Good morning, and welcome to the Eversource Energy fourth quarter and year-end 2018 results. My name is Brandon, and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session during which you can dial star one if you have a question. Please note this conference is being recorded. I will now turn it over to Jeffrey Kotkin. You may begin, sir.
Thank you, Brandon. Good morning, and thank you for joining us. I am Jeff Kotkin, Eversource Energy's Vice President for Investor Relations. During this call, we will be referencing slides that we posted last night on our website. 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 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 31st, 2017, and on Form 10-Q for the three months ended September 30th, 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 two, speaking today will be Jim Judge, our Chairman, President, and CEO. 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 M. Moreira, our Treasurer and Senior VP for Finance and Regulatory. Jay S. Buth, our VP and Controller. Now I will turn to slide four and turn over the call to Jim.
Thank you, Jeff, and thank you everyone for joining us this morning. I am happy and very pleased to discuss our successful performance in 2018 and the very strong future we see for Eversource. Our 8,000 talented, 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 states. In doing so, we have created a solid, very long track record of delivering significant value to our shareholders and doing so in a way that effectively manages the risks of our business. 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, when combined with our success in reducing our O&M costs 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 four, 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 & Power settlement was the first electric rate case settlement in Connecticut since 1986 and underscores the level of trust and transparency that we've 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 for 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 on some of our strategic initiatives to support New England's focus on sustainability and greenhouse gas reduction. In addition to the divestiture of our fossil units, we successfully completed the build-out of 62 megawatts of solar in Massachusetts. The solar investment totals approximately $170 million. In addition, we also 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 all support Massachusetts State Energy Policy, by the middle of next year, we're due to file a new plan for the next three-year cycle, beginning with 2021.
Our progress in these areas is being recognized. Various ESG rating firms 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 also 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 five, you can see that our total return continues to outperform both the utility index and the broad market on a short-term and long-term basis. While past performance is certainly 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 six, 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 our 5%-7% long-term growth rate and exceeds the average dividend growth in our industry. As you can see on slide seven, we continue to forecast growth of 5%-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 or through the year 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 for our growth.
As you can see on slide eight, we made an announcement earlier this month that we believe will have a very positive impact on our results well through the next decade. On February 8th, we announced the purchase of a 50% share of some of the projects in offshore wind energy leases that Ørsted acquired when they bought Deepwater 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 U.S. and are 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, and 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 siting process and will have very limited impact on our earnings growth through 2023.
Beginning in 2024, we expect our 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. Later this year, we expect to bid into the second Massachusetts offshore wind RFP, where the state seeks another 400 megawatts-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. Phil will have more to say about the expected financial impact of this announcement.
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. The 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 delivered below the budget that was set when a final investment decision was made. This factor, 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 about being a disciplined bidder who 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 are New England's 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. Through this partnership, we're quite pleased to play a leading role in executing the region's energy policies. We're also pleased with the long-term earnings growth opportunities these investments will provide to our shareholders. I'll turn the call over to Phil.
Thank you, Jim. Today, my part 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 of our 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. We're right in line with that projection. Our electric distribution segment 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. Also offsetting the higher revenues were increases in depreciation, interest, and property tax expense.
Our electric transmission segment earned $1.34 per share in 2018, compared with $1.23 in 2017. Improved results primarily reflect our increased investment 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 were not decoupled 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 off by $0.09 per share in the fourth quarter, due in part to the absence of the generation earnings due to the divestiture, as well as higher depreciation interest in 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, colder weather, and some increased revenues stemming from the Yankee Gas rate decision. We also had $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 & 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 on its allowed ROE of 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 refunds 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 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 a lot. 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 a standard 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 multi-year rate review outcomes in 2018 from our Massachusetts electric jurisdictions and our Connecticut electric and natural gas utilities.
NSTAR Electric implemented roughly a $32 million increase in base distribution rates on January 1, 2019 as part of its five-year performance-based rate plan approved by the Massachusetts DPU in November 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 1, 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 our FERC-regulated facilities. We invested just shy of $1 billion in the transmission facilities at CL&P, NSTAR Electric, and Public Service Company of New Hampshire in the year 2018. 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 as 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%-2% in 2019.
