康涅狄格電力 (ES) 2019 Q4 法說會逐字稿

Welcome to the Eversource Energy Q4 and Year-end 2019 Results Conference Call.

My name is Paulette, and I will be your operator for today's call.

(Operator Instructions) Please note that this conference is being recorded.

I will now turn the call over to Jeffrey Kotkin.

You may begin.

Thank you, Paulette.

Good morning, and thank you for joining us.

I'm Jeff Kotkin, Eversource Energy's Vice President for Investor Relations.

During this call, we'll be referencing slides that we posted last night on our website.

And as you can see on Slide 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, 2018, and our Form 10-Q for the 3 months ended September 30, 2019.

Additionally, our explanation as to how and why we use certain non-GAAP measures and how those measures reconcile to GAAP results is contained within our news release and the slides we posted last night and in our most recent 10-K.

Speaking today will be Jim Judge, our Chairman, President and CEO; and Phil Lembo, our Executive Vice President and CFO.

Also joining us today are Werner Schweiger, our EVP and Chief Operating Officer; Joe Nolan, our EVP for Strategy and Customer and Corporate Relations; John Moreira, our Treasurer and Senior VP for Finance and Regulatory; Jay Buth, our VP and Controller; and Mike Ausere, our VP for Business Development.

Now I will turn to Slide 2 and turn over the call to Jim.

Thank you, Jeff, and good morning.

Thank you, everyone, for joining us today for our review of 2019 results and for our updated long-term outlook.

I'll start by thanking our 8,300 Eversource Energy colleagues for just a terrific 2019 and for the very bright future we expect for our company and our customers.

As you can see on Slide 4, our investors benefited from a very strong total return of 34.4% in 2019.

That return was 860 basis points ahead of our peer index and nearly 300 basis points ahead of the S&P 500 total return in 2019.

And as you also can see on this slide, our 3-year, 5-year and 10-year performance has consistently beaten our peer index as well as the broader market.

And as the January 2020 performance comparison shows, we're off to another strong start this year.

That constancy of shareholder return is directly related to our solid long-term record of operating performance.

On Slide 5, you can see the results of our commitment to continuous improvement in our operating metrics related to reliability, safety and emergency response.

They are in the top-tier of our industry and the top decile of our industry peer group for reliability.

That execution and the drive to provide ever-improving service to our 4 million customers here in New England form the linchpin of our strategy.

By excelling at our basic business, we enjoy strong credibility with our regulators and other state and federal policymakers.

Our leadership position on energy issues is also enhanced by our strategy of being a catalyst for clean energy development in New England and for our efforts to strive for best-in-class governance, employment policies, safety programs, energy efficiency support and leadership in our communities.

Some of the organizations that have recognized our leadership over the past year are listed on Slide 6. The credibility generated by our strong operating performance helps us achieve very tangible results, especially in areas such as structuring long-term rate deals in our regulatory jurisdictions or entering new business ventures, such as water and offshore wind.

We have a prominent seat at the table as our business strategy aligns very well with the energy, economic and environmental goals of the region.

All New England states are targeting at least an 80% reduction in greenhouse gas emissions by the year 2050.

This is a very ambitious goal, especially given that nearly 50% of those emissions today come from the millions of motor vehicles that cross our thoroughfares daily.

In December, we announced that we will support these efforts by setting a goal of making Eversource carbon neutral by 2030.

That's the most ambitious goal of any energy utility in the United States.

And as you can see on Slide 7, we have already reduced our carbon emissions by approximately 70% over the past few years, primarily by divesting our fossil generation in New Hampshire.

From here, our efforts will focus on the combination of improving the efficiency of our electric grid, further accelerating the replacement of older cast iron and unprotected steel natural gas distribution pipes; changing our fleet to include more hybrid and electric vehicles; and increasing the energy efficiency of our buildings.

Setting this aggressive carbon reduction goal makes us more attractive to ESG-focused investors, who now comprise about 10% of the 1,600 domestic and international funds currently invested in Eversource shares.

Our clean energy strategy is further enhanced by our partnership with Ørsted to build at least 4,000 megawatts of offshore wind off the coast of Massachusetts.

This build-out is incremental to our goal of making our operations carbon neutral by 2030.

Slide 8 provides a status report on the 1,714 megawatts we have won thus far through successful bids into Rhode Island, Connecticut and New York RFPs.

As you can see on this slide, we have secured approvals of the long-term agreements we have under contract.

So clearly, the focus ahead is on siting approvals.

This year, we expect to file our construction and operations plans for our two large projects with the Bureau of Ocean Energy Management, or BOEM.

We expect to file Revolution Wind in the first half of 2020 and Sunrise Wind in the second half of the year.

Those filings would be consistent with our expectation that Revolution will have its first full year of operation in 2024, and Sunrise will have its first full year of operation in 2025.

We continue to target operation of the first and smallest of these three projects, South Fork, by the end of 2022.

We are currently reviewing that schedule in light of BOEM's recent announcement that it will not complete its cumulative impact study on the six tracts off Massachusetts until mid-June.

That study is part of the Vineyard Wind application, but will likely encompass all of the tracts.

The pricing of most of our PPAs is public and noted on this slide.

In December, Congress passed and the President signed legislation extending for one year and increasing over 2019 levels both investment tax credits and production tax credits for construction commencing in 2020.

We applaud this extension, which supports this rapidly growing industry, and we expect to qualify for 18% tax credits on our three projects.

As you know, while we were successful in the New York RFP last year, we were not successful in the Massachusetts RFP or the Connecticut RFP, both of which were awarded in the fall.

