Eversource Energy (ES) — Q4 2018 Earnings Call Transcript

Thank you, Brendon. 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 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 U.S. Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on management's current expectations and are subject to risk 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, 2017, and on Form 10-Q for the three months ended September 30, 2018. 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. As you can see on slide 2, 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 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 Jay Buth, our VP and Controller. Now I will turn to slide 4 and turn over the call to Jim Judge.

Thank you, Jeff. And thank you everyone for joining us this morning. I am happy, very pleased to discuss our successful performance in 2018 and the very strong future we see for Eversource. Our 8,000 talented and dedicated employees undertake their work every day to improve the experiences of our customers, support our approximately 500 communities and execute the forward-looking clean energy policies of our state. And doing so, we've created a solid, very long track record of delivering significant value to our shareholders and managing the risks of our business effectively. A regulated business cannot be successful without positive relationships with its regulators. We firmly believe that our success in achieving top-tier reliability and safety performance, combined with our success in reducing our O&M cost by more than 20% since 2012, enables us to create constructive regulatory frameworks that are fair to both customers and investors. As you can see on slide 4, we settled two major distribution rate cases in Connecticut in 2018: one for our electric business and one for our natural gas business. The Connecticut Light and Power settlement was the first electric rate case settlement in Connecticut since 1986 and underscores the level of trust and transparency that we have developed with other parties. Less than seven months after the three-year CL&P settlement went into effect, we implemented a separate three-year rate settlement through Yankee Gas. Both CL&P and Yankee Gas settlements provide us with forward-looking rate mechanisms that allow us to step up our investments in our infrastructure to better serve our customers without suffering the earnings consequences of rate lag. In 2018, we also moved ahead with some of our strategic initiatives to support a relentless focus on sustainability and greenhouse gas reduction. In addition to the divestiture of our costly units, we successfully completed the build-out of 62 megawatts of solar in Massachusetts, with the solar investments totaling approximately $170 billion. Additionally, we began implementing separate initiatives in Massachusetts to invest a total of $233 million in battery storage, electric vehicle infrastructure and other grid modernization projects. They also support Massachusetts state energy policy, and by the middle of next year, we will compile a new plan for the next three-year cycle beginning with 2021. Our progress in these areas is being recognized. Various ESG rating groups consistently rank Eversource near the very top of their rating scales, and we now have more than 130 separate socially responsible funds that have invested in our company. We have achieved strong returns for our shareholders, while managing our risk profile. Across the board, our credit ratings remain very strong, among the highest in the industry. Turning to slide 5, you can see that our total return continues to outperform both the utility index and the broad market from a short-term and long-term basis. While past performance is no guarantee of future returns, it can be a good indicator. Past performance does validate our contention that a company that excels in its service to customers can also excel in delivering value to shareholders. Turning to slide 6, you can see that dividend growth remains a central feature of our total return profile. On February 6th, our board of trustees approved a $0.12 annualized increase in our common dividend. The 6% increase is consistent with the midpoint of a 5% to 7% long-term growth rate and exceeds the average dividend growth in our industry. As you can see on slide 7, we continue to forecast growth of 5% to 7% long-term, a continuation of what we have delivered since our merger closed in 2012. The forecast that Phil will discuss with you shortly extends five years through 2023. That’s a two-year extension to our prior guidance that only went through 2021. As you expect, we continue to plan for even longer-term growth. As you can see on slide 8, we made the announcement earlier this month that we believe will have a very positive impact on our results well into the next decade. On February 8th, we announced the purchase of a 50% share of similar projects and offshore wind energy leases that Ørsted acquired when it bought Peak Water Wind late last year. Our latest transaction builds upon the partnership we first developed with Ørsted in 2016 when we acquired a 50% interest in Bay State Wind. This month’s announcement relates to leases for more than 250 square miles of ocean off the Massachusetts coast that are adjacent to the 300 square mile Bay State lease that we jointly own. These lease areas are among the best sites for offshore wind in the entire United States and they're in a prime location to meet the growing appetite for offshore wind in New England and New York. Together, the Bay State Wind and Deepwater Wind sites could host at least 4,000 megawatts, which we share the partnership 50:50 with Ørsted, the world's largest, most successful, and most experienced developer of offshore wind. The Deepwater portfolio in which we now have a 50% share includes contracts for about 830 megawatts of offshore wind that will be sold to utilities in Connecticut, Rhode Island and New York. The 830 megawatts represent the largest concentration of offshore wind contracts currently awarded in North America. These projects still must go through the signing process and will have very limited impact on our earnings growth through 2023. However, beginning in 2024, we expect that investment to be a significant source of earnings for Eversource. Those 830 megawatts are likely just the beginning. Last week, we bid into a New York offshore RFP that is expected to be awarded this spring, and later this year, we expect to bid into the second Massachusetts offshore wind RFP where the state seeks another 400 to 800 megawatts of clean generation. All told, New England and New York have announced targets or adopted legislation that could result in the development of up to 15,000 megawatts of offshore wind by the year 2035. We will have more to say about the expected potential impact of this announcement; however, I want to underscore how pleased we are with this transaction, how pleased we are with our partner Ørsted and the opportunity to bring a significant source of locally produced clean energy to our region. A major factor in our decision to expand our relationship with Ørsted is our partner's unequaled global experience and track record of delivering offshore wind projects on time and on budget. Ørsted has more than a 25% worldwide market share, much larger than its nearest competitor. Of the seven projects Ørsted recently completed, six were under budget that was set when the final investment decision was made. This fact, combined with Ørsted's record of completing projects on schedule, has allowed the company to consistently deliver on its return expectations. Ørsted also shares our philosophy of being a disciplined bidder and will not sacrifice returns to win business. While we don't expect to win every offshore wind RFP, we fully expect that our successful bids will achieve a level of profitability commensurate with the project risk. We believe we are the largest energy company and the largest developer of energy infrastructure in our region. Collectively, New England has very ambitious greenhouse gas reduction targets seeking to reduce emissions by 80% by the year 2050. New York has established aggressive renewable targets as well. Offshore wind will be central to meeting this region's carbon reduction and renewable development goals, and through this partnership, we're quite pleased to play a leading role in executing the region's energy policies. We are also pleased with the long-term earnings growth opportunities these investments will provide to our shareholders. Now I'll turn the call over to Phil.