Growth will also be as a result of distribution capital tracking mechanisms in the areas such as replacement of older 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 expense, 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, so eight out of the 13 over the next three years. This represents a significant increase from the $6.5 billion forecast we provided to you last year for our core business for those same years.
It's a key contributor to continuing our outstanding service reliability to our customers into the extension of our 5%-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%-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, 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 suite 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 to you over recent years are moving ahead toward final completion. The Greater Hartford Central Connecticut reliability family of 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 a 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're 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 three and a half billion from 2019 through 2021, compared with last February's forecast of $2.9 billion for these same years. 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 a 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 cities of Somerville and Cambridge. We'll be making incremental substation investments. These investments are being made to meet the growing demands 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 Hopkinton 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 application, and the installation of new combined heat and power systems in 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 annual average of more than 12% through 2023, far faster than any of our other regulated segments. 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 rate base reaching approximately $1.2 billion by the end of 2023.
Turning to slide 20, you can see 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 investments 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 smaller existing systems, particularly in Connecticut. About three weeks ago, state regulators approved Aquarion's purchase of assets of two smaller water companies in southeast Connecticut. Four other small acquisitions are now before regulators for approval. I've mentioned a 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, I'd say, 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, you can see on slide 22, we are currently implementing $233 million of the approved investments in core grid modernization, storage, and electric vehicle infrastructure. Beyond these programs, the DPU has asked the state's 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 mod programs through 2023. Like Connecticut, we expect Massachusetts to also consider the rollout of Advanced Metering Infrastructure, or AMI, but we've not reflected any rollout of AMI in this forecast. Separately, we've 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%-2% for 2019 that I mentioned earlier. Turning to our financing plan.
As illustrated at the end of the appendix, we have 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, and the cash flow benefits of bonus depreciation, as everybody knows, has ended. These factors are positive for customers and positive 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 debt and equity to finance our investments in a balanced way, as you can see on slide 23. 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%-7% range through 2023 anticipates the issuance of this equity over the five years. I'll repeat that. We expect to grow earnings per share around the middle of our 5%-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'll be opportunistic about the equity issuance, and we'll time them accordingly over the next several years. The PPAs we have for offshore wind do not produce revenues or earnings until the turbines begin producing energy.
Construction costs, including interest on debt, will be capitalized into the cost of the projects, but there will be no earnings on the equity investment until the turbines are operating. By 2024, we expect all 830 MW of offshore wind to be fully operational, being additive to our earnings growth trajectory in a meaningful way going forward. Cash flow is 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 for all agencies. We've always maintained a balanced approach here, achieving above-average strong earnings and dividend growth, and also strong credit ratings. We prided ourselves on delivering strong financial performance and strong financial condition. This plan accomplishes both in a balanced way, delivering 5%-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 continued 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 state's clean energy initiatives. We continue to provide our investors with strong earnings and dividend growth and have provided an attractive future growth opportunity. Going forward, our core business continues to be the engine for our 5%-7% EPS growth outlook through 2023. Our underlying rate base growth is 6.7%, and we continue with our strong focus on our O&M costs. We see offshore wind as being additive to our earnings growth in a meaningful way beyond 2023.
Look forward to seeing many of you at the equity and fixed income conferences coming up in Boston and New York over the next weeks. I'll turn the call back to Jeff for Q&A.
Thank you, Phil. I'm going to, pardon me, return the call to Brandon to remind you how to enter your questions.
Thanks, Jeff. We will now begin the question and answer session. If you have a question, please press star one on your telephone keypad. If you'd like to be removed from the queue, please press the pound sign or the hash key. If you're on a speakerphone, please pick up your handset first before dialing. Once again, if you have a question, please press star one on your telephone keypad.
Thank you, Brandon. First question this morning is from Michael Weinstein from Credit Suisse. Good morning, Mike.
Good morning. Good morning, guys.
Good morning.
Thanks for the big update. A question on the equity coming out. I know that you said it's going to be opportunistic, can you give us a sense of whether some of it is backend loaded for the wind project? I think you said that you wouldn't be investing in the wind projects until they come online, right? That'd be pretty far out. I think the Ørsted deal was only $225 million, 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. Why do you need equity now? I understand that with bonus depreciation rolling off, you're a cash taxpayer at some point in this plan, 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 backend loaded or front-end loaded?
