Eversource Energy (ES) — Q4 2019 Earnings Call Transcript

Thank you, Paulette. 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. And as you can see on slide one, 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 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, 2018, and our Form 10-Q for the three months ended September 30, 2019. 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; Jay Buth, our VP and Controller; and Mike Ausere, our VP for Business Development. Now, I will turn to slide two and turn over the call to Jim.

Thank you, Jeff, and good morning. Thank you everyone for joining us today for our review of 2019 results and for our updated long-term outlook. I'll start by thanking our 8,300 Eversource Energy colleagues for just a terrific 2019 and for the very bright future we expect for our company and our customers. As you can see on slide four, our investors benefited from a very strong total return of 34.4% in 2019. That return was 860 basis points ahead of our peer index and nearly 300 basis points ahead of the S&P 500 total return in 2019. And as you also can see on this slide our three-year, five-year and ten-year performance has consistently beaten our peer index, as well as the broader market. And as the January 2020 performance comparison shows, we're off to another strong start this year. That constancy of shareholder return is directly related to our solid long-term record of operating performance. On slide five you can see the results of our commitment to continuous improvement in our operating metrics, related to reliability, safety and emergency response. They are in the top-tier of our industry and the top decile of our industry peer group from reliability. That execution and the drive to provide ever-improving service to our 4 million customers here in New England, form the linchpin of our strategy. By excelling at our basic business, we enjoy strong credibility with our regulators and other state and federal policymakers. Our leadership position on energy issues is also enhanced by our strategy of being a catalyst for clean energy development in New England and for our efforts to strive for best-in-class governance employment policies, safety programs, energy efficiency support and leadership in our communities. Some of the organizations that have recognized our leadership over the past year are listed on slide six. The credibility generated by our strong operating performance helps us achieve very tangible results, especially in areas such as structuring long-term rate deals in our regulatory jurisdictions or entering new business ventures, such as water and offshore wind. We have a prominent seat at the table, as our business strategy aligns very well with the energy economic and environmental goals of the region. All New England states are targeting at least an 80% reduction in greenhouse gas emissions by the year 2050. This is a very ambitious goal, especially given that nearly 50% of those emissions today come from the millions of motor vehicles that cross our thoroughfares every day. In December, we announced that we will support these efforts by setting a goal of making Eversource carbon neutral by 2030. That's the most ambitious goal of any energy utility in the United States. And as you can see on slide seven we have already reduced our carbon emissions by approximately 70% over the past few years, primarily by divesting our fossil generation in New Hampshire. From here, our efforts will focus on improving the efficiency of our electric grid, further accelerating the replacement of older cast iron and unprotected steel natural gas distribution pipes; changing our fleet to include more hybrid and electric vehicles; and increasing the energy efficiency of our buildings. Setting this aggressive carbon reduction goal makes us more attractive to ESG-focused investors, who now comprise about 10% of the 1,600 domestic and international funds currently invested in Eversource shares. Our clean energy strategy is further enhanced by our partnership with Ørsted to build at least 4,000 megawatts of offshore wind off the coast of Massachusetts. This build-out is incremental to our goal of making our operations carbon neutral by 2030. Slide 8 provides a status report on the 1,714 megawatts we have won thus far through successful bids into Rhode Island, Connecticut and New York RFPs. As you can see on this slide, we have secured approvals of the long-term agreements we have under contract. So clearly, the focus ahead is on siting approvals. This year we expect to file our construction and operations plans for our two large projects with the Bureau of Ocean Energy Management or BOEM. We expect to file Revolution Wind in the first half of 2020 and Sunrise Wind in the second half of the year. Those filings would be consistent with our expectation that Revolution will have its first full year of operation in 2024, and Sunrise will have its first full year of operation in 2025. We continue to target operation of the first and smallest of these three projects South Fork by the end of 2022. We are currently reviewing that schedule in light of BOEM's recent announcement that it will not complete its cumulative impact study on the six tracks of Massachusetts until mid-June. That study is part of the Vineyard Wind application, but will likely encompass all of the tracks. The pricing of most of our PPAs is public and noted on this slide. In December, Congress passed and the President signed legislation extending for one year and increasing over 2019 levels both investment tax credits and production tax credits for construction commencing in 2020. We applaud this extension which supports this rapidly growing industry, and we expect to qualify for 18% tax credits on our three projects. As you know, while we were successful in the New York RFP last year, we were not successful in the Massachusetts RFP or the Connecticut RFP, both of which were awarded in the fall. While the Connecticut pricing is not public, the Massachusetts pricing was made public with the contract filing this month. Like the first Massachusetts RFP in 2018, the pricing in the most recent RFP would not be sufficient for us to earn our targeted mid-teen returns. So, although disappointed, I was comfortable with our bid not being selected. As I have said to both the Ørsted Board and the Eversource Board, we control the two best ocean tracks that BOEM has auctioned off in New England. They are the closest to shore, which you can see on slide 9 and should be the most economic to develop and maintain. Between New York, Connecticut, Massachusetts and Rhode Island there will likely be at least 15,000 megawatts of contracts available to developers over the coming years. The last thing we would want to do is lock ourselves into contracts for 20 to 25 years that would not allow us to earn our targeted returns because we bid too aggressively. We consider our sites to be a tremendous competitive advantage, and we'll be disciplined in our bidding. We'll take some additional few years to reach the 4,000 megawatt capacity for our tracks. We are fine with being patient and preserving our potential returns. In the meantime, all four developers of the tracks of Massachusetts achieved a significant milestone late last year when we committed to BOEM and the Coast Guard that we would coordinate our development to provide one nautical mile spacing between offshore wind turbines, both East-West and North-South across all parcels creating a grid-like configuration. We believe this is a very positive development in addressing the concerns of both the region's fishermen and the Coast Guard. In late January, the Coast Guard published a notice for public comment indicating that this one nautical mile by one nautical mile configuration will create adequate spacing for search and rescue operations and would maintain safe ship navigation. Earlier this month, Connecticut Governor, Ned Lamont announced a public-private partnership that will result in up to $157 million being invested in refurbishing the New London State Pier as a staging ground for offshore wind construction. This innovative partnership into which Eversource and Ørsted together will invest a projected $77.5 million will allow Connecticut to realize significant economic development benefits from this new clean energy source. So, to conclude my offshore wind comments, I want to emphasize what a great opportunity this development is for our region, for our customers and for our company. The area off the Massachusetts coast is perhaps the best place for offshore wind in all of North America, because of the year-round wind speeds, the shallow depth of the waters and the proximity to Southern New England roads. I believe our two parcels are the best situated of the six parcels that BOEM has auctioned off and our partner Ørsted is the best and most experienced developer of offshore wind in the world. Perhaps most importantly, offshore wind is in the sweet spot of public policy, providing billions of dollars of economic development benefits to our region and benefiting from widespread support from public policymakers, the business community and environmental groups. As a result, I could not be more optimistic about the future of our offshore wind business. As a reminder, our offshore wind opportunity is incremental to the solid growth prospects we foresee for our core business. As you can see on slide 10, we have grown earnings per share by approximately 6% on average, since the 2012 merger that created Eversource. We expect to continue to grow earnings per share by 5% to 7% solely through the growth of our core regulated utility business. And that 5% to 7% growth excludes earnings from the two large offshore wind projects that we expect will produce significant additional EPS growth in 2024 and 2025. As shown on slide 11, the key element of our total return profile remains our dividend growth. With our solid earnings growth and conservative payout ratio we consider our dividend to be extremely well supported with a growth trajectory similar to our 5% to 7% EPS growth. Earlier this month, the Eversource Board of Trustees approved a 6.1% increase in our quarterly common dividend. That increase underscores our confidence in our long-term earnings growth and business strategy. Now, I'll turn the call over to Phil.