While the Connecticut pricing is not public, the Massachusetts pricing was made public with the contract filing this month.

Like the first Massachusetts RFP in 2018, the pricing in the most recent RFP would not be sufficient for us to earn our targeted mid-teen returns.

So although disappointed, I was comfortable with our bid not being selected.

As I have said to both the Ørsted Board and the Eversource Board, we control the two best ocean tracts that BOEM has auctioned off in New England.

They are the closest to shore, which you can see on Slide 9 and should be the most economic to develop and maintain.

Between New York, Connecticut, Massachusetts and Rhode Island, there will likely be at least 15,000 megawatts of contracts available to developers over the coming years.

The last thing we would want to do is lock ourselves into contracts for 20 to 25 years that would not allow us to earn our targeted returns because we bid too aggressively.

We consider our sites to be a tremendous competitive advantage, and we'll be disciplined in our biddings.

We take an additional few years to reach the 4,000 megawatt capacity for our tracts, we are fine with being patient and preserving our potential returns.

In the meantime, all four developers of the tracts off Massachusetts achieved a significant milestone late last year, when we committed to BOEM and the Coast Guard that we would coordinate our development to provide one nautical mile spacing between offshore wind turbines, both East-West and North-South across all parcels, creating a grid-like configuration.

We believe this is a very positive development in addressing the concerns of both the region's fishermen and the Coast Guard.

In late January, the Coast Guard published a notice for public comment indicating that this one nautical mile by one nautical mile configuration will create adequate spacing for search and rescue operations and would maintain safe ship navigation.

Earlier this month, Connecticut governor, Ned Lamont, announced a public-private partnership that will result in up to $157 million being invested in refurbishing the New London State Pier as a staging ground for offshore wind construction.

This innovative partnership into which Eversource and Ørsted together will invest a projected $77.5 million will allow Connecticut to realize significant economic development benefits from this new clean energy source.

So to conclude my offshore wind comments, I want to emphasize what a great opportunity this development is for our region, for our customers and for our company.

The area off the Massachusetts coast is perhaps the best place for offshore wind in all of North America because of the year-round wind speeds, the shallow depth of the waters and the proximity to Southern New England load.

I believe our two parcels are the best situated of the six parcels that BOEM has auctioned off, and our partner Ørsted is the best and most experienced developer of offshore wind in the world.

Perhaps most importantly, offshore wind is in the sweet spot of public policy, providing billions of dollars of economic development benefits to our region and benefiting from widespread support from public policymakers, the business community and environmental groups.

As a result, I could not be more optimistic about the future of our offshore wind business.

As a reminder, our offshore wind opportunity is incremental to the solid growth prospects we foresee for our core business.

As you can see on Slide 10, we have grown earnings per share by approximately 6% on average since the 2012 merger that created Eversource.

We expect to continue to grow earnings per share by 5% to 7%, solely through the growth of our core regulated utility business.

And that 5% to 7% growth excludes earnings from the two large offshore wind projects that we expect will produce significant additional EPS growth in 2024 and 2025.

As shown on Slide 11, a key element of our total return profile remains our dividend growth.

With our solid earnings growth and conservative payout ratio, we consider our dividend to be extremely well supported, with a growth trajectory similar to our 5% to 7% EPS growth.

Earlier this month, the Eversource Board of Trustees approved a 6.1% increase in our quarterly common dividend.

That increase underscores our confidence in our long-term earnings growth and business strategy.

Now I'll turn the call over to Phil.

Thanks, Jim.

And today, I'll cover our results for 2019, discuss the earnings guidance for 2020, and the key drivers that support that.

I'll provide an update for you on our five-year CapEx plan and our 5% to 7% EPS growth and review the outstanding regulatory items we have pending.

I'll also cover briefly what our financing plans are for the year 2020.

I'll start with Slide 13 and our fourth quarter and full year results for 2019.

Our GAAP earnings were $2.81 per share in 2019, including a $0.64 Northern Pass charge we recorded in the second quarter.

Excluding that charge, we earned $3.45 per share in 2019 compared with earnings of $3.25 per share in 2018.

The $3.45 was a 6.2% increase and right at the midpoint of the earnings guidance we provided you a year ago.

In the fourth quarter of '19, we earned $0.76 per share compared with earnings of $0.73 in the fourth quarter of 2018.

Now some specifics about the quarter and year.

Earnings for our electric distribution segment were $1.59 per share in 2019 compared with $1.44 in 2018.

They were $0.28 per share in the fourth quarter of '19 compared with $0.24 in the fourth quarter of 2018.

So both the full year and the fourth quarter results improved primarily as a result of higher distribution revenues.

These were partially offset by higher depreciation and operation and maintenance expense.

The transmission segment earned a total of $1.43 per share in 2019, excluding the Northern Pass charge compared with $1.34 in 2018.

They were $0.36 per share in the fourth quarter of 2019 compared with $0.31 in the fourth quarter of '18.

The higher full year and fourth quarter earnings primarily reflects an increased level of investments in our transmission facilities.

Our transmission rate base ended 2019 at an estimated $7.26 billion compared with $6.75 billion at the end of 2018.

Transmission capital expenditures totaled slightly more than $1 billion in 2019 or about 3.5% higher than the year previous.

Earnings from our natural gas segment totaled $0.30 per share in '19 compared with $0.29 in 2018.

Fourth quarter earnings were $0.12 per share in 2019 compared with $0.14 in 2018.

For the full year, higher revenues were largely offset by higher operations and maintenance costs, depreciation, higher property tax and interest expense.

The fourth quarter decline was due to higher O&M and depreciation expense, as well as the absence in 2019 of a benefit that we received in 2018 related to our Yankee rate case.