Thank you, Jim. My portion of the call will cover the 2018 results, an update on our key regulatory dockets, a look at 2019 guidance, our new five-year financial forecast, and a discussion about financing plans during that forecast period. As Jim said, we had a strong 2018 from both an earnings and operational perspective. Beginning with slide 10, we earned $3.25 per share for the full year compared with $3.11 in 2017. A year ago we projected earnings of between $3.20 per share and $3.30, so we're right in line with that projection. Our electric distribution segments earned $1.44 per share in 2018 compared with earnings of $1.57 in 2017. The decrease was primarily due to low generation earnings as a result of the divestiture of our New Hampshire generating unit assets. Higher revenues were offset by increases in depreciation, interest, and property tax expenses. Our Electric Transmission segment earned $1.34 per share in 2018 compared with $1.23 in 2017. Improved results primarily reflect our increased investments in that business. Our Natural Gas Distribution business earned $0.29 per share in 2018 compared with $0.23 in 2017. The increase was primarily due to higher revenues at our Yankee Gas Connecticut property, which would not decouple until late in the year, as well as the outcome of a Yankee Gas rate review and the increased revenues related to our capital investment tracker mechanisms. On the Water Distribution segment, we earned $0.10 per share in 2018 and we acquired Aquarion in December, so no 2017 results to report there. Eversource parent and other earned $0.08 per share in 2018, including two non-recurring items that we discussed in the third quarter. The $0.08 per share write-off of our investment in Access Northeast and a $0.06 gain from various tax reform items. I know that a number of analysts may or may not have adjusted their estimates accordingly for these events. Fourth quarter 2018 earnings totaled $0.73 per share compared with $0.75 in the fourth quarter of 2017. Transmission earnings were down $0.01 compared with the fourth quarter of 2017 primarily due to a higher effective tax rate in that business in 2018, which cost us about $0.03 per share. Electric distribution was up by $0.09 per share in the fourth quarter due in part to the absence of generation earnings due to the divestiture, as well as higher depreciation, interest, and storm damage restoration costs. Conversely, our Natural Gas Distribution segment earnings were up by $0.06 per share in the quarter benefiting from capital tracker mechanisms, cooler weather and some increased revenues stemming from the Yankee Gas rate decision. We also had a $0.01 per share in the fourth quarter of 2018 from our water business. Slide 11 summarizes the constructive resolution of our three distribution rate reviews in 2018 for Connecticut Light and Power, Yankee Gas, and Aquarion in Massachusetts. We expect far less state rate activity in 2019, though for the first time in nearly a decade, we expect to file a general rate review in New Hampshire. Public service in New Hampshire is under-earning and its allowed ROE is 9.67% despite significant cost management success across that business since 2012. In New Hampshire, rate reviews take about a year to complete, but utilities have the opportunity to request interim rate increases subject to refund if they expect to under-earn their previously authorized ROEs while the rate review is pending. As a result, we are planning to file for interim rate relief in New Hampshire in April and a full rate review in May of this year. The next area to cover is FERC. This past fall, I'm sure you know, FERC issued a proposed new methodology for determining whether it should initiate new proceedings concerning transmission ROEs, and if so, what methodology should be used to decide on them. As you can see on slide 12, there are still four complaints pending against the ROEs earned by the New England electric transmission owners of which we have lagged. Initial briefs on the FERC methodology were filed in January with reply briefs due in a couple of weeks. We're hopeful that in 2019 this long-running dispute will be resolved by FERC, and that FERC endorses standards that in the future will make this type of serial complaints we've had in New England highly unlikely. From 2018 now I'd like to turn to slide 13 and discuss our 2019 guidance. We expect to earn between $3.40 and $3.50 per share in 2019. As you can see on the slide, we expect to benefit from our multiyear rate review outcomes in 2018 from our Massachusetts electric jurisdictions and our Connecticut electric and natural gas utilities. NSTAR Electric implemented roughly $32 million increase in base distribution rates on January 1st of 2019 as part of its five-year performance-based rate plan approved by the Massachusetts DPU in November of 2017. This increase will help fund reliability enhancement and customer service initiatives. At CL&P, base distribution rates will rise by an incremental $31.1 million on May 1st of 2019. Here again, this increase provides us timely recovery for our system improvements. Yankee Gas implemented a $1.4 million rate increase on November 15, 2018. The increase was the first of three approved in a multi-year agreement with Connecticut's PURA, with the second increase effective beginning in 2020. Yankee Gas also received approval for a tracking mechanism for cast iron and unprotected steel pipe replacements. Finally, Aquarion in Massachusetts implemented a $2 million rate increase just before the end of last year. In the transmission business, we expect to benefit from our continued investment in FERC regulated facilities. We invested just shy of a $1 billion in the transmission facilities at CL&P electric and public service in New Hampshire in the year 2018. And transmission investments in 2019 are expected to be at a similar level at $990 million as we complete some of our major transmission projects in Connecticut, New Hampshire, and continue to address our overhead and underground maintenance activities. In terms of O&M, although overall O&M is expected to increase in 2019 in areas of spending where we have regulatory commitments and recoveries in place, the O&M that affects earnings is expected to decline by about 1% to 2% in 2019. Growth will also be a result of distribution capital tracking mechanisms