Thanks, Jim. And today, I'll cover our results for 2019 discuss the earnings guidance for 2020 and the key drivers that support that. I'll provide an update for you on our five-year CapEx plan in our 5% to 7% EPS growth and review the outstanding regulatory items we have pending. I'll also cover briefly what our financing plans are for the year 2020. I'll start with slide 13 and our fourth quarter and full year results for 2019. Our GAAP earnings were $2.81 per share in 2019, including a $0.64 Northern Pass charge we recorded in the second quarter. Excluding that charge we earned $3.45 per share in 2019 compared with earnings of $3.25 per share in 2018. The $3.45 was a 6.2% increase and right at the midpoint of the earnings guidance we provided you a year ago. In the fourth quarter of 2019, we earned $0.76 per share compared with earnings of $0.73 in the fourth quarter of 2018. Now some specifics about the quarter and year. Earnings for our electric distribution segment were $1.59 per share in 2019 compared with $1.44 in 2018. They were $0.28 per share in the fourth quarter of 2019 compared with $0.24 in the fourth quarter of 2018. So both the full year and the fourth quarter results improved primarily as a result of higher distribution revenues. These were partially offset by higher depreciation and operation and maintenance expense. The transmission segment earned a total of $1.43 per share in 2019, excluding the Northern Pass charge compared with $1.34 in 2018. They were $0.36 per share in the fourth quarter of 2019 compared with $0.31 in the fourth quarter of 2018. The higher full year and fourth quarter earnings primarily reflect an increased level of investments in our transmission facilities. Our transmission rate base ended 2019 at an estimated $7.26 billion compared with $6.75 billion at the end of 2018. Transmission capital expenditures totaled slightly more than $1 billion in 2019 or about 3.5% higher than the year previous. Earnings from our natural gas segment totaled $0.30 per share in 2019 compared with $0.29 in 2018. Fourth quarter earnings were $0.12 per share in 2019 compared with $0.14 in 2018. For the full year, higher revenues were largely offset with higher operations and maintenance costs, depreciation, higher property tax and interest expense. The fourth quarter decline was due to higher O&M and depreciation expense as well as the absence in 2019 of a benefit that we received in 2018 related to our Yankee rate case. Full year earnings from our water distribution segment totaled $0.11 per share in 2019 compared with $0.10 per share in 2018. Fourth quarter earnings in our water distribution business were $0.02 per share in 2019 that's up $0.01 over 2018. Improved results for the quarter were due in part to higher revenues lower interest and operating expense At the parent and others we earned $0.02 per share in 2019 compared with earnings of $0.08 per share in 2018. The decline incurred largely in the fourth quarter when the parent lost $0.02 per share compared with earnings of $0.03 per share in 2018. This was due in part to $0.02 per share gain in 2018 relating to the results of a regulatory decision allowing recovery of certain merger-related costs by Yankee Gas. It also resulted from a higher effective tax rate in 2019 than we had in 2018. Turning to slide 14. Our earnings per share guidance for 2020 is the range of $3.60 to $3.70 per share and this is consistent with our long-term growth rate expectations. The primary drivers of earnings growth are expected to be our continued investment in our transmission system and the positive impacts of our multiyear regulatory plans in place for our electric and natural gas distribution businesses. In the first half of this year, we are implementing an electric distribution base rate adjustments totaling more than $60 million and a natural gas rate adjustment of nearly $16 million. Additionally, I will discuss shortly, we have rate requests pending at one of our electric subsidiaries in one of our natural gas distribution companies. Also contributing to earnings growth would be the impact of infrastructure investment tracking mechanisms in place for our electric and natural gas distribution segments. These involve safety programs in pipe replacements in our gas business. Offsetting these benefits are expected increases in depreciation, interest cost and property tax expense. Also we'll have a higher share count in 2020 as a result of the equity sale last June and closing it out with the full width by the end of May of this year. From 2020, I'll turn to slide 15 and our long-term capital investment forecast. Over the next five years, we are projecting capital investments of $14.2 billion from our core electric natural gas and water business as well as the supporting information technology and facilities investments. These investments are focused on providing reliable service to our 4 million customers across three states. In our electric transmission segment, we expect to invest approximately $4 billion over the next five years. As a result, by the end of 2023, we expect our regulated transmission rate base to be $9.4 billion. That's approximately $1 billion higher than we had estimated just a year ago. And then we expect the rate base to be at $9.6 billion by the end of the forecast period in 2024. Turning to slide 16. You can see that in just the years 2020 through 2023, our capital investments are expected to be $1.6 billion higher in those time periods than what we had forecast at this time a year ago. This increase is primarily driven by investments in our electric transmission segment. For the years, 2020 through 2023, capital investments in electric transmission are expected to increase by about $1 billion. We have multiple drivers affecting this increased level of spending and they're all related to providing reliable service in supporting our region's clean energy goals. For example, we're increasing the use of drones to better inspect our transmission