will take a look at them. So there’s nothing different to that strategy. We continue to look for opportunities whether it be a opportunity that has more customers of the smaller acquisitions, of roll-ups, we'll continue to evaluate them.

Okay. Any regulatory – major regulatory issues or stuff you see going down the line here in the next again kind of 9 to 12 months?

Are you referring to in the water business?

In the water business. Yes.

No. No. Nothing that we see on the horizon in that time period. That’s correct.

Okay. And then just real quick, you answered most of my offshore wind questions. But wondering on those contracts either the New York one or the other ones you've had, how much flexibility if any is in that pricing, and are there any clauses in terms of buyouts or adjustments or contract cancellations or anything along those lines of say costs got out of line or there were timing delays stuff like that?

Yes. I think you can assume that this is just standard contract revisions in terms of commitments to pricing and then standard commitments in terms of getting projects and service, but there are certainly opportunities within a reasonable range of these changes in dates and all that. That's all provided for already in the contracts.

Okay. Great. Thanks a lot.

Hey. Good morning, everyone. I am basically all set. Just one follow-up I guess since you have me in here. The comment you made about lower returns and you would have been comfortable with the answer to a prior question for offshore wind that is. How would you think going forward about that trade-offs? If pricing continues to decline perhaps faster than your costs, would you be more willing to sacrifice a little bit of the returns or a little bit of the volume of projects won? How do you think of that tradeoff?

I think some of the – some of it is speculation of what might happen in the future. But I would say that our position is that we want to maintain our return levels going forward in that business. So we'll look for opportunities to maintain and participate in auctions or RFPs in a way that we can compete effectively and that competition allows us to maintain a mid-teens level of returns for our shareholders.

Okay. So it would be to be mid-teens, it wouldn't mean – it has to be more than a certain level above your regulated distribution returns, right?

Yes.

I could say.

Yes. That is correct.

Okay. Thank you.

All right. Thank you, Andrew. That's the end of the queue for today. So we want to thank you all for joining us. We look forward to seeing most of the folks on the call at the EEI Conference starting on Sunday. Thank you.