in areas such as replacement of old cast iron and unprotected steel pipes in our natural gas business and older water mains at Aquarion. Somewhat offsetting the additional revenues associated with these investments are higher depreciation, interest expenses, and property taxes. Turning from the recent investments to future capital expenditures. I'll move on to slide 14. Overall, we expect to invest nearly $13 billion in our core electric, natural gas, and water delivery systems from 2019 through 2023. We expect to invest nearly $8 billion over the next three years. This represents a significant increase from the $6.5 billion forecast we provided to you last year from our core business for the same years. It's a key contributor to continuing our outstanding service reliability to our customers and the extension of our 5% to 7% growth rate through 2023. As you can see on slide 15, every segment of the business is forecasting higher expenditures, with the electric transmission and distribution business showing the greatest growth. As shown on slide 16, we expect these increases to move our regulated rate base from $16.6 billion at the end of 2017 to $24.5 billion by the end of 2023. That’s a 6.7% compound annual growth rate that is expected to maintain our safe, secure, and reliable delivery systems and drive our 5% to 7% EPS growth over that period. This is the basis of why we believe we can grow earnings around the midpoint of our range on average over the next five years. We’re confident in that ability. On the transmission side, the increased investment aligns with our asset management oversight process and anticipates completion of our larger projects in Greater Boston, our New Hampshire seacoast, and our Greater Hartford suites of projects. It also includes significant regional projects such as substation investments in Greenwich, Connecticut and in Cambridge, Massachusetts, as well as a number of smaller projects to improve the resilience and security of the transmission system. These include replacing overhead structures and upgrading some of our underground infrastructure due to age and asset condition. Turning to slide 17, you see that many of the larger projects we have spoken about in recent years are moving ahead to final completion. The Greater Hartford Central Connecticut reliability family projects should be complete by the end of this year. We received a written order on January 31st of this year from the New Hampshire site evaluation committee approving the Seacoast reliability project and that is expected to be complete by the end of this year. The Greater Boston reliability project continues to progress. This is a joint solution with National Grid. We are responsible for 28 of these projects, of which 25 should be complete by the end of this year. In the Electric Distribution segment, we forecast capital expenditures of nearly $3.5 billion from 2019 through 2021 compared with last February's forecast of $2.9 billion for the same year. We also expect to invest another $2.25 billion over the course of the years 2022 and 2023 in electric distribution. There are a number of factors driving the increase. As we discussed previously, we've identified many additional automation and storm hardening opportunities following the rash of Nor'easters and tornadoes that struck our overhead electric system last March and May. We also are seeing faster customer growth in certain areas of Greater Boston, including the Seaport area and the cities of Somerville and Cambridge, which will require incremental substation investments. These investments are being made to meet the growing demand of customers in these areas. In the Natural Gas business, we now forecast $2.33 billion of capital expenditures over the next five years, with about $1.4 billion occurring in the next three. These expenditures include an acceleration of pipe replacement in both Connecticut and Massachusetts. In the recent Yankee Gas rate case, the Connecticut PURA shortened the period for replacing the older cast iron and unprotected natural gas distribution pipes from 13 years to 11 years. Our new forecast also reflects a more rapid replacement of cast iron and unprotected steel pipe in our larger Massachusetts system. We're also making additional plant and system investments in our Huntington LNG facility that we're doing in parallel with our current liquefier and major systems upgrade. On slide 18, you can see our forecasted pipe replacement capital budget for the next five years. You may recall that as a result of the Yankee Gas rate settlement, we now have fully reconciling pipe replacement and tracking mechanisms in place in both states. In addition to pipe replacement, we continue to see some growth from new construction, new customers, additional fuel cell applications, and the installation of new combined heat and power systems and customer facilities fueled by natural gas. This growth requires additional investments in our natural gas infrastructure, which drives the distribution rate base growth by an average annual average of more than 12% through 2023, far faster than any of our other regulated segments. The rate base is expected to exceed $3.5 billion here by the end of 2023. Turning to slide 19, in our Water Segment, we invested about $102 million in Aquarion systems in 2018, about 50% more than Aquarion's prior owners were investing each year. We expect to invest nearly $625 million in Aquarion systems over the next five years, or about $125 million per year. As you can see on the slide, we're projecting a rate base reaching approximately $1.2 billion by the end of 2023. Turning to slide 20, about a third of that investment is designed to improve Aquarion's ability to meet the water supply needs of southwestern Fairfield County in Connecticut. We now have reconciling mechanisms to recover pipe replacement investment in each state Aquarion serves. In addition to growing Aquarion through investments in our existing service territory, we continue to seek out opportunities to acquire small existing systems, particularly in Connecticut. About three weeks ago, state regulators approved Aquarion's purchase of assets of two smaller water companies in southeastern Connecticut. Four of the small acquisitions are now before regulators for approval. I mentioned the number of items that are included in our five-year