equipment. High-resolution drone photography is allowing us to identify damage of failing equipment much more effectively and efficiently allowing us to accelerate the replacement of at-risk equipment, before it can cause reliability problems for our customers. In addition to replacing older equipment, we also need to address some notable areas of growth. While overall our electric loads are flat to lower, we are installing additional equipment to address significant customer growth, particularly in pockets of Boston and Cambridge, Southwest, Connecticut and Coastal New Hampshire. We also need to add equipment to better integrate the renewable energy that continues to come online to maintain voltage and reactive capacity. On the electric distribution side, we project investments of approximately $6.1 billion over the next five years. From 2020 through 2023, we project nearly an additional $400 million investment compared to last year's forecast. Our investments are helping to drive the excellent top-tier reliability performance that Jim identified earlier by improving the resiliency and reliability on our systems addressing continued economic growth and at the same time helping to drive our O&M costs out of the system. Much of the increase in our distribution capital program since last year's forecast is driven by substation investments in the growth regions that I mentioned earlier such as Greater Boston. We also continue to invest in the DPU-approved grid modernization program in Massachusetts. You may recall that in late 2017 and in the first half of 2018, the DPU approved $233 million of investments, including $55 million for two battery storage projects, $45 million for electric vehicle infrastructure that connects 3,500 charging points and an additional $133 million for technology enhancements on our distribution system. We had initially expected these investments would be completed over a five-year period but we now expect nearly all the work to be complete in a 3.5-year or less period or by early to mid-2021. Additionally in 2018, the DPU instructed us to file an additional three-year plan by mid-2020 to cover the years 2021 through 2023. In our capital investment forecast, we have included approximately $290 million for that new three-year plan in Massachusetts. There are a few changes in the natural gas and water distribution segments where capital investments more closely resembles the plan we showed you a year ago. The increased investment in our natural gas distribution system during the years 2020 to 2023 is primarily at NSTAR Gas where we have a number of additional resiliency projects plus continued execution of our pipe replacement program. And we have similar work underway at Yankee Gas. At Aquarion on slide 17, we provided you with an updated Aquarion rate base estimate that now reflects the expected sale of certain water facilities around Hingham Massachusetts to the town. We expect the sale to close in the second half of this year and we expect to receive more than $100 million for these facilities, a valuation that was prescribed following a State Court review. More than 90% of Aquarion Water's rate base is located in Connecticut and much of the capital investment over the coming years will come not only from replacing older less reliable pipes but also from new projects that bring additional water supplies into Southwest Fairfield County where currently summertime irrigation is precious. More specifics about that extensive work are shown on the slide in the appendix. From what is included in our capital forecast, let's turn to slide 18 and discuss some of the items that are not reflected in the forecast. On the electric distribution side, the forecast does not include grid modernization investments in Connecticut or New Hampshire. Connecticut regulators have opened a number of dockets related to grid modernization such as storage and electric vehicle charging infrastructure and are pursuing them aggressively with regular public input sessions. But because those dockets are not yet complete, we have not included any such investments in our plan. Similarly while we have proposed several innovative grid initiatives in New Hampshire, including battery storage project as these initiatives are not yet approved, we have not included any of these investments in our current plans either. We are not reflecting any investment in advanced meter infrastructure or AMI in any state. In Connecticut, there is an active AMI docket now underway as part of its grid modernization review. Massachusetts regulators have indicated that they will open the review of AMI in other customer-facing technologies, although no specific time-frame has been established at this time. We currently estimate the total investment needed to switch over all of our electric and natural gas customers to AMI in the two states, Connecticut and Massachusetts to be approximately $1 billion. But it's unclear at this time if or when AMI might be authorized by regulators. We are also evaluating a recent report issued by Dynamic Risk Assessment Systems, the consultants working for Massachusetts DPU to determine if we will need to make any incremental capital expenditures on our Massachusetts gas distribution system. These investments would be needed to meet evolving state safety requirements. No additional investments have been included or have been identified or included at this time in our forecast. As you can see on slide 19, the level of investment in our plan will produce a rate base CAGR of 6.9% nearly 7% from year-end 2018 through 2024. This rate base growth underscores our high confidence in the core business producing an EPS CAGR of 5% to 7% and as we've said in the past, we believe we will be somewhere around the middle of that range. Earnings from our major offshore wind investments will be incremental to the core business 5% to 7% CAGR. In years when we are not adding any offshore wind, we expect to be solidly in the 5% to 7% range. As Jim said in