Full year earnings from our water distribution segment totaled $0.11 per share in 2019 compared with $0.10 per share in 2018.

Fourth quarter earnings in our water distribution business were $0.02 per share in 2019.

That's up $0.01 over 2018.

Improved results for the quarter were due in part to higher revenues, lower interest and operating expense.

At the parent and other, we earned $0.02 per share in 2019 compared with earnings of $0.08 per share in 2018.

The decline occurred largely in the fourth quarter when the parent lost $0.02 per share compared with earnings of $0.03 per share in 2018.

This was due in part to a $0.02 per share gain in 2018 relating to the results of a regulatory decision, allowing recovery of certain merger-related costs by Yankee Gas.

It also resulted from a higher effective tax rate in 2019 than we had in 2018.

Turning to Slide 14.

Our earnings per share guidance for 2020 is the range of $3.60 to $3.70 per share, and this is consistent with our long-term growth rate expectations.

The primary drivers of earnings growth are expected to be our continued investment in our transmission system and the positive impacts of our multiyear regulatory plans in place for our electric and natural gas distribution businesses.

In the first half of this year, we are implementing electric distribution base rate adjustments, totaling more than $60 million and a natural gas rate adjustment of nearly $16 million.

Additionally, as I will discuss shortly, we have rate requests pending at one of our electric subsidiaries and one of our natural gas distribution companies.

Also contributing to earnings growth would be the impact of infrastructure investment tracking mechanisms in place for our electric and natural gas distribution segments.

These involve safety programs and pipe replacements in our gas business.

Offsetting these benefits are expected increases in depreciation, interest cost and property tax expense.

Also, we'll have higher share count in 2020 as a result of the equity sale last June and closing out the forward by the end of May of this year.

From 2020, I'll turn to Slide 15 and our long-term capital investment forecast.

Over the next five years, we are projecting capital investments of $14.2 billion from our core electric, natural gas and water business as well as the supporting information technology and facilities investments.

These investments are focused on providing reliable service to our four million customers across three states.

In our electric transmission segment, we expect to invest approximately $4 billion over the next five years.

As a result, by the end of 2023, we expect our regulated transmission rate base to be $9.4 billion.

That's approximately $1 billion higher than we had estimated just a year ago.

And then we expect the rate base to be at $9.6 billion by the end of the forecast period in 2024.

Turning to Slide 16.

You can see that in just the years 2020 through 2023, our capital investments are expected to be $1.6 billion higher in those time periods than what we had forecast at this time a year ago.

This increase is primarily driven by investments in our electric transmission segment.

For the years 2020 through 2023, capital investments in electric transmission are expected to increase by about $1 billion.

We have multiple drivers affecting this increased level of spending, and they're all related to providing reliable service in supporting our region's clean energy goals.

For example, we're increasing the use of drones to better inspect our transmission equipment.

High-resolution drone photography is allowing us to identify damage of failing equipment much more effectively and efficiently, allowing us to accelerate the replacement of at-risk equipment before it can cause reliability problems for our customers.

In addition to replacing older equipment, we also need to address some notable areas of growth.

While overall our electric loads are flat to lower, we are installing additional equipment to address significant customer growth, particularly in pockets of Boston and Cambridge, Southwest Connecticut and coastal New Hampshire.

We also need to add equipment to better integrate the renewable energy that continues to come online to maintain voltage and reactive capacity.

On the electric distribution side, we project investments of approximately $6.1 billion over the next 5 years.

From 2020 through 2023, we project nearly an additional $400 million investment compared to last year's forecast.

Our investments are helping to drive the excellent top-tier reliability performance that Jim identified earlier by improving the resiliency and reliability on our systems, addressing continued economic growth, and at the same time, helping to drive our O&M costs out of the system.

Much of the increase in our distribution capital program since last year's forecast is driven by substation investments in the growth regions that I mentioned earlier, such as Greater Boston.

We also continue to invest in the DPU-approved grid modernization program in Massachusetts.

You may recall that in late 2017 and in the first half of 2018, the DPU approved $233 million of investments, including $55 million for 2 battery storage projects, $45 million for electric vehicle infrastructure that connects 3,500 charging points and an additional $133 million for technology enhancements on our distribution system.

We had initially expected these investments would be completed over a five-year period, but we now expect nearly all the work to be complete in a 3.5-year or less period or by early to mid-2021.

Additionally, in 2018, the DPU instructed us to file an additional three-year plan by mid-2020 to cover the years 2021 through 2023.

In our capital investment forecast, we have included approximately $290 million for that new 3-year plan in Massachusetts.

There are a few changes in the natural gas and water distribution segments, where capital investments more closely resemble the plan we showed you a year ago.

The increased investment in our natural gas distribution system during the years '20 to '23 is primarily at NSTAR Gas, where we have a number of additional resiliency projects plus continued execution of our pipe replacement program.

And we have similar work underway at Yankee Gas.

At Aquarion, on Slide 17, we provided you with an updated Aquarion rate base estimate that now reflects the expected sale of certain water facilities around Hingham, Massachusetts, to the town.

We expect the sale to close in the second half of this year, and we expect to receive more than $100 million for these facilities, a valuation that was prescribed following a state court review.

More than 90% of Aquarion Water's rate base is located in Connecticut, and much of the capital investment over the coming years will come not only from replacing older, less reliable pipes, but also from new projects that bring additional water supplies into Southwest Fairfield County, where currently, summertime irrigation is restricted, some of you may know about that.

More specifics about that extensive work are shown on the slide in the appendix.

From what is included in our capital forecast, let's turn to Slide 18 and discuss some of the items that are not reflected in the forecast.