Sure. Mike, let me just add to something that you mentioned there. Clarify a few things. The capital program of $13 billion and the construction of the 830 MW is included over the next five years, not just that initial payment that you referenced for the partnership in Ørsted. It's the construction of the 830 MW worth of turbines and our CapEx program. As I said, we'll be opportunistic and assess what our needs are over that time period. 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. I wouldn't say that any of it is front-end or back-end loaded. I'd just say we'd be opportunistic of how we're going to approach it going forward.
How much of it is driven by the fact that you are becoming a cash taxpayer again? Because just a few years ago, we were talking about the possibility of stock buybacks. This is the flip of that. I'm just wondering, what's the driver of the $2 billion?
Yeah. We've been a tax cash payer. Actually, we were a tax 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 we'll probably be in the $130 million-$150 million range in 2019 in terms of cash payment. Just to clarify, in terms of, we have not really discussed share buyback. I know that 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 the 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 the next five years is 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. 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. We're basically guiding to 6% even with the drag associated with the offshore wind investment.
Got you. That offshore wind investment is just the Ørsted for now, just the 50% investment for now, right?
That is our partnership with Ørsted, 50% on Day one .
Okay, great. Thank you.
Thanks, Mike. Next question, pardon me, is from Insoo Kim from Goldman. Good morning, Insoo.
Morning. Maybe to ask the timing of the equity in a different way. Phil, I think you had 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 target FFO to debt of, let's say 14%-15%? If so, what time period do you look to, I guess, achieve or at least maintain that level?
Well, certainly, we like where our Moody's credit rating is, you're right, that we would target to maintain that credit rating. You're also right that that would indicate FFO to debt at those levels, that would imply we would be targeting that to maintain those ratings. There's really no change there, I think that as we get into our spring forecast period with the rating agencies, we obviously have discussed any press release that comes out, we'll provide an updated forecast as we go forward.
Understood. Then regarding the 5%-7% EPS CAGR through this time period, do you expect that to be a little bit lumpy given a lot of the bulk of the increase of the regulated investments are in the next three years, then you have a lot of the wind construction financing without the earnings benefits coming in the latter half of that period? I'm just trying to gauge whether it's more of stable or whether we could expect some lumpiness.
I'd say it's more stable. Yes. Certainly, any particular quarter could have particular things in it, I'd say you should expect us to be in a stable growth environment.
Understood. 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-based growth?
When you look at it, I'll say first, nothing's been approved, right?
Right.
If you did a full rollout in Connecticut and Massachusetts, you might be at $1 billion for a full rollout everywhere for AMI. To proceed with a program like that, it would be over multiple years to get that installed. That's the sizing that you should be thinking about there.
Got it. Thank you very much.
Great. Thanks, Insoo. Next question is from Julien Dumoulin-Smith from Bank of America. Good morning, Julien.
Hey, good morning, team. Thank you. Perhaps just to kick off on the offshore side, if I can. Can you elaborate a little bit on how you think about the size of the equity check now? I know you've put down something of a down payment here with the $225. I know that you are targeting regulated-like returns on this investment, What is the equity check that you're going to need just to kind of backdoor, if you will, into the 2024-ish earnings profile that we're talking about here?
Yeah. Julien, this is Jim. I don't know, you mentioned regulated returns. Ørsted has identified high single-digit IRRs as an appropriate return target, and importantly, there's a limit on that. That translates more to mid-teens ROE for us. We would expect the offshore wind to be our highest-earning business segment.
Sorry. Okay, to run and reconcile with that, mid-teen returns on what kind of equity check? And should we include the $225 that you've paid as part of the denominator in that ROE?
Yeah. Certainly, the $225 is part of the total cost of the project. There'll be construction costs that go in there. You can imagine that, given the competitive nature of this business, that discussing specific construction costs or other assumptions would be sort of, I think, letting a little bit too much out of the bag in terms of competitors. I'd 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. The $225 is part of 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 palatable way to ask it. What about an equity contribution as a percentage of the capitalization? I know that you have ITCs in the capitalization. Are we thinking 50/50, 30/70? Kind of high conceptually.