periods immediately after we bring a large offshore wind project into service, earnings growth is likely to be significantly above the 5% to 7% range. We expect those high-growth periods to be the 12 months after first Revolution Wind and then Sunrise Wind into service. As you know for competitive reasons and because we're still early in the siting process, we have not discussed our expected total investment in these projects. So I will say that we are expecting to invest $300 million to $400 million in the offshore wind business in the year 2020. As we've previously said, we expect to capitalize the projects with a 40% to 45% equity and 55% to 60% debt percentage. That's consistent with our current Eversource capitalization. And as we've said, we continue to expect to earn mid-teens returns on the equity in these projects once operational. As noted on slide 20, core business earnings growth is not just tied to rate base growth in the associated CWIP there are other items. First, some of the regulated segments particularly Massachusetts and New Hampshire distribution earned below their authorized returns in 2018 and we are expecting a significant recovery from these levels going forward. Second, as our highly regarded energy efficiency programs grow so do potential incentives we receive for doing an exceptional job. Third, we are conservatively modeling nominal O&M to be relatively flat during the five year forecast period compared with 2019 levels. The bottom-line is we're very comfortable that our regulated segments alone will support the 5% to 7% earnings growth and again somewhere in the middle of that range. From our growth rate I'll turn to two active rate cases one in New Hampshire, a public service in New Hampshire; and in Massachusetts at NSTAR Gas. Slide 21 shows the status of these rate cases. On the left-hand side you'll see that PSNH filed a rate case last year seeking a $70 million increase in base distribution rates. Following the settlement with the staff the New Hampshire Public Utility Commission approved a $28 million temporary increase that will remain in effect until the PUC implements a final decision on the permanent rates. We expect that decision in May with an effective date July 1. The New Hampshire PUC process includes a number of days devoted to settlement discussions and the scheduled targets April 7 for the filing of the settlement if we're able to negotiate one. Regardless hearings will take place in April and historically most New Hampshire rate cases have been settled. At NSTAR Gas we filed an application in November of last year to raise distribution rates by $38 million effective October 1, 2020. We also requested a performance-based rate mechanism similar to the one approved for NSTAR Electric in its rate case in late 2017. Such a mechanism would tie rate adjustments in the future to inflation measures in years two through five of a five year plan. We expect this rate case to be fully litigated as was the NSTAR Electric case. Worth noting is that our three largest distribution franchises are currently under multiyear rate plans and we anticipate no new base rate plans for these franchises to be effective before 2022. Turning from the states to the FERC information on slide 22. There's been significant FERC ROE activity since our November earnings call but none of it directly related to our four pending complaints against the ROEs identified by the New England transmission owners. In a recent decision that was quite disappointing to us FERC ruled in November of 2019 that it would abandon two of the four methodologies it had earlier suggested it would use in determining just and reasonable ROEs. Instead it said it would focus solely on discounted cash flow and CAPM mechanisms. Many parties requested reconsideration of that ruling and FERC appears to be considering reviewing its decision in that MISO case. In the meantime, we continue to book earnings at the same rate at which FERC has ordered us to bill customers. That includes a base ROE of 10.57% with a project cap of 11.74%. We have billed at the same rate since early 2015 and do not expect to change it from FERC rules on the New England case. Turning to slide 23. I'll review the status of our equity issuance. As you may recall we closed immediately on one-third of nearly 18 million shares that were issued and sold in June of 2019. So the issuance at that time was just under six million shares. The remaining nearly 12 million shares was subject to a forward share purchase arrangement. On December 30 we closed on an additional six million shares of the forward and we'll close out the remaining approximately six million shares by the end of May of 2020. Also last year, we used about one million treasury shares to fund our dividend reinvestment and certain employee incentive and retirement plan obligations. We had expected to issue about 1.5 million shares last year. But because of our higher share price we've reduced that rate of issuance. Later in the forecast period, we expect to implement an at-the-market program to address any equity requirements that exist. At this time, we expect to issue approximately $700 million in new equity. This is the same number that we've discussed for over a year now through such mechanism during the forecast period. We'll continue to evaluate our financing needs as we move through the forecast period but we have no additional equity in the forecast. We're very enthused and confident we'll be able to accomplish this ambitious plan we described you this morning. The plan will allow us to fulfill our work on behalf of our customers while supporting energy policies of our states which they've adopted. Slide 24 illustrates some of our track records and it illustrates the targets we've set for ourselves over the past eight years and how we've been successful in meeting or beating them, delivering significant benefits to our customers and value to our investors. Thanks again for your time. I'll turn the call back to Jeff.