nearly $13 billion capital forecast. On slide 21, we list some potentially significant items that are not in our core business CapEx forecast and may come to fruition during the forecast period. In the CapEx forecast, we've been conservative in terms of what may come out of the grid modernization dockets in the states we serve. In Connecticut, we await the release of a Connecticut PURA report on a year-long review of distribution companies' long-range planning, which there was considerable discussion about Advanced Metering Infrastructure or AMI, also discussion of energy storage, increased real-time monitoring of lines and substation conditions, and other topics. Because the review has extended longer than we had anticipated, we opted not to include any AMI or basic incremental grid modernization spending at CL&P in this forecast. We also did not include any basic grid mod in New Hampshire in this forecast, but expect to make some proposals in New Hampshire's upcoming general rate review or in a separate filing following the New Hampshire PUC's issuance of a final decision in their ongoing grid modernization proceedings. In Massachusetts, we are currently implementing $233 million of approved investments in core grid modernization, storage, and electric vehicle infrastructure. Beyond these programs, the DPU has asked the states’ electric utilities to propose next year a new three-year grid modernization program for the period of 2021 through 2023. Our forecast includes spending on incremental core grid modernization programs through 2023. Like Connecticut, we expect Massachusetts to also consider the rollout of advanced metering infrastructure or AMI. However, we have not reflected any rollout of AMI in this forecast. Separately, we have not included any investments in Northern Pass in this forecast. In terms of O&M, we expect O&M to remain relatively flat during years two through five of our five-year forecast after the decline of 1% to 2% for 2019 that I mentioned earlier. Turning to our financing plan. As illustrated at the end of the appendix, we have a modest level of maturities that will need to be refinanced this year and next year. However, we do have a significant core business capital program that I described earlier. In addition, we have approximately $100 million of excess deferred income taxes that will be refunded to customers over the next few decades. The cash flow benefits of bonus depreciation have ended, and these factors are positive for customers and depositors for long-term growth. Over the past four years, we've invested nearly $10 billion in our infrastructure to maintain great performance for our customers. Annual capital expenditures grew from about $1.9 billion in 2015 to more than $2.8 billion in 2018, which contributed to our top quartile reliability and service response for customers. We also entered the water business by acquiring New England's largest investor-owned water company back in December of 2017. We continue to evolve our business to meet the growing needs of our customers, as well as the clean energy mandates of our region. In order to finance this growth, this five-year forecast period does include the issuance of both new debts and equity to finance investments in a balanced way. We expect to issue approximately $2 billion of new equity over the next five years. This equity will help fund the nearly $13 billion of core business and capital investments we expect to make through 2023 and also our 50% of the capital requirements associated with the construction of the offshore wind facilities for which we and Ørsted have secured PPAs that Jim talked about earlier. We'll also use treasury shares to satisfy our dividend reinvestment program needs. Our expectation to grow earnings per share around the midpoint of the 5% to 7% range through 2023 anticipates the issuance of this equity over the five years. I'll repeat that. We expect earnings per share to grow around the middle of our 5% to 7% growth rate through 2023 even while issuing approximately $2 billion of equity through new common share issuance and with the Eversource shares coming out of Treasury for our dividend reinvestment program. We will be opportunistic about the equity issuance and will time them accordingly over the next several years. The PPAs we have for offshore wind will not produce revenues or earnings until the turbines begin producing energy. Construction costs including interest on debt will be capitalized into the class of the projects, but there will be no earnings on the equity investment until the turbines are operational. By 2024, we expect all 830 megawatts of offshore wind to be fully operational, adding to our earnings growth trajectory in a meaningful way going forward. Cash flows are also expected to rise significantly once the offshore wind turbines are fully operational. On the fixed income side, we continue to carry very strong credit ratings from all agencies. We've always maintained a balanced approach here, achieving above-average strong earnings and dividend growth and also strong credit ratings. We pride ourselves on delivering strong financial performance and strong financial condition. This plan accomplishes both in a balanced way, delivering 5% to 7% EPS growth and maintaining the strong financial condition and metrics that we currently have. To summarize on slide 24, as Jim said earlier, 2018 was a very strong year for us. Our reliability and safety metrics remained in the upper tier of the industry. Our customer service metrics continue to improve, and we are introducing innovative technology to improve the customer experience in many ways, including more mobile access. We continue to play a vital role in implementing our states' clean energy initiatives. We continue to provide our investors with strong earnings and dividend growth and to provide an attractive future growth opportunity. Going forward, our core business continues to be the engine for our 5% to 7% EPS growth outlook for 2023. Our underlying rate base growth is 6.7%, and we continue with our strong focus on our O&M part. We see offshore wind as being added to our earnings growth in a meaningful way beyond 2023. I look forward to seeing many of you at the Equity and Fixed Income Conferences coming up in Boston and New York over the next week. I'll turn the call back to Jeff for Q&A.