On the electric distribution side, the forecast does not include grid modernization investments in Connecticut or New Hampshire.

Connecticut regulators have opened a number of dockets related to grid modernization such as storage and electric vehicle charging infrastructure, and are pursuing them aggressively with regular public input sessions.

But because those dockets are not yet complete, we have not included any such investments in our plan.

Similarly, while we have proposed several innovative grid initiatives in New Hampshire, including a battery storage project, as these initiatives are not yet approved, we have not included any of these investments in our current plans either.

We are not reflecting any investment in advanced meter infrastructure, or AMI, in any state.

In Connecticut, there is an active AMI docket now underway as part of its grid modernization review.

Massachusetts regulators have indicated that they will open the review of AMI in other customer-facing technologies, although no specific time frame has been established at this time.

We currently estimate the total investment needed to switch over all of our electric and natural gas customers to AMI in the two states, Connecticut and Massachusetts, to be approximately $1 billion.

But it's unclear at this time if or when AMI might be authorized by regulators.

We are also evaluating a recent report issued by Dynamic Risk Assessment Systems, the consultants working for the Massachusetts DPU, to determine if we will need to make any incremental capital expenditures on our Massachusetts gas distribution system.

These investments would be needed to meet evolving state safety requirements.

No additional investments have been included -- have been identified or included at this time in our forecast.

As you can see on Slide 19, the level of investment in our plan will produce a rate base CAGR of 6.9%, nearly 7% from year-end 2018 through 2024.

This rate base growth underscores our high confidence in the core business, producing an EPS CAGR of 5% to 7%, and as we've said in the past, we believe we will be somewhere around the middle of that range.

Earnings from our major offshore wind investments will be incremental to the core business 5% to 7% CAGR.

In years when we are not adding any offshore wind, we expect to be solidly in the 5% to 7% range.

As Jim said, in periods immediately after we bring a large offshore wind project into service, earnings growth is likely to be significantly above the 5% to 7% range.

We expect those high-growth periods to be the 12 months after first Revolution Wind and then Sunrise Wind enter into service.

As you know, for competitive reasons and because we're still early in the siting process, we have not discussed our expected total investment in these projects.

So I will say that we are expecting to invest $300 million to $400 million in the offshore wind business in the year 2020.

As we've previously said, we expect to capitalize the projects with a 40% to 45% equity and 55% to 60% debt percentage.

That's consistent with our current Eversource capitalization.

And as we've said, we continue to expect to earn mid-teens returns on the equity in these projects once operational.

As noted on Slide 20, core business earnings growth is not just tied to rate base growth and the associated CWIP.

There are other items.

First, some of the regulated segments, particularly Massachusetts and New Hampshire distribution earned below their authorized returns in 2018, and we are expecting a significant recovery from these levels going forward.

Second, as our highly regarded energy efficiency programs grow, so do potential incentives we receive for doing an exceptional job.

Third, we are conservatively modeling nominal O&M to be relatively flat during the 5-year forecast period compared with 2019 levels.

The bottom line is, we're very comfortable that our regulated segments alone will support the 5% to 7% earnings growth, and again, somewhere in the middle of that range.

From our growth rate, I'll turn to two active rate cases, one in New Hampshire, at Public Service of New Hampshire; and in Massachusetts at NSTAR Gas.

Slide 21 shows the status of these rate cases.

On the left-hand side, you'll see the PSNH filed a rate case last year, seeking a $70 million increase in base distribution rates.

Following the settlement with the staff, the New Hampshire Public Utilities Commission approved a $28 million temporary increase that will remain in effect until the PUC implements a final decision on the permanent rates.

We expect that decision in May with an effective date of July 1. The New Hampshire PUC process includes a number of days devoted to settlement discussions and the schedule targets April 7 for the filing of the settlement, if we're able to negotiate one.

Regardless, hearings will take place in April, and historically, most New Hampshire rate cases have been settled.

At NSTAR Gas, we filed an application in November of last year to raise distribution rates by $38 million effective October 1, 2020.

We also requested a performance-based rate mechanism similar to the one approved for NSTAR Electric in its rate case in late 2017.

Such a mechanism would tie rate adjustments in the future to inflation measures in years two through five of a 5-year plan.

We expect this rate case to be fully litigated as was the NSTAR Electric case.

Worth noting is that our three largest distribution franchises are currently under multiyear rate plans, and we anticipate no new base rate plans for these franchises to be effective before 2022.

Turning from the states to the FERC information on Slide 22.

There's been significant FERC ROE activity since our November earnings call, but none of it directly related to our four pending complaints against the ROEs identified by the New England transmission owners.

In a recent decision that was quite disappointing to us, FERC ruled in November of '19 that it would abandon two of the four methodologies it had earlier suggested it would use in determining just and reasonable ROEs.

Instead, it said it would focus solely on discounted cash flow and CAPM mechanisms.

Many parties requested reconsideration of that ruling, and FERC appears to be considering reviewing its decision in the -- in that MISO case.

In the meantime, we continue to book earnings at the same rate at which FERC has ordered us to bill customers.

That includes a base ROE of 10.57% with a project cap of 11.74%.

We have billed at the same rate since early 2015 and do not expect to change it until FERC rules on the New England case.

Turning to Slide 23.

I'll review the status of our equity issuance.

As you may recall, we closed immediately on one-third of nearly 18 million shares that were issued and sold in June of 2019.

So the issuance at that time was just under 6 million shares.

The remaining nearly 12 million shares was subject to a forward share purchase arrangement.

On December 30, we closed on an additional 6 million shares of the forward, and we'll close out the remaining approximately 6 million shares by the end of May of 2020.