Yeah. Julien, I'll try it another way. We're not going to sort of disclose the financing construct of our bids.
Okay.
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, suggests that we want to do about a $2 billion equity issue during this five-year window to continue to maintain the track record that we have. That track record is one that's worth noting in terms of credibility and consistency. If you look at the slide five, we have had a remarkable run, whether you look at one, three, five, 10-year performance of outperforming the index and outperforming the S&P 500. I go back, if you looked at 20 years, I was CFO of NSTAR 20 years ago. I think the performance results are even more dramatic. There's consistency, and I believe credibility given the track record.
While the financial performance has been top tier for the majority of that window of time, we've also been the top tier in terms of financial condition. We've put together a financing plan here that is going to allow us to again be a top-tier financial performer, at the same time of having a top-tier credit rating. The financing is fundable, right, in terms of we have cash needs, whether it's core business or whether it's offshore wind. What we've sized here, I think is one that's going to allow us to continue the wonderful track record that we've had. We've got commitment and conviction to deliver on that 5%-7% earnings growth and dividend growth that we've had going for so many years.
If I can just jump in real quickly on the 5-7, obviously you're rebasing off the $3.25. How are you thinking about the sort of the shape of that to get to the midpoint? You just raised CapEx at the same time raising equity. Seems like it's about a nickel decline versus the prior baseline for 2020 and 2021. I'm sort of curious, as you see this play out through 2023, are you still saying it's midpoint of that 5-7 versus the prior baseline?
Yes. Yes, we are. Absolutely. Again, just in terms of the rebaselining comment, traditionally our track record has been that each year we would move into the new year and then add another year. This year we're adding two more years into that. It's very traditional as to how we've addressed giving you the long-term guidance. Certainly conviction in a stable way with being at the middle of that range is clearly what we're confident in delivering.
All right. Excellent. I'll leave it there. Thank you all very much.
Thank you, Julien. Our next question is from Stephen Byrd from Morgan Stanley. Good morning, Stephen.
Good morning. I wanted to talk about offshore wind as well. Just conceptually, with your partnership with Ørsted, obviously Ørsted's a very accomplished offshore wind developer. At a high level, how have you all determined 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 bids into the RFP, the basis for it, the returns that we expect from those bids. It's a true 50/50 partnership from a risk perspective.
Understood. 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, how do you think about execution risk for these projects? You obviously have PPAs in place, which is a huge element here, how do we think about the potential risks of execution here?
That's about a 24-month permitting and siting calendar and site assessment work that has to go on. The U.S. BOEM is a key agency. You get state and local permitting as well. Construction is another 24 months. Right now, where we are in the cycle is we expect South Fork Wind to be finished by the end of 2022 on that calendar. The Revolution Wind, which is the larger one, 700 megawatts of PPAs, to be done by the end of 2023.
Okay, understood. Just one last question, just on Northern Pass. You highlighted on a slide, which is really helpful, all the permits, and I guess the two next steps that I'm thinking about are the New Hampshire Supreme Court review and the Army Corps of Engineers process. Would you mind just talking a little bit further about next steps there and sort of how we think about those two pending processes?
Sure. The process has kicked off at the New Hampshire Supreme Court. They agreed to hear our case, received briefs on the case. We expect that oral arguments would soon be determined in New Hampshire, probably in the May timeframe. There really is no precise deadline or timeframe that's required for the court to decide, but we would expect some decision to be by the end of the year type of thing. At the Army Corps permit, there's been a preliminary assessment of that, and really at this stage, once all of the other approvals are made, we don't see any issue in moving through that Army Corps permitting process.
Great. That's all I have. Thank you.
Thanks, Stephen. Next question is from Praful Mehta of Citi. Good morning, Praful.
Morning, guys. How are you doing?
Good, Praful. How are you?