Thank you, Phil. And I'm going to return the call to Brendon to remind you how to enter your question.

Good morning, guys. Thanks for the big update. A question on the equity coming out. Can you give us a sense of whether some of it is back-end loaded for the wind project? I think you said that you wouldn't be investing in the wind projects until they come online, right? So that would be pretty far out. And that was, I think, the Ørsted is only $225 million so that wouldn't be that much of the $2 billion equity to account for that. Maybe you can give us a sense of what that equity is for like why do you need equity now. I mean I understand that with bonus depreciation rolling out, tax cash taxpayer at some point in this plan. So that would be a contributor. Can you just tell us what's driving the $2 billion of equity and when you'll need most of it? Is it back-end loaded or front-end loaded?

Sure. So, Mike, let me just add to something that you mentioned or clarify a few things. The capital program of $13 billion and the construction of 830 megawatts is included over the next five years, not just that initial payment that you referenced to the partnership in Ørsted. So it's the construction of the 830 megawatts where the turbines and our CapEx program. So as I said, we will be opportunistic and assess what our needs are over that time period. There's no rush to need to do anything, but we'll take our time to look at what our construction program looks like over that time period and make some determination over the course of that period. So I wouldn't say that any of it is front-end or back-end loaded. I just say we'd be opportunistic about how we're going to approach it going forward.

Is how much of it is driven by the fact that you are becoming a cash taxpayer again and because I mean just a few years ago we were talking about the possibility of stock buybacks right. So this is the flip of that. I'm just wondering what's the driver of the $2 billion?

Yes. Mike, we're a better tax cash payer actually, we are a tax and cash payer this year and we expect to be a tax cash payer next year. We had about $160 million of cash taxes in 2018 and will probably be in the $130 to $150 range in 2019 in terms of cash payment. And just to clarify in terms of, we had not really discussed share buyback. I know but we got the question a lot, but I've always and we've always said that our focus is on investing in the infrastructure of business. And we didn't see that we would be in that mode of buying shares back that we would be continuing to invest in the business. As I said, we've had a significant capital program over many years, and have the next five years as even larger as I described going forward.

Mike, this is Jim. Just to add to a point that Phil made earlier in his comments. I think it's important to recognize that we're guiding towards 6%, the midpoint of the range through 2023, and in the process, we're not only funding the core business CapEx, but we're funding the build-out of the offshore wind as well, with virtually no earnings contribution from that business until 2024 when revolution wind comes online. So we're basically guiding to 6% even with the drag associated with the offshore wind investment.

Got it, and that offshore wind investment is currently just a 50% investment in Ørsted, correct?

That is our partnership with Ørsted 50% on day one.

Good morning. Maybe to ask the timing of the equity in a different way. So I think you have mentioned in the past that you wanted to keep the current Moody's credit rating intact. Do you have any sense of does that imply a target FFO to debt of, let's say, 14% to 15%? And, if so, what time period do you look to achieve or at least maintain that level?

Well, certainly we like where our Moody's credit rating is. As you're right that we were target to maintain that credit rating. And you are also right that it would indicate FFO to debt at those levels which would imply we would be targeting that to maintain those ratings. So there's really no change there, and I think that as we get into our kind of our spring forecast period with the rating agencies, we'll obviously have discussed any press release that comes out and will provide an updated forecast as we go forward.

Understood and then regarding the 5% to 7% EPS CAGR through this time period. Do you expect it to be a little bit lumpy given a lot of the regulated, the bulk of the increase of the regulated investments are in the next three years and then you have a lot of the wind construction financing without the earnings benefit coming in the latter half of that period? I'm just trying to gauge whether it’s more stable or whether we could expect some lumpiness?

I'd say it's more stable. Certainly any particular quarter could have particular things in it, but I'd say you should expect us to be in a stable growth environment.

Understood and just one more if I could. What's the total potential opportunity set for AMI at least over this five-year period that could add to the rate base growth?

When considering our situation, it's important to note that nothing has been approved yet. If a full rollout were to happen in Connecticut and Massachusetts, the total cost for a complete rollout across all areas for AMI could reach around one billion dollars. This would require installation over several years, so that's the scale you should keep in mind.

Hey, good morning, team. Thank you. Perhaps just to kick off on the offshore side, could you elaborate a little bit on how you think about the size of the equity check now? I mean I know you've put down something of a down payment here with 225. I know that you are targeting regulated-like returns on this investment, but what is the equity check that you're going to need just the kind of backdoor if you will into the 2024-ish earnings profile that we're talking about here?

Yes. Julien, this is Jim. I don't know, you mentioned regulated returns, Ørsted has identified high single-digit IRR as an appropriate return target. Importantly, is the limit on that, so that translates more to mid-teens ROE for us. We would expect offshore wind to be our highest earning business segment.

I’m sorry, okay, to run and reconcile with that mid-teens on what kind of equity check? And should we include the 225 that you've paid as part of that equity as part of the denominator in that ROE?

Yes. I mean certainly the 225 is part of the total cost of the project. There will be construction costs that go in there but you can imagine that given the competitive nature of this business, discussing specific construction costs or other assumptions would be letting a little bit too much out of the bag in terms of competitors. So I say we'll try to be transparent. I think you probably have an assessment of your own as to what a megawatt cost to build or something like that, but the 225 is part, I'm just getting started and there'll be construction costs that get added to that as we go forward.