Also, last year, we used about 1 million treasury shares to fund our dividend reinvestment and certain employee incentive and retirement plan obligations.

We had expected to issue about 1.5 million shares last year.

But because of our higher share price, we've reduced that rate of issuance.

Later in the forecast period, we expect to implement an at-the-market program to address any equity requirements that exist.

At this time, we expect to issue approximately $700 million in new equity.

This is the same number that we've discussed for over a year now through such a mechanism during the forecast period.

We'll continue to evaluate our financing needs as we move through the forecast period, but we have no additional equity in the forecast.

We're very enthused and confident we'll be able to accomplish this ambitious plan we described to you this morning.

The plan will allow us to fulfill our work on behalf of our customers, while supporting energy policies of the states, which they've adopted.

Slide 24 illustrates some of our track records, and it illustrates the targets we've set for ourselves over the past eight years, and how we've been successful in meeting or beating them, delivering significant benefits to our customers and value to our investors.

Thanks, again, for your time.

I'll turn the call back to Jeff.

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

(Operator Instructions)

Thank you, Paulette.

Our first question this morning is from Mike Weinstein from Crédit Suisse.

Can you explain how -- why do you think the bids are coming in so low for Massachusetts offshore wind auctions?

And what gives you confidence that you can eventually win further auctions going forward if the bids are coming low?

Sure.

This is Jim, Mike.

The -- we can't sort of rationalize some of the pricing that other bidders have put in there.

Obviously, the returns that they expect are lower.

It may be an instance where they're trying to buy market share.

But if you -- as we talk here today, Ørsted and Eversource, that joint venture is the largest developer of offshore wind in North America based upon the 1,714 megawatts that we have contracted.

So we see the glass as half full rather than half empty.

We've won some bids that are going to be profitable for us.

We will continue to be selective in opportunities.

I would say that more so than the other states, Massachusetts has clearly been focused on price and price alone, whereas other states have looked for other contributions to the state via the economic developments or what have you.

So Massachusetts has clearly shown themselves to be a state that's focused primarily on price, and we'll look for opportunities.

It's currently over 25,000 megawatts of offshore wind legislated in the Northeast.

15,000 megawatts alone when you look at New York, Connecticut, Massachusetts and Rhode Island.

And only about 1/3 of that has been contracted for us.

So we're pretty excited about the opportunity here and the timing will fit with our financial discipline, making sure that we win bids that are profitable.

Got you.

And also, do you expect to continue excluding offshore wind earnings from forward earnings growth projections and future updates?

Or do you think you might raise the guidance range at some point, maybe next year?

Mike, this is Phil.

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

Got you.

One last question here.

Can you explain how offshore wind will qualify for the PTC extension?

I think initially that was supposed to apply only to onshore projects, but I understand there are some ways that they can be applied to offshore, but I'm -- maybe you can explain that a little bit?

Mike, it's Jay Buth.

We -- when we kind of look at this in totality with the portfolio, we do read, when we kind of read that language and we talk to some of our advisers, we do see an avenue for the PTC extension to be potential for that offshore wind business.

We do have some other strategies that we're looking at deploying from a qualification standpoint as well.

So we do feel pretty confident in terms of our qualification realms.

Next question is from Insoo Kim from Goldman.

First, regarding financing, how much of the Sunrise Wind construction costs are you assuming would be funded by the initial cash flows from Revolution Wind?

And depending on the timing of the permitting and potential delays, at what point would your future equity needs change and the potential magnitude of that?

Well, I'd -- that requires some speculation on my part.

I'd say that we're confident with the schedule that we have that we're able to finance our construction programs that we have in place for both our core business as well as the wind development with our cash flows from our business.

The cash flows are all fundable.

We -- there are flows from the core business, and there will be cash generated from revenues or tax benefits from the offshore wind that would be used to help finance the whole portfolio of capital that we have.

So as I said, right now, looking at the forecast, we have no new equity needs in there other than to complete what we've already indicated in the past.

And we're confident we'll be able to do that.

Understood.

And maybe a little bit bigger picture, Jim, obviously Eversource has benefited from its favorable ESG characteristics, including the strategy on offshore wind.

When you just look out longer term at your portfolio mix, could you just update us a little bit on your thoughts on what the optimal mix is?

Whether it's on the offshore renewable front or on the water utilities front or anything else that you may be contemplating?

Well, I think we're pretty pleased with our core business.

I think we've perceived as an excellent operator, whether you look at electric, gas or water.

I do think in the renewable space, we have taken advantage of opportunities to develop utility-scale solar, where we have that opportunity.

And obviously, offshore wind is a growing opportunity for us as well.

I wouldn't say that we have a target mix between each sector.

The water sector is -- I continue to believe is something that begs for a sort of roll-up.

Unfortunately, when you look at how water utilities trade currently at such a high price, it's hard to make the math work and make it accretive, which has always been our threshold for deals.

So we'll look for opportunities to grow the business.

We'll be selective and disciplined as we have in the past, but we're pleased with each one of the legs of the stool.

Next question is from Steve Fleishman from Wolfe.

Just a couple of questions related to offshore wind.

So could you just maybe give some sense on why the timing delays and the broader impact from BOEM?

And also just -- I think there is some opposition to the mile-by-mile configuration.

So just could you give a sense on your conviction on getting that approved?

And then finally, just how are you feeling about your cost assumptions that you've put into your projects, given just the latest view of cost to build the projects and any impact of delays?

Okay.

Jeff, you keep me honest here in terms of the questions.