Thank you, Phil and I'm going to turn the call back to Paulette to remind you how to enter the Q&A.

Thank you, Paulette. Our first question this morning is from Mike Weinstein from Credit Suisse. Good morning Mike.

Hi, good morning. Thanks for taking my call. Can you explain why you think the bids are coming in so low for Massachusetts offshore wind auctions? What gives you confidence that you can win further auctions if the bids are low?

Sure. This is Jim. Hi Mike. We can’t quite understand some of the pricing that other bidders have submitted. Clearly, their expected returns are lower, which might indicate they are trying to gain market share. However, as we discuss this, Ørsted and Eversource's joint venture stands as the largest developer of offshore wind in North America, with 1,714 megawatts contracted. We view the situation positively. We have secured profitable bids and will remain selective in our opportunities. Massachusetts appears to be mainly focused on price, unlike other states that are considering additional contributions to the state, such as economic development. There are now over 25,000 megawatts of offshore wind planned in the Northeast, with 15,000 megawatts coming from New York, Connecticut, Massachusetts, and Rhode Island, but we have only contracted for about a third of that. We are excited about the prospects and our timing is aligned with our financial discipline to ensure we secure profitable bids.

Got you. Thanks. And also do you expect to continue excluding offshore wind earnings from forward earnings growth projections and future updates or do you think you might raise the guidance range at some point maybe next year?

Mike this is Phil. Our current plan is to have our core business growth rate and keep it separate at this stage.

Got you. One last question here. Can you explain how offshore wind will be affected by the PTC extension? I think initially that was supposed to apply only to onshore projects, but I understand there are some ways that they can be applied to offshore. Maybe you can explain that a little bit?

Hey Mike, it's Jay Buth. How are you? When we consider everything collectively regarding the portfolio, we interpret that language positively. Conversations with some of our advisers suggest that the potential for the PTC extension could benefit our offshore wind business. We are also exploring other strategies from a qualification perspective. Therefore, we feel quite confident about our qualification areas.

Got you. I'll get back in the queue. Thank you very much.

All right. Thanks Mike. Next question is from Insoo Kim from Goldman. Good morning Insoo.

Good morning. Thank you. First regarding financing, how much of the Sunrise Wind construction costs are you assuming would be funded by the initial cash flows from Revolution Wind? And depending on the timing of the permitting and potential delays, at what point would your future equity needs change and the potential magnitude of that?

I would say we're confident in our schedule and believe we can finance our construction programs for both our core business and wind development with our cash flows. These cash flows are interchangeable. There are revenues from our core business, and we'll generate cash from revenues or tax benefits from the offshore wind, which will help finance our entire capital portfolio. Right now, based on our forecast, we have no new equity needs beyond what we've already indicated in the past, and we are confident we can achieve that.

Understood. And maybe a little bit bigger picture Jim. Obviously, Eversource has benefited from its favorable ESG characteristics, including the strategy on offshore wind. When you just look out longer-term, your portfolio mix, could you just update us a little bit on your thoughts on what the optimal mix is? Whether it's on the offshore renewable front or on the water utilities front or anything else that you may be contemplating?

We are quite satisfied with our core business and are recognized as strong operators in electric, gas, and water sectors. We have taken advantage of opportunities in developing utility-scale solar and see offshore wind as a growing opportunity. Although we do not have a specific target mix for each sector, I believe the water sector has potential for consolidation. However, current high valuations for water utilities make it challenging to find deals that meet our criteria for being accretive. We will continue to seek opportunities for business growth while being selective and disciplined, and we are pleased with all aspects of our operations.