Sorry, but I'm going to dig into a little bit of the offshore wind again. I think the question from my side is more conceptual, as in you really on this call have gone headlong into offshore wind, right? The focus on offshore wind has increased significantly. Obviously, the partnership with Ørsted, and I think there are plenty of skeptics on offshore wind, more around the concerns on execution risk. Clearly, it's been done in Europe, but the risks around large projects, execution approvals, still seems to be pretty high among investors in the U.S. How did you get comfortable with that risk? Do you believe that this would be executed on time, on budget? Do you see any big risks that are out there that you worry about?
Yeah, 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, it's 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 siting 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 U.S. The sense that we get is that the policymakers, and particularly in the states in New England, have a very strong appetite for more offshore wind.
Been through some of the site assessment plan already in 2017, has been actually completed already. We're basically right where we thought we'd be from a siting and permitting perspective. 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. I have reason to believe that the spending that we have in the plan out in 2022 and 2023 is likely to take place as we go through the permitting process and begin construction.
Just to add a couple things to that. The more information that you have and the more certainty you have going into the process certainly reduces the risk exposure. We've been at this for multiple years, three years basically to do site analysis, to start the ball rolling in terms of permitting. The lack of surprises there to somebody who maybe has just been a winner of a lease, who has bid in but really hasn't been able to do multiple years of wind and seabed assessments and those types of things. Another comfort factor I'd add would be the amount of preliminary engineering and preliminary work that has identified and moved forward on a number of these items.
Got you. That's super helpful color. Just in terms of returns, clearly the returns sound pretty good based on the current views and the forecast. 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?
Certainly, construction is a big element in terms of, and as Jim mentioned, our track record for our projects being completed on time and on schedule, and Ørsted's track record for completing projects on time and on schedule are pretty high up on the list. Construction costs could be one element.
It could, but we have a fair degree of comfort and did a lot of due diligence with our board in terms of entering into this deepwater transaction. I think what's important to recognize is that now with Ørsted, we have the one and two closest leases to the mainland. That means that the construction costs, the water depth, are appealing in terms of a build-out. It's worth noting that the Ørsted lease that we entered into in 2016 cost us $600,000. Again, it's a lease that's very close to shore. Leases that are out another 20-25 miles in deeper water, more transmission costs, just sold a couple of weeks ago for $135 million apiece. I think that's a pretty good indication that there's a lot of value here, that there's robust interest in offshore wind build-out.
We have some significant advantages in cost and construction because of the locations of our two appealing leases.
Got you. That's super helpful again. Thanks so much, guys.
Thank you, Praful. Next question is from Julien Dumoulin-Smith from Bank of America. Good morning, Antoine.
Hey, guys. Thanks for taking my question. 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 refinancing those. Depending on levels of short-term debt, we could be doing issuances that are incrementally higher than that. 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. $800 million is what the maturities are, and I would expect we'll probably do something above that to keep our short-term debt levels down.
Got it. Over the five-year period, you have $1,275 of CapEx. You have this $2 billion of equity, $500 million combined of treasury shares. I mean, cash from ops, you're probably doing at least $2 billion a year. If you add these all up, you have very limited incremental debt issuance over the period. Is that a right way to think about this?
Yeah. 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-
Right
hear in that list of items.
Got it. Okay. Thank you.
Thank you, Julien. Next question is from Angie Storozynski from Macquarie. Good morning, Angie.
Good morning. No questions about offshore wind for a change, but a different angle. Would you be interested in expanding your T&D businesses in New England if there were to be potential asset sales in New England?
Hi, Angie. This is Jim. We would be obviously interested at the right price in terms of expanding our T&D. It's our core business. We have a long track record of being a disciplined bidder. When you look at the transactions that we've done, 20 years ago, a company that formed NSTAR was done and is seen as hugely positive from a shareholder perspective over that 20-year period. Seven years ago now, we did the deal that merged NU and NSTAR into what's now Eversource. A deal that was widely recognized as being a big win for investors as well as customers.
We did the water acquisition deal that we did last year, which true to form was delivered on , it was accretive to earnings in the first year, as we had indicated, and the actual earnings performance outperformed our budget or our expectations for that business. Whether it's T&D or the water business, we think our core platform is a successful one, and we would be interested in expanding. There have been dozens and dozens of transactions in this region that have taken place that we didn't win because, again, we're a disciplined bidder. It'll all come down to the value that we can bring to the transaction and what the asking price would be for the acquisition.