I think the offshore wind, one of the things that we're pleased to see was our fit would be a good degree of granularity provided by BOEM with the dates that were provided at the Vineyard Wind proceeding all the way through the record of decision date.

I think people realized that delays at Vineyard Wind may have some impact on other developments.

We certainly hope that, that's minimal.

Obviously, the cumulative impact analysis that's due on June 12 will provide some guidance of schedules going forward.

Eversource and Ørsted, we filed a very robust and complete and high-quality COP filing for South Fork.

So I expect that that can help expedite our approval once BOEM has completed their cumulative impact analysis.

On the mile-by-mile, while there's still maybe some opposition to that design, there has been sort of a coalition.

The Coast Guard has come out in favor of it.

They think that it provides adequate distance for mariners to travel safely and for the fishing community.

We think it basically addresses the primary hesitation or concern that BOEM had when they did stall the Vineyard Wind process.

In terms of cost assumptions, we are continuously looking at project construction, not only cost but schedules and opportunities to improve them.

I'm happy that the partner that we have, Ørsted, their track record and the way that I've seen the costs develop tend to include some conservatisms and contingencies that look to be appropriate.

So we're continuously reviewing and testing those cost assumptions.

And right now, we're very comfortable that what we see is consistent with the returns that we've provided the Street midterm -- mid-teen returns on equity.

Next question is from Paul Patterson from Glenrock.

I wanted to just touch base again on Slide 19 and the CWIP number.

How do you guys expect that to go?

What's your trend expectation with respect to that over this forecast period?

In terms of the CWIP number, Paul?

Yes.

Yes, typically, that would move up during the forecast period, just given our level of construction activities.

I don't have a specific rate of increase that I would give you.

But I would say that we would see that number as increasing during that period.

Okay.

And then with respect to the -- just one more thing on the offshore wind.

There was this independent evaluator report that came out on Friday, in which they discussed the potential for the Mayflower project to be re-bid and as being a potential opportunity for you guys.

I was looking -- I was just wondering if you guys have any thoughts about that potential?

Or...

Well, I can't speculate.

I think I did see something that suggested that the winning bid was close to the second bid.

And some people are making a case that, that winning bid may be a higher risk and should be reassessed.

But I don't have any perspective or insight as to what will be done with that.

Okay.

And then with respect to transmission, there have been several dockets filed at FERC, some dealing with ISO New England with respect to competition.

There are a number of different cases that are basically kind of the offspring of FERC Order 1000, it seems like in terms of compliance in efforts to -- for cost containment, what have you.

And I was wondering what your thoughts might be in terms of this apparent effort on the part of FERC to broaden or to reassert this sort of competitive effort with respect to transmission projects?

Well, I think we've seen ISO respond.

They issued an RFP in December to address transmission needs due to retirements of Mystic 8 and 9. I think it's expected sometime in 2024.

And there's a schedule in the process for competitive bids to be submitted in March.

Eversource and National Grid will be obligated to propose backstop solutions against which qualified business developers can bid.

So -- and there is competition in New England with sort of the major projects that's on the line.

Right.

But they're talking about things like the immediate needs stuff and supplemental projects.

And I'm just wondering, I mean, should we look towards this Mystic one that you just mentioned as perhaps being a data point with which to see how this competition thing works out?

Or I'm just sort of wondering, in general -- I mean, we don't have any -- we have these so-called thing that came out and what have you.

Those types of filings and what have you, responses to them.

So we're sort of early in the process, but I was just wondering, I mean -- if you think this could potentially have any impact on your forecast in terms of transmission investment and what have you?

Well, I don't think so.

I believe that the -- some of the reliability concerns that Phil mentioned in terms of structure replacements that have been identified and more of them were find -- were found with the use of drones, identifying vulnerabilities with the federal government's focus on reliability in the transmission system, in particular, I think you're going to see the incumbents continue to be the one to address particular near-term fixes that need to be -- or upgrades that need to be required by the system.

Okay.

And then just back on the grid mod in Connecticut that Phil touched on.

I'm sorry if I missed this, but what -- when do you think we're going to actually get something out of there?

I mean, as you mentioned, there are several proceedings, it's kind of difficult to monitor.

When do you think we might actually see some actual sort of concrete proposals or what have you coming out of that?

Yes.

So Paul, you're right.

There's almost a dozen.

I think there's actually 11 different dockets that are active, and the Connecticut process has been inclusive, and they've really stuck to schedule.

I mean they've been aggressive in terms of going through the particular topics.

But I will admit that I don't have a particular target date, not -- one has not been published at this time.

But we expect to see something move in the first half of 2020.

I don't -- what I've said before, I believe, to still be true is you're not going to see like one item with all 11 come out.

You'll probably see some piecemeal one or two of the 11 move forward in the first half of this year, but I don't have any more specifics on that.

Yes, I think the ones that they seem to be interested in battery storage, EVs or certainly programs that we have in place already in Massachusetts.

And those are in kind of the top of the list at -- in Connecticut right now.

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

Team, congratulations.

So perhaps to keep going a little bit in the same direction as Paul here.

But turning back to Slide 18, talking a little bit and trying to quantify, if you will, some of these upsides.

I know you said specifically, AMI was $1 billion still, that seems unchanged.

Can you talk about, a, the time line, if there are any kind of data points we should be tracking?

And then separately, for the other 2 bullets here, I know it's difficult to put your finger on any kind of specific numbers.

But as you begin to assess the quantum overall of capital here, how would you frame those other two?

I get it's difficult, but at least initially, especially on the Massachusetts gas side, where I know that there are some data points coming up here.

Yes, Julien, this is Phil.