Sorry maybe this might be a little more power way to ask it. What about like equity contribution is like a percentage of the capitalization. I know you have ITCs and the capitalization but is we taking 50:50, 30:70, kind of high conceptually?

Yes, Julien, I'll try it another way that we're not going to sort of disclose the financing construct of our bids, but we are saying that the dramatic increase in our core business CapEx, coupled with the cost estimates that we have to build out the offshore wind suggest that we want to do about a $2 billion equity issue through this five-year window to continue to maintain the track record that we have. Our track record highlights our credibility and consistency. As shown in slide 5, we have achieved impressive performance over various time frames, consistently outperforming both the index and the S&P 500. Reflecting on my time as CFO of NSTAR twenty years ago, the results have been even more striking over the long term. This consistent performance reinforces our credibility. While our financial results have consistently ranked at the top, we have also maintained a strong financial condition throughout most of this period. We have developed a financing plan that positions us to continue as a top-performing entity while upholding a high credit rating. The financing is flexible, addressing our cash needs for both our core business and offshore wind projects. This strategy will enable us to uphold the exceptional track record we have established. We are committed to achieving 5% to 7% growth in both earnings and dividends, which we have sustained for many years.

If I can just jump in real quickly on the 5% to 7%, obviously, you're rebasing after 325. How are you thinking about the sort of the shape of that to get to the midpoint? I mean you just raised CapEx, at the same time raising equity, seems like it's about a nickel decline versus the prior baseline for 2021 but I'm sort of curious as you see this out play out through 2023. Are you still saying it is midpoint of that 5% to 7% versus the prior baseline?

Yes. We are. Absolutely and again just in terms of the rebase lining comment. I mean traditionally our track record has been set each year we would move into the new year and then add another year and this year we're adding two more years into that. So it's very traditional as to how we've addressed giving you long-term guidance but certainly conviction in a stable way with being in the middle of that range is clearly what we're confident in delivering.

Good morning. I wanted to talk about offshore wind as well and just conceptually with your partnership with Ørsted, obviously, Ørsted is a very accomplished offshore wind developer. At a high level how have you all determine the allocation of risk? Is it sort of essentially a true partnership where all risks are shared equally between the partners or is there a bit of a different delineation in terms of responsibility and risk between the two partners?

It's a shared risk 50:50. We collaborate on various benches into the RFP. The basis for the returns that we expect promotes bids. So it's a true 50:50 partnership from a risk perspective.

Understood. And then when I think about the permitting process. I'm just not familiar with everything that would be involved or sort of other approval elements, and just thinking through permitting risk and other risks here. At a high level again, don't need to go through every permit, but how do you think about execution risk for these projects? You obviously have PPAs in place which is a huge element here, but how do we think about the potential risks of execution here?

That's about 24 months permitting and citing calendar and site assessment work that has to go on. Then the US O&M is a key agency and then you get state and local permitting as well. Construction then is another 24 months, so right now where we are in the cycle is we expect South Fork site to be finished by the end of 2022 on that calendar. And the Revolution wind which is the larger one, 700 megawatts of PPAs to be done by the end of 2023.

The process has begun at the New Hampshire Supreme Court, which has agreed to hear our case and received the briefs. We anticipate that oral arguments will be scheduled soon, likely around May. While there is no specific deadline for the court's decision, we expect a ruling by the end of the year. Regarding the Army Corps permit, a preliminary assessment has been made, and once the other approvals are secured, we do not foresee any issues moving forward with that permitting process.

Good morning, everyone. How are you? I want to touch on offshore wind again. My question is more conceptual, as you have really embraced offshore wind during this call. The focus on offshore wind has grown significantly, particularly with the partnership with Ørsted. However, there are still many skeptics regarding offshore wind, especially concerning execution risks. While it has been successfully done in Europe, the apprehensions about executing large projects and obtaining approvals seem to be considerable among investors in the US. How did you become confident in managing that risk? Do you believe this project will be completed on time and within budget, or are there significant risks that you are concerned about?

Yes. I think it's a good question. I do think it's important to note that, while there was a lot of discussion of the offshore wind, what's particularly notable is that the dramatic increase in our core business CapEx for the three years in particular is about a 25% increase for the next three years. And that's driving a lot of our growth prospects along with the rate platforms that we have in place. Ørsted has a long track record in many countries of going through the sighting process of delivering on projects and actually coming in under budget and on schedule. I understand that it's a new process here in the US. The sense that we get is that policymakers in particular in the states in New England have a very strong appetite for more offshore wind. We've been through some of the site assessment plans already in 2017, which has been actually completed already. So we're basically right where we thought we would be from a sighting and permitting perspective. And I think there's a lot of excitement around the demand and the interest in offshore wind. We're making commitments in the various states in terms of economic development et cetera. So I have reason to believe that the spending that we have in the plan of 2022 and 2023 is likely to take place as we go through the permitting process and begin construction.

I just add a couple of things to that. Another factor would be the amount of preliminary engineering and preliminary work that has gone forward on a number of these items. So the lack of surprises there to somebody who maybe has just been a winner of a lease who has been in but really hasn't been able to do multiple years of wind and seabed assessments and those types of things.

Got you, that's super helpful color. And just in terms of returns, clearly the return sounds pretty good based on the current views. Is there in your assessment, given you've done so much analysis on it, where are the big levers that could drive returns downwards or upwards? Is it just construction or are there other factors that we should be thinking about as well?