None of this is envisioned in or embedded in that $2 billion of equity issuances, right? That this is just to finance your current CapEx plans, and then you're not trying to shore up your balance sheet for a potential M&A deal.
No. It's strictly for, as I mentioned, the capital plans we have and the investment activities that are in the five-year horizon.
Great. That's all I have. Thank you.
All right. Thanks, Angie. Next question is from Andrew Weisel from Scotiabank Howard Weil. Good morning, Andrew.
Hey, good morning, everyone. That was a long time to not talk about offshore wind. Kidding, of course. Just one or two going back to that topic. Strategically, Ørsted obviously now owns Block Island and is interested in developing offshore 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?
Well, Northeast Utilities is an old name there. Certainly the assets that we acquired in the transaction with Ørsted were the deep-water Northeast assets. There were other assets that were not part of the transaction. We see our competency in this particular region as opposed to across the U.S.
Proximity was a factor. There were other leases that Ørsted bought in the process that were further down the East Coast in the Mid-Atlantic area. We didn't buy into those properties. At this stage, we feel that the proximity is important. These two leases are right off the coast of Massachusetts and Rhode Island, close to our own core operations. That was a factor in the decision at this point.
Okay. I know that you guys are very confident that the construction will be on time and on schedule. My question is mechanically or procedurally, what happens if you're not able to deliver on the obligations under the various PPAs? In other words, how does each state treat that potential scenario where the turbines aren't spinning on time?
I think, yeah, this is Leon Olivier, Andrew Weisel. Each of the PPAs has certain provisions in it that would essentially require you to post more credit, letter of credit. The penalties are, relatively speaking to the investment, are minimal if you don't meet the in-service dates.
Okay, very good. Just a quick one on the equity. If I heard correctly, Phil, I think you said that DRIP needs would come from the treasury stock. For the bulk of the $2 billion number, though, should we expect block issuances as needed, or would it be more like an equity forward deal?
There are many different ways of doing that, whether they be a block trade or roadshows or forward. In terms of an ATM kind of program. Not really describing specifically the intent, but certainly all of those would be, or the method, all of those methods would be evaluated, and we would move forward, again, opportunistically and in a manner that we felt was appropriate for the time.
Got it. In the past few years, what have the DRIP obligations been?
It's $90 million to $100 million annually.
Got it. Thank you very much.
Great.
Thank you, Andrew. Next question is from Paul Patterson from Glenrock. Good morning, Paul.
Good morning. How you doing?
All right, Paul.
Just a few quick ones. The ROE in New Hampshire, you guys said that you're under-earning your allowed. I was just wondering, could you tell us what it was for 2018?
We've just filed our final numbers or are in the process of doing it. I'd say it's just shy of 8%. It's below 8%.
Okay. With respect to, I know that Grid Mod is not in Connecticut or New Hampshire in your forecast, but I also noticed that the Grid Mod docket has sort of been held in abeyance for some I'm not clear why. Could you sort of elaborate a little bit more what might be going on there?
Yeah. I just comment that 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. I think it's got to do with the changes organizationally that happened when the new administration comes in.
Yeah.
Yeah.
In New Hampshire, they typically have a smaller staff than any of the other states. In fact, just recently, they've started to move forward in a more active way in terms of draft position papers that would require more study. It's moving along and there's no particular reason other than staffing at this stage.
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 is that just the savings that you guys are doing from just what you guys have often been doing in terms of 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. 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. Certainly the O&M gets reduced as a result of it. Being flat is really a challenge because you've got inflation, you've got negotiated wage increases. Really you're taking kind of 2%-3% of costs out of the business just to stay flat.
Okay. Then just on the offshore wind, are you guys thinking of doing firm EPCs or anything like that with respect to the execution of the actual build-out, or how do you guys look at that? I know you mentioned that this Ørsted and what have you, has got a good track record. Other than that, I'm just wondering, any idea about firm EPCs, or how should we think of that?
Paul, this is Lee. I think the way to think of that is that Ørsted brings all of the resident competencies that they need, that they're just coming off building or are in the process of building over 2,200 megawatts off of the U.K. alone. Again, as Jim said, all on schedule, below budget, so they're in very good shape. For them, it's a core expertise. It'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. The capacity factor, just could you remind me what it is that you guys are expecting for wind, offshore wind?