In terms of one of the -- following on to Paul's comment, one of the 11 items has to do with AMI in Connecticut, and there does seem to be some interest there.

And one or the other utilities operating in the state has implemented at least a partial AMI solution that's out there.

We've said in the electric and gas in Massachusetts and Connecticut, that's about $1 billion.

And that likely would be spread over a four-year, five-year time period.

You're not going to get all of that spending in at once.

So I'd say that Connecticut is probably ahead of Massachusetts in that regard in terms of, at least there's a docket out there and a framework to start looking at.

So that could be something you see in 2020, at least a direction.

In terms of Massachusetts, they have indicated and they continue to indicate they want to have more of a generic docket looking at AMI and other customer-facing items, but have not yet set a date for that.

I'm not sure if there's one on the drawing board, but I'd say that's probably something that's going to at least kick-off during this year.

I don't have any more time line for that.

So again, half of our customers are -- it's kind of a 50-50 split between the two.

So I mean, realistically, you'd say, half of the $1 billion is in each of the states.

In terms of the gas assessments, that's come out, and we've been asked, and all the companies are preparing information now to be responsive to that assessment.

So I would say we should know within a relatively short period of time, if there's any incremental spend out of that.

And something to keep in mind that I just wanted to remind folks on, it's sort of in our gas filing in Massachusetts, we saw that this was coming, right?

We didn't know what might come out in terms of the spending level, but we knew that this report was out there.

So in the filing that we already have underway in Massachusetts for the gas case, we already have a carve-out tracker with zero in it right now that we're proposing to say, look, we don't know what's going to come out, but likely something will and we will have a place for it.

So we won't have to wait five years to go back and get our recovery for it.

So we planned ahead not knowing exactly what the numbers were or what would happen, but we at least have the mechanism lined up there.

So again, as you suggest, it's a little bit early to speculate there, but there could be some hundreds of millions of dollars between all of these that would be incremental.

Got it.

And then just going -- sorry to nitpick a little bit further on one of your specific angles here, but this notion of fuel security here.

I know you guys have kind of talked broadly about Mystic here, but more broadly, that seems to highlight some of the acute issues potentially here.

We saw some FERC actions very recently.

Is that another angle that, I know, we've kind of alluded to here, but I'll leave it open-ended in the Boston area, and more broadly, when you think about winter?

Yes.

I'm not -- it is open-ended.

I'm not really sure what you're asking about?

Sorry.

What I was getting after is, obviously, if Mystic 8 and 9 go away, and in general, you have this open question as to enabling the retirements of these urban large-generation sources.

Are there opportunities that open themselves and afford themselves sort of in the here and now to backstop or enable these retirements otherwise?

I think the -- this is Jim, Julien.

The competitive FERC 1,000 solicitation will sort of reveal a number of opportunities that have been created to address the challenge of Mystic 8 and 9 going away.

So I don't want to speculate on what they might be.

We'll see soon enough.

Next question is from Travis Miller from Morningstar.

Just wondering on -- going back to this transmission and that idea of upside on the transmission as we get out to the 2023, 2024.

Wondering if you could characterize the gating factors, for a lack of better term, that might be coming there?

Is there a policy change?

Is it FERC change?

State change?

Wondering what might lead to some of those extra growth projects that are not in the forecast right now?

Well, I'll have Phil add on.

But one observation I'd make, Travis, is that Jeff Kotkin is the best IR guy in our industry, and that's not me saying that, that's all you folks on the phone saying that because he wins the II award every year.

And one of the reasons he does is he provides a lot of granularity on our capital spending plans going forward.

And there's a long history here of providing a CapEx forecast, and he provides it based upon projects that are already in the queue that we're aware of, that are in our plan.

Obviously, we know more about projects that are in our plan for 2020 than we do for 2025 right now.

And so if you look, every single year since the merger in 2012, we have updated the CapEx forecast going forward, and it has increased and it's -- basically because we're more aware of future needs going forward.

So there are projects that are out there that we're not aware of right now that will be in the mix.

And that's not just transmission, but distribution, electric and gas and water business as well.

I don't know if you want to add to that, Phil?

Yes, I'd just add, in terms of a couple of categories is, I talked about connecting distributed resources to the system.

I think we have about 2,600 distributed -- megawatts of distributed energy resources in our territory now.

So as policies progress and as clean energy connections are required, I think that could be a category that expands in that time period.

So nothing to put in there yet, but that's certainly a driver.

And each year, we're spending more on cyber and physical security and things like that so that the ramp-up in that particular category seems to get higher and higher each year.

So those might be a couple of categories that could move spending up as you move out in the forecast.

Okay.

And then just within that, are there any large project opportunities that you see -- as you look out kind of that five-year trends, I think, transmission window.

Are there any areas where you'd see, hey, this could be a possible large project opportunity, let's call it, $400 million, $500 million type of thing?

Yes.

Right.

Actually, just the opposite.

I'd say our forecast now includes more smaller projects, more bite-size inside the fence.

As I said, cyber is certainly an issue.

I'd say the largest single project that we have now is our Seacoast Reliability Project that we have as a single project.

All the other transmission is really groups of smaller activities that we're doing for reliability and to improve the reliability for our customers.

So we don't see any big projects out there.

Next question is from Andy Levi from ExodusPoint.

I agree what you say about Jeff.

So just, I guess, a follow-up from an earlier question.

You were -- I know this is something that you had commented on, Jimmy.

So just on the spacing relative to the offshore wind.

When do you guys find out what the final kind of outcome of that spacing is?

I guess, we're what 1 mile by 1 mile now is -- or is that...

Yes, 1 x 1 mile And fortunately, we were the first ones to agree to go to that design a while ago.