Right. Thank you very much.

Great.

Thanks, Insoo. Next question is from Steve Fleishman from Wolfe. Good morning, Steve.

Good morning. I have a couple of questions about offshore wind. Can you provide some insight into the timing delays and the overall impact from BOEM? Additionally, I've heard there might be some opposition to the mile-by-mile configuration. What are your thoughts on getting that approved? Finally, how confident are you in the cost assumptions you've outlined for your projects, considering the current situation with construction costs and any delays?

Okay. Jeff, please keep me honest with the questions. Regarding offshore wind, one thing we are pleased to see is the level of granularity provided by BOEM with the timelines issued during the Vineyard Wind proceeding up to the record of decision date. People understand that delays with Vineyard Wind might affect other projects, although we hope that impact is minimal. The cumulative impact analysis expected on June 12 will offer guidance for future schedules. Eversource and Ørsted submitted comprehensive and high-quality corporate filings for South Fork, which should help speed up our approval once BOEM finishes their cumulative impact analysis. Regarding the mile-by-mile configuration, while there may still be some opposition, there has formed a coalition in support of it. The Coast Guard endorses it, believing it allows sufficient space for safe navigation and fishing activities. This solution addresses the main concerns BOEM had when they paused the Vineyard Wind process. On the cost assumptions front, we consistently evaluate project construction costs, timelines, and potential improvements. I am confident in our partner Ørsted, as their track record demonstrates a prudent approach with appropriate conservatisms and contingencies. We are continuously assessing these cost assumptions and currently feel aligned with the mid-teen returns on equity we have communicated to investors.

Okay. Great. Thank you.

Thanks Steve. Next question is from Paul Patterson from Glenrock. Good morning, Paul.

Hey, good morning guys. How are you doing?

All right.

I wanted to just touch base again on slide 19 and the CWIP number. How do you guys expect that to go? What's your trend expectation with respect to that over this forecast period?

In terms of the CWIP number, Paul? Yeah, typically that would move up during the forecast period just given our level of construction activities. I don't have a specific rate of increase that I would give you. But I would say that, we would see that number as increasing during that period.

Okay. And then regarding offshore wind, there was an independent evaluator report released on Friday discussing the potential for the Mayflower project to be rebid, which could present an opportunity for you. I was wondering if you have any thoughts on that potential.

Well I can't speculate. I think I did see something that suggested that the winning bid was close to the second bid. And some people are making a case that, that winning bid may be a higher risk and should be reassessed. But I don't have any perspective or insight as to what will be done with that.

Okay. Regarding transmission, several dockets have been filed at FERC related to ISO New England and competition. Various cases appear to stem from FERC Order 1000, which seems focused on compliance and cost containment efforts. I am curious about your views on FERC's apparent initiative to expand or reinforce competitive efforts concerning transmission projects.

I think we've seen ISO respond. They issued an RFP in December to address transmission needs due to the retirements of Mystic 8 and 9. It's expected sometime in 2024, and there's a schedule for a competitive bid to be submitted in March. Eversource and National Grid will be required to propose backstop solutions that qualified business developers can bid on. There is competition in New England concerning major projects that are at stake.

Right. They are discussing immediate needs and supplemental projects. Should we consider Mystic 1 as a reference point for understanding how this competition unfolds? I am also curious if you believe this could affect your forecast regarding transmission investments and related aspects.

I don't think so. I believe that some of the reliability concerns mentioned regarding structure replacements have been identified, and more vulnerabilities were discovered using drones. With the federal government's emphasis on reliability in the transmission system, I think the incumbents will continue to be the ones to address the necessary near-term fixes or upgrades required by the system.

Okay. Regarding the grid modifications in Connecticut that Phil mentioned, I apologize if I missed it, but when can we expect to see some outcomes from that? As you pointed out, there are several proceedings happening, making it quite challenging to keep track. When do you think we might actually see some concrete proposals or similar developments emerging from that?

Yes, Paul, you're correct. There are currently 11 different active dockets, and the process in Connecticut has been inclusive and has adhered to its schedule. They have been proactive in addressing various topics. However, I don't have a specific target date, as none has been published yet. We anticipate some progress in the first half of 2020. As I've mentioned before, I don't expect all 11 items to be released at once; it's more likely that we will see one or two of them make advancements in the first half of this year, but I don't have further details on that. The focus seems to be on battery storage and electric vehicles, which we already have programs for in Massachusetts, and these are currently prioritized in Connecticut.

Okay fair enough. Thanks so much.

Thank you, Paul.

Our next question is from Julien Dumoulin-Smith from Bank of America Merrill Lynch.

Hey good morning team congratulations.