Capacity factors, they're on the range of 45%-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.
Okay. Just finally, weather-adjusted sales growth for 2018. Could you tell us what that was?
I didn't tell you what it was, but for electric, Paul, it was. Again, I'll preface my answer by saying, as a result of our rate plans that we have in place, 90% of our revenues, all of Massachusetts, all of Connecticut are decoupled.
Right.
Really, weather has no impact. Only New Hampshire is the only jurisdiction that is still is not decoupled. Weather-adjusted normalized for the year was down slightly, like 0.2%.
Okay, great. Thanks so much.
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're thinking 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, do you have an obligation there to invest if, say, Ørsted were to make a decision to go forward?
No. With any opportunity, we'd have the right to participate or not. There's no commitment or obligation to fully build out the 4,000 megawatts. We'd have an option to proceed or not.
Okay. On your own-
Correct.
Based on your own economics and decision. Okay. Then in terms of policy too, 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 winds 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?
Well, there's been a mixture. There's clearly been offshore wind-specific RFPs. The State of Massachusetts was the first to legislate it. 1,600 megawatts need to be bid, and it's specific to offshore wind. They've 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 state should go to 9,000 megawatts, although only 2,400 has been legislated to date. 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, our Revolution Wind project won an additional 100 megawatts, but there were also solar and nuclear commitments in that process as well. The majority of it are offshore wind specific, but there were some clean energy RFPs that would invite all fuel sources. I would just mention, Jim, that in Connecticut, the Governor Lamont, filed a bill yesterday, a Senate bill that would add an additional 1,000 megawatts of offshore wind. That's firming up as well.
Okay, great. That was 1,000 megawatts of pure
Yes
offshore wind. Just
Pure offshore wind.
Great. Okay, thanks a lot. Appreciate it.
All right. Thanks, Travis. Next question is from Andy Levi from ExodusPoint Capital Management. Good morning, Andy.
Hey, guys. Can you hear me?
Yeah.
Yes.
I apologize if this was answered already. I've just been popping around. Just back on the equity, how much of the $2 billion is allocated for the offshore wind? That's been announced.
Yeah. There is no specific allocation, Andy, is the direct answer. We would look at our total portfolio of construction and investment needs, which we've said is $13 billion over the next five years for our CapEx, then add onto that the build-out, our share of the cost of the 830 MW of build-out of the offshore wind. Looking at the total pot is where we would focus, not specifically assign it to one area.
No, I understand that. If you didn't have the offshore wind, how much equity would you be issuing?
Well, you're asking it in the same way, only differently.
No, you're good, Phil.
Yeah. As I said, the $2 billion of equity supports kind of our total CapEx and offshore wind plan for the next time.
Okay, let me ask you a different way then. What's the proper capital structure for an offshore wind project?
Well, that one you did miss, Andy, because we talked about that earlier.
Okay. There you go. What's the bottom line on that?
That's the competitive process, obviously.
Oh, okay.
We're not going to disclose the cap structure or the capital cost.
I guess your return on investment or however you measure it, must be based on how you finance it, right?
Correct.
Okay, at some point, will you share that with us?
Yeah. 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 transition-like or better, when you look at sort of the returns on equity that we would expect there.
Okay. That's assuming that everything goes as planned, or do you have a contingency built into that?
We work with Ørsted in building appropriate contingencies, not only in terms of spending, but in terms of schedule.
Got it. Okay. That's very good. Thank you very much.
Thanks, Andy.
Thanks, Andy. Next question is from Michael Weinstein from Credit Suisse. Good morning, Mike.
Hey, guys. Just one quick follow-up. I just wanted to have you explicitly say that, just confirm, that you basically have 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.
Right. There's a certain amount that's why the equity might look high to some people, because it's not as part of that $12 billion-$13 billion CapEx plan.
That's exactly correct, Mike.
Okay, you're not saying how much.
That's correct also. Yeah.
Okay. Just wanted to get that out there. Thank you.
Thank you.
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.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for joining. You may now disconnect.