Construction is definitely a significant factor, and as Jim pointed out, our history of completing projects on time and according to schedule is very impressive. Therefore, construction costs could be one aspect to consider.

It could, but we are quite confident. We conducted thorough due diligence with our board regarding this deepwater transaction. It's important to recognize that with Ørsted, we now possess the closest leases to the mainland, which makes the construction costs and water depth favorable for development. Notably, the Ørsted lease we acquired in 2016 cost $600,000, and these leases are situated very close to shore. Leases located another 20 or 25 miles out in deeper waters increase transmission costs. A couple of weeks ago, similar leases sold for $135 million each, indicating significant value. There is strong interest in offshore wind development, and we have distinct advantages in cost and construction due to the strategic locations of our two valuable leases.

Thank you, Praful. Next question is from Antoine Armand from Bank of America. Good morning, Antoine.

Hey, guys. Thanks for taking my question. I just wanted to get a quick sense of new debt financing needs this year beyond the maturities.

Typically, we don't give a precise schedule of our debt financing needs throughout the course of the year or the exact timing of it. But I do expect that for the maturities that we have, we have $800 million of maturities that we would be financing and refinancing those and depending on levels of short-term debt, we could be doing issuances that are incrementally higher than that. So most of those would be at the various operating entities who have needs because they have their own construction programs and they finance their construction with internal funds plus debt financing. So $800 million is what the maturities are, and I would expect we will probably do something above that to keep our short-term debt levels down.

Got it and then over the five-year period. So you have capital expenditures. You have this $2 billion of equity, and $500 million combined of treasury shares. And then I mean cash from ops so you probably doing at least $2 billion a year. So if you have added these all up, you have very limited incremental debt issuance over the period. Is that a right way to think about this?

Yes, and then we have, as we've mentioned a few times, that we are additive to that $13 billion capital plan, is the build-out of the offshore wind that I didn't mention here in that list of items.

Good morning. No questions about offshore winds for change, but a different angle. So would you be interested in expanding your T&D businesses in New England? If there were to be federal asset sales in New England?

Hi, Angie. This is Jim. We would certainly be interested at the right price in expanding our T&D core business. We have a long history of being disciplined bidders, as evidenced by transactions we've conducted over the past 20 years. The formation of NSTAR is viewed very positively from a shareholder perspective over that time. Seven years ago, we merged NU and NSTAR into what is now Eversource, a move that was well-regarded by both investors and customers. Last year, we completed a water acquisition that was also successful, adding to earnings in the first year and exceeding our expectations for that business. Whether it’s T&D or the water segment, we believe our core platform is strong and we are interested in growth. However, we have missed out on many transactions in the region because we remain disciplined in our bidding approach. Ultimately, it will depend on the value we can provide and the asking price for any acquisition.

No. It's strictly for the capital plans we have and the investment activities that are in the five-year horizon.

Hey, good morning, everyone. That was a long time to not talk about offshore wind, kidding of course, but just one or two going back to that topic. Strategically, Ørsted obviously now onto Block Island and is interested in developing offshore wind in the mid-Atlantic. Would you consider expanding beyond New England and New York or are you going to stick to your former corporate name of Northeast utilities?

So, we will. Northeast utilities is an old name but certainly the assets that we acquired in the transaction with Ørsted were the deepwater Northeast assets. There were other assets that were not part of the transaction. So we see our competency in this particular region as opposed to across the US. Proximity was a factor there are other leases that the Ørsted bought in the process that were further down the east coast from the mid-Atlantic area. And we didn't buy into those properties. So we at this stage, we feel that the proximity is important. These two leases are right off the coast of Massachusetts and Rhode Island coastal core operations. So that was a factor in the decision at this point.

I understand that you are confident the construction will proceed on time and as scheduled. My question is about the mechanical or procedural steps that would be taken if you cannot meet the obligations outlined in the various PPAs. Specifically, how does each state handle the situation if the turbines are not operational as planned?

I think, yes, this is Lee, Andrew. The issue with the PPAs has certain provisions that essentially required you to post more credit letters, letter of credit, but the penalties are relatively speaking to the investment are minimal if you don't meet the in-service dates.

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

Good morning. How you doing? Just a few quick ones: the ROE in New Hampshire, you guys said that you're under earning a lot. I just wonder could you tell us what it was for 2018?

We've just filed our final numbers; we are in the process of doing it. I say it's just shy of 8%; it's below 8%.

Okay, regarding the grid modification, I understand it’s not included in the forecasts for Connecticut or New Hampshire. However, I’ve noticed that the grid modification docket seems to be on hold for some reason, and I'm not entirely sure why. Could you provide a bit more detail on what might be happening there?

Yes. I just commented with the new governor coming in there have been some changes. The former chair of PURA has now taken a more significant job as the Commissioner of DEEP. So I think it's got to do with the changes organizationally that happened with the new administration.

And in New Hampshire, they typically have a smaller staff than any of the other states. In fact, just recently they started to move forward in a more active way in terms of draft mechanisms or draft position papers that will require some more studies. So it's moving along and if there's no particular reason other than staffing at this stage.

And then I think after this year, you're expecting O&M to be flat. Is that tied in any way to the CapEx that you guys have been investing or just is that just the savings that you guys are doing from what you guys have often been doing? There's cost containing.