So perhaps to keep going a little bit in the same direction this fall here. But turning back to slide 18 talking a little bit and trying to quantify if you will some of these upsides. I know you said specifically AMI was $1 billion still that seems unchanged. Can you talk about a: the time line if there are any kind of data points we should be tracking? And then separately for the other two bullets here, I know it's difficult to put your finger on any kind of specific numbers. But as you begin to assess the quantum overall of capital here, how would you frame those other two? I get it's difficult, but at least initially especially on the Massachusetts gas side where I know that there are some data points coming up here. Yes, Julien, this is Phil. Following Paul's comment, one of the items relates to AMI in Connecticut, where there appears to be growing interest. One of the utilities in the state has already implemented a partial AMI solution. In Massachusetts and Connecticut, we estimate the investment could reach about $1 billion, likely spread over four to five years and not happening all at once. Connecticut seems to be ahead of Massachusetts because there is an existing docket and framework to begin discussions. We might see developments in 2020 for Connecticut. In Massachusetts, they have expressed interest in establishing a broader docket for AMI and other customer-related topics, but no date has been set yet. It's uncertain if there are plans in place, but it’s expected to kick off this year. Realistically, half of our customers are split between the two states, suggesting that about $500 million is attributable to each state. Regarding gas assessments, we've been asked to prepare information in response to that assessment, and we expect to have updates soon on potential incremental spending. Additionally, in our gas filings in Massachusetts, we anticipated this scenario. While we were unsure about the precise spending amounts, we included a provision in our proposal to account for unknown future expenses, meaning we won't have to wait years to seek recovery. We've proactively set up a mechanism for this potential spending. As you pointed out, it's a bit early to make predictions, but there could be several hundred million dollars in incremental costs across these items.

Got it. I want to delve a bit deeper into a specific point regarding fuel security. I know you've discussed Mystic broadly, but this issue seems to highlight some potential challenges. We noticed some recent actions from FERC. Is this another aspect we've touched on? I'm curious about your thoughts on the Boston area and more generally when considering the winter ahead.

Yes. I'm not really sure what you're asking about.

So what I was getting after is obviously, if Mystic eight and nine go away and in general you have this open question as to enabling the retirements of these urban large-generation sources. Are there opportunities that open themselves and afford themselves sort of in the here-now to backstop or enable these retirements otherwise?

I think this is Jim, Julien. The competitive FERC 1,000 solicitation will reveal a number of opportunities created to address the challenge of Mystic eight and nine going away. I don't want to speculate on what they might be. We'll see soon enough.

Okay. All right, fair enough. It comes back to that. Understood indeed. Thank you.

Great, thanks so much Julien. Next question is from Travis Miller from Morningstar. Good morning Travis.

Good morning. Thank you. I'm curious about the potential for growth in transmission as we look toward 2023 and 2024. Can you explain the key factors that might be hindering progress? Are there any changes in policy, FERC, or state regulations that could influence the additional growth projects not currently included in the forecast?

Well, I'll have Phil add on. But one observation I'd make Travis is that Jeff Kotkin is the best IR guy in our industry and that's not me saying that that's all you folks on the phone saying that because he wins the II award every year. And one of the reasons he does is he provides a lot of regularity on our capital spending plans going forward. And there's a long history here of providing a CapEx forecast and he provides it based upon projects that are already in the queue that we're aware of that are in our plan. Obviously, we know more about projects that are in our plan for 2020 than we do for 2025 right now. And so if you look every single year since the merger in 2012, we have updated the CapEx forecast going forward and it has increased and it's – basically because we're more aware of future needs going forward. So there are projects that are out there that we're not aware of right now that will be in the mix. And that's not just transmission but distribution electric and gas and water business as well. I don't know if you want to add to that Phil?

Yes, I'd just add in terms of a couple of categories is I talked about connecting distributed resources to the system. I think we have about 2600 distributed – megawatts of distributed energy resources in our territory now. So as policies progress and as clean energy connections are required. I think that could be a category that expands in that time period. So nothing to put in there yet, but that's certainly a driver. And each year we're spending more on cyber and physical security and things like that so that the ramp-up in that particular category seems to get higher and higher each year. So those might be a couple of categories that could move spending up as you move out in the forecast.

Okay. And then just within that are there any large project opportunities that you see – as you look out kind of that five-year trends I think on transmission window. Are there any areas where you'd see hey, this could be a possible large project opportunity, let's call it $400 million $500 million type of thing?

Yes. Right. Actually just the opposite. I'd say our forecast now includes more smaller projects that are more bite-size inside the fence. As I said cyber is certainly an issue. I'd say the largest single project that we have now is our Seacoast Reliability Project that we have as a single project. All the other – transmission is really groups of smaller activities that we're doing for reliability and to improve the reliability for our customers. So we don't see any big projects out there.

Okay, great. I appreciate the thoughts.

Thank you, Travis. Next question is from Andy Levi from ExodusPoint. Good morning, Andy.

Hey, guys. How are you?

Good Andy. How are you?

Thank you, Andy.

So just I guess a follow-up from an earlier question. You were – I know this is something that you had commented on Jimmy. So just on the spacing relative to the offshore wind. When do you guys find out what the final outcome of that spacing is? I guess we're what one mile by one mile now is – or is that...