And so we're probably further along than others in terms of development of COPs that need to be filed with the BOEM.

Again, it's to accommodate the shipping and Coast Guard and fishing interests.

The -- we do believe the Coast Guard agrees that it's adequate to address the concerns that they had initially.

And we think that will weigh in on BOEM's decision when they evaluate the cumulative impact.

All the developers have agreed to the same format that Eversource and Ørsted have committed to earlier.

So we'll see how this addresses the concerns or questions that BOEM may have, and we'll know about that on June 11 or June 12.

Okay.

So in mid-June, we'll get the idea of what the final spacing is?

Or will that be in December?

I think June will give you the expectation is that we'll get a draft from BOEM that will address the cumulative impact of these six leases and provide standards for us to use going forward.

That draft EIS ultimately will be finalized by the end of 2020.

I think the date that was published through the Vineyard Wind decision was a record of decision, December 18, 2020.

So June 12 for the draft and December 18 for the final.

Okay.

And then just on the spacing, I guess, Ørsted was in New York earlier in the month.

So if the spacing, we -- right now, we're 1 mile by 1 mile.

But if the spacing got, I guess, wider, I don't know if that's the right term, but if it was 1.25 miles or whatever it is, at what stage does -- not the first two projects, but kind of the overall concept of making a large investment as far as, for no better way to put it, building a factory or building the stuff that you are on land.

At what stage does the spacing become too wide and makes it kind of not as economic or not economical to kind of put all that capital in because it would take away from the longer-term growth abilities of the overall acreage that you have?

Yes.

I think, as I said, the 1 x 1 should be adequate.

One of the mitigating factors, Andy, is that when we began this process and we talked about 4,000 megawatts, we were looking at a technology that was 8-megawatt turbines.

And now we're seeing that Ørsted is actually testing here in Massachusetts some of the 12-megawatt turbines.

So we were forced to have two holes in the water, if you will.

It may very well be that it doesn't have larger turbines on them, which would obviously positively impact the economics.

So right now, we don't anticipate any need beyond the 1 x 1, but we continue to believe that that will be adequate to provide us the financial results that we're targeting here.

But anything over the 1 x 1 kind of changes everything?

So I don't know what changes everything, but we'd certainly evaluate it.

I haven't heard anybody propose something beyond the 1 x 1, other than the discussions about shipping lanes also being...

The corridors and things like that?

Yes.

Yes.

Okay.

So I guess, we still have to monitor it.

But it does seem that to be the biggest concern that Ørsted had in kind of the entire process.

But I should have this down at lunch.

Next question is from Andrew Weisel from Scotia.

A lot of it is already covered, of course, but just a quick one on the offshore wind.

If we do see some slippage in the in-service dates related to BOEM or whatever.

Do you have a quick and dirty rule of thumb of what a one-year delay would have on earned returns relative to your expectation of mid-teens, whether that's tax credits or more broadly?

No.

I don't think it sort of reduces our returns.

It basically will just delay them.

We have factored into our purchased power agreements flexibility for delays, especially if they're created by regulatory approvals.

So we don't anticipate major financial consequences of it, although if further delays occur, the earnings profile would shift out from what we're currently planning for 2024, 2025.

Got it.

Okay.

And then just lastly on O&M.

Obviously, you're guiding to flat through the forecast period.

Would that be flattish in each year, including 2020?

Or is there any lumpiness or gradual trajectory?

It should be consistent throughout the forecast period, Andrew.

No particular lumpiness.

Okay.

So 2020 should be flat with 2019 then?

Yes, modestly flat, I'd say.

In '19, we had, I think, one of the drivers of O&M being up or really the driver is really kind of a higher level of storms than we had had the previous year.

So I know you've heard that from other people.

Storms sometimes could create lumpiness, but we're not expecting any other known items to be lumpy during that time period.

Next question, we have Mike Weinstein from Crédit Suisse back.

With all the offshore talk, I thought I'd switch over to the other water for a minute.

You've owned Aquarion now for a few years.

Can you describe how operating and planning a water system has been more or less difficult than the electric and gas systems that you would have?

I remember at the time, you were the first electric utility really to buy a water company, and there was questions about whether that would be easier or more difficult.

And then also, now that you have some experience, but you consider looking beyond New England for further water investments at some point.

I know that in the past, you haven't, but now that you have experience, would you maybe reconsider that?

Yes.

I would say that the water business that we've had for a short period of time that we have has met or exceeded expectations.

I mean we committed that it would be accretive to earnings the first year.

It's a very, very small business, obviously, but it was.

They grew their earnings in the second year.

I do -- there is sort of a roll-up strategy within the towns, I think, in the last seven or eight years, Aquarion has rolled in 70 or 71 small water entities, but it doesn't move the dial a lot, it's relatively small.

It's over 50,000 water entities in the state.

So -- I'm sorry, the country.

And so it does beg for consolidation.

As I mentioned earlier, the pricing is so high that it's tough to justify paying the premiums that it -- would be required.

I think that we have expanded our footprint.

And I started many years ago at Boston Edison, and we are -- we fared pretty well.

We knew Massachusetts.

We did the deal that created Eversource.

We expanded our footprint into Connecticut and New Hampshire and have proven that we're able to excel really in terms of our operation and financial results beyond Massachusetts.

Now we're into New York with offshore wind, and we've had some success there.

So I think we're less hesitant to move outside of our footprint.

And it may very well mean that our water expansion would require us to do that.

All right.

Thanks, Mike.

That was the last question in the queue.

So we want to thank you all very much for your time today.

If you've got any follow-up questions, please give us a call.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating, and you may now disconnect.