Well, certainly I did highlight on the call that certainly the CapEx investment has driven improvements and high levels of reliability and safety and performance for our customers, but it also helps in terms of taking other costs out of the business. If you repair something that you don't have to go visit two or three times to repair, if you replace it, you'd have some O&M savings. So certainly the O&M gets reduced as a result of it. So being flat is really a challenge because you've got inflation and negotiated wage increases. So really you're taking kind of 2% to 3% of cost out of the business just to stay flat.

Okay and then just on the offshore wind. Are you guys thinking of doing perm EPCs or anything like that with respect to the execution of the actual build-out or how do you guys look at that?

Yes, Paul, this is Lee. I think the way to think that is that Ørsted brings all of the resident competencies that they need; they're just coming off building or in the process of building over 2,200 megawatts for the UK alone. And again, as Jim said, all on schedule and below budget, so they're in very good shape for them. It's a core expertise that's what they do. So it really wouldn't make any sense to bring in an EPC. There are other developers that clearly will have to bring in an EPC because they just don't have that core competency.

Okay and then the capacity factor, just could you remind me what it is that you guys are expecting for wind? Offshore wind.

Capacity factors are on the range of 45% to 50% capacity factors on the wind, and it's higher in the winter when prices are the highest in the region including New York, so there's a great benefit in that winter period for reliability and price suppression as well.

I didn't tell you what it was but for electric, Paul, it was and again I preface my answer by saying as a result of our great plans that we have in place, 90% of our revenues in all of Massachusetts and all of Connecticut are decoupled. So weather has no impact; only New Hampshire is the only jurisdiction that is still not decoupled but normalized for the year was down slightly like 0.2%.

Thank you, Paul. Next question is from Travis Miller for Morningstar. Good morning, Travis.

Good morning, thank you. I'll return to the offshore wind if you don't mind. The agreement with Ørsted outside of the projects in the works right now. When we think about that CapEx beyond and thinking out to the big potential, what type of obligation as part of that deal with Ørsted and partnership with Ørsted? You have an obligation there to invest if say Ørsted were to make a decision to go forward?

No. With any opportunity we have the right to participate or not. There's no commitment or obligation to fully build out the 4,000 megawatts. We have an option to proceed or not.

Okay, on your own based on your own economics and decision, okay. And then in terms of policy to again apart from the PPAs in place, are there any policies that need to go into effect in any of those northeastern states to promote offshore wind such that you could make it easier to go forward or are you going to be competing with other renewable sources on some of those non-identified projects?

Yes. There's been a mixture. This clearly been actual offshore wind specific RFPs; the state of Massachusetts was the first to legislate that 1,600 megawatts need to be bid and it's specific to offshore wind. If it completed 800 of that with the first solicitation, we expect the next one to occur the first half of 2019 here. Additional legislation in Massachusetts has asked the Department of Energy resources to take a look at doubling that number to go to 3,200 megawatts. The state of New York has legislated 2,400 megawatts that they're going to do through multiple solicitations. Connecticut and Rhode Island have been active as well. In New York, the governor has actually suggested that he thinks that they should go to 9,000 megawatts although only 2,400 has been legislated to date. So the policy is in the form of offshore wind solicitations. One of the Connecticut solicitations that took place last year had offshore wind among other clean energy resources. In that instance, the revolution wind project won an additional 100 megawatts, but there were also solar and nuclear commitments in that process as well. So the majority are offshore wind specific but there were some clean energy RFPs that would invite all fuel sources. Also important to note is that in Connecticut, the governor has filed a bill yesterday, a Senate bill that would add an additional 1,000 megawatts of offshore wind. So that's firming up as well.

Hey, guys. Can you hear me? Okay, and I apologize if this was answered or that has been popping around so just get back on the equity. How much of the $2 billion is allocated for the offshore wind? The spread out?

Yes. There's no specific allocation, Andy, is the direct answer. We would look at our total portfolio of construction and investment needs, which we said is $13 billion over the next five years for our CapEx. Then we would add on to that the build out of our share of the cost of the 830 megawatts of build out of the offshore wind. So looking at the total pot is where we would focus not specifically on that area.

No. No. I understand that but if you didn't have the offshore wind how much equity would you be issuing?

Well, you're asking it the same way only differently. As I said, the $2 billion of equity supports kind of our total CapEx and offshore wind for the next five years.

Yes. We've been saying based upon actually Ørsted has disclosed an 8% unlevered IRR which is going to give us a return that we think would be transmission-like or better when you look at the returns on equity that we would expect there.

Correct.

Okay and that's assuming that everything goes as planned or do you have a contingency built in into that?

We work with Ørsted to build in appropriate contingencies not only in terms of spending, but in terms of schedule.

Hey, guys, and just one quick follow-up. I just wanted you to explicitly say that just to confirm that you basically have offshore wind; additional offshore wind in the equity number, but it's not in the CapEx plan, correct?

That is correct. It's not CapEx, it's equity investment.

There's a certain amount that might seem high in equity to some people because it is not included in the $12 billion to $13 billion CapEx plan.

That's exactly correct, Mike.

All right. Well, thank you very much for joining us today. If you have any follow-up questions, feel free to give us a call or send us an email. We look forward to seeing you at the conferences in early March. Take care.