Yes, one mile is – and fortunately we were the first ones to agree to go to that design a while ago. And so we're probably further along than others in terms of development of COPs that need to be filed with the BOEM. Again it's to accommodate the shipping and Coast Guard and fishing interests. The – we do believe the Coast Guard agrees that it's adequate to address the concerns that they had initially. And we think that will weigh in on BOEM's decision when they evaluate the cumulative impact. All the developers have agreed to the same format that Eversource and Ørsted have committed to earlier. So we'll see how addresses the concerns or questions that BOEM may have and we'll know about that on June 11 or 12.

Okay. So in mid-June we'll get the idea of what the final spacing is, or will that be in December?

I think June will give you – the expectation is that we'll get a draft – yes from BOEM that will address the cumulative impact of these six leases and provides standards for us to use going forward. That draft EIS ultimately will be finalized by the end of 2020. I think the date that was published through the Vineyard Wind decision was a record of decision December 18, 2020. So June 12 for the draft and December 18 for the final.

Okay. Earlier this month, Ørsted was in New York. Currently, the spacing is one mile by one mile. If the spacing were to increase, like to 1.25 miles, at what point does the spacing become too wide, making it less economical to invest in building a factory or related infrastructure on land? How does this affect the long-term growth potential of the acreage you have?

Yeah. I think as I said, the one-by-one should be adequate. One of the mitigating factors, Andy is that, when we began this process. And we talked about 4,000 megawatts we were looking at a technology that was 8-megawatt turbines. And now we're seeing that Ørsted is actually testing here in Massachusetts, some of the 12-megawatt turbines. So, we were forced to have two holes in the water, if you will. It may very well be that it doesn't have larger turbines on them, which would obviously, positively impact the economics. So, right now, we don't anticipate any need beyond the one-by-one. But we continue to believe that, that will be adequate to provide us the financial results, that we're targeting in.

But anything over the one by-one, kind of changes everything?

So, I don't know, what changes everything. But we'd certainly evaluate it. I haven't heard anybody propose, something beyond the one-by-one, other than the discussions about shipping lanes also being...

The corridors and things like that?

Yeah. Yeah.

Okay. So I guess we still have to monitor it. But it does seem that to be the biggest concern that Ørsted had, in kind of the entire process. But I should have this down at lunch so. Okay, thank you guys.

Okay. That's all right. Thanks, Andy. Next question is from Andrew Weisel from Scotia. Good morning, Andrew.

Hey, Good morning everyone. A lot of it is already covered of course, but just a quick one on the offshore wind. If we do see some slippage, in the in-service dates related to BOEM or whatever. Do you have a quick and dirty rule of thumb of what, a 1-year delay, would have on earned returns relative to your expectation of mid-teens, whether that's tax credits or more broadly?

No. I don't think it sort of reduces our returns. It basically will just delay them. We have factored into our purchase power agreement, flexibility for delays, especially if they're created by regulatory approvals. So, we don't anticipate, major financial consequences of it, although if further delays occur, the earnings profile would shift out from what we're currently planning for 2020 to 2025.

Got it, okay. And then just lastly on, O&M. Obviously, you're guiding to flat through the forecast period. Would that be flattish in each year, including 2020, or is there any lumpiness or gradual trajectory?

It should be consistent throughout the forecast period, Andrew. No particular lumpiness.

Okay. So 2020, should be flat with 2019, then?

Yeah. Modestly flat, I'd say. In 2019, we had, I think, one of the drivers of O&M being up was really kind of a higher level of storms, than we had had the previous year. So, I know you've heard that from other people. Storms sometimes could create lumpiness. But we're not expecting any other known items to be lumpy, during that time period.

Got it. Thank you very much.

All right, thanks Andrew.

Next question we have from Mike Weinstein from Credit Suisse.

Hi guys. With all the offshore talk I thought I'd switch over to the other water, for a minute. You've owned Aquarion, now for a few years. Can you describe how operating and planning of water system has been more or less difficult, than the electric and gas systems, that you would have? I remember at the time you were the first electric utility and really to buy a water company? And there was, questions about whether that would be easier or more difficult. And then, also now that you have some experience, but you consider looking beyond New England for further water investments, at some point. I know that in the past you haven't but now that you have experience, would you maybe reconsider that?

I would say that the water business we've had for a short period has met or exceeded our expectations. We committed to it being accretive to earnings in the first year, and although it's a very small business, it delivered on that promise. Their earnings grew in the second year. There is a roll-up strategy within towns, and over the last several years, we've integrated 70 or 71 small water entities. However, it doesn't significantly impact us since there are over 50,000 water entities in the country, making consolidation challenging. Additionally, the pricing is very high, making it tough to justify the premiums required for consolidation. We have, however, expanded our footprint. I started many years ago in Boston-Edison, and we did well in Massachusetts. After creating Eversource, we expanded into Connecticut and New Hampshire and have managed to accelerate our operational and financial results beyond Massachusetts. Now we are entering New York with offshore wind projects and have seen some success there. We are increasingly open to moving outside our traditional footprint, which may lead us to expand our water business further.

Thank you.

All right, thanks Mike. That was the last question in the queue. So we want to thank you all very much, for your time today. If you've got any follow-up questions, please give us a call.