康涅狄格電力 (ES) 2021 Q3 法說會逐字稿

Welcome to the Eversource Energy Q3 2021 Results Conference Call.

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

At this time, all participants are in a listen-only mode.

Later, we will conduct a question-and-answer session.

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

And I will now turn the call over to Jeff Kotkin.

Sir, you may begin.

Thank you, Cheryl.

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 risks and uncertainty, which may cause the actual results to differ materially from forecasts and projections.

These factors are set forth in the news release issued yesterday.

Additional information about the various factors that may cause actual results to differ can be found in our Annual Report on Form 10-K for the year ended December 31, 2020, and on our Form 10-Q for the 6 months ended June 30, 2021.

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

Speaking today will be Joe Nolan, our President and Chief Executive Officer; and Phil Lembo, our Executive Vice President and CFO.

Also joining us today are John Moreira, our Treasurer and Senior VP for Finance and Regulatory; and Jay Buth, our VP and Controller.

Now I will turn to Slide 3 and turn over the call to Joe.

Thank you, Jeff.

We hope that all on the phone are safe and well, and we look forward to seeing many of you in person next week at the EEI conference.

I will cover a few topics this morning and then turn over the call to Phil to discuss our third quarter financial results and our regulatory activity.

First, I want to discuss last week's Nor'easter, which impacted approximately 525,000 customers across our service territory.

Our Eastern Massachusetts customers sustained the greatest damage with more than 450,000 customers impacted.

That's over 35% of Eversource's customers in Eastern Massachusetts.

This storm was far less damaging in Connecticut, Western Massachusetts and New Hampshire.

So, as we wrapped up the restoration in those areas, we were able to quickly redeploy resources to Southeastern Massachusetts, Cape Cod and Martha's Vineyard.

Areas that took the brunt of the storm.

Our internal resources were supplemented by hundreds of crews from outside the region, and we were able to essentially complete the work over this past weekend.

This experience underscores the benefits of a large T&D organization, one where resources can be shifted based on the greatest need.

Last year, it was Connecticut.

Last week, it was Massachusetts.

Next time it might be New Hampshire.

We have 9,300 dedicated employees, all focused on providing the best possible experience for our customers.

Lessons we learned last year in Connecticut, particularly regarding communication with municipalities have been vigorously applied this year.

Our customers and community leaders have certainly noticed our enhancements, and we have received many positive comments on our storm response.

Customers are noting that not all the best linemen in New England work for the New England Patriots.

When storms have threatened us, and recall that we have had glancing blows from three tropical storms this summer and last week's events that I described at the beginning of my comments, I have been at the center of the action from before the storm hits until the last of our customers has power restored.

I believe that it's critical for us to be out front, visible, transparent and collaborative during these major events, something that has been difficult to do as we all worked in a remote pandemic restricted environment for the last 18 months.

Next, I want to discuss our Connecticut rate settlement.

To start, I want to thank the parties from DEEP, the Connecticut Attorney General's office, the Office of Consumer Counsel and the state's industrial consumers for being willing to sit down and work out a settlement that will yield meaningful and immediate bill credits to customers and strengthen the Connecticut focus and control at Connecticut Light and Power.

In news reports, Governor Lamont, Attorney General William Tong and state leaders were quoted as saying that the settlement provides customers with some well-deserved relief in the short term, greater local control and oversight and an improved customer experience.

We agree.

I also want to thank PURA for approving the settlement agreement last Wednesday.

Phil will discuss settlement specifics in a moment, but we are very grateful to PURA for the opportunity to move forward on a positive note.

Settling critical regulatory and legal disputes was a necessity to reset our relationship with key Connecticut stakeholders.

We all want the state to move ahead on addressing critical energy and climate issues.

And the outstanding disputes had the potential to delay some of this important work.

Since becoming CEO this past spring, my top priority has been to strengthen our relationships in Connecticut.

I've met regularly with key state policymakers as well as business leaders and customers, underscoring our commitment to the state where the largest number of Eversource employees live and work.

This will continue to be a strong focus for me going forward.

Eversource is fully committed to providing each and every one of our 4.3 million electric, natural gas and water customers across New England with exceptional service.

With the Connecticut temporary rate docket now behind us, we can move on to other important topics, where progress has been hindered by the drain in time and resources devoted to Storm Isaias and the interim rate reduction, supporting the build-out of electric vehicle infrastructure, incenting the construction of customer-owned energy storage, installing AMI - that is the clean energy future, and we will work together with our customers and policymakers to get there.

Changing topics, I'm going to cover some very positive developments in recent months concerning our offshore wind partnership with Ørsted.

You can see the status of our current projects on Slide 3. Each has advanced since our last earnings call.

To start, our smaller project, South Fork, has received its final environmental impact statement, and we expect a record of decision to be posted later this month.

BOEM's project website anticipates a decision on South Fork's construction and operating permit or a COP in January of 2022, and we anticipate construction beginning early next year.

We continue to expect commercial operation of the 12-turbine, 130-megawatt project by the end of 2023.

In August, we announced that Kiewit will commence construction of the project substation this month in Texas, and that we expect it to be installed in the summer of 2023.

Moving to the 704-megawatt Revolution Wind project that will deliver clean power to Connecticut and Rhode Island.

BOEM continues to anticipate a COP decision in July of 2023, which would support a 2025 in-service date.

State siting hearings have commenced.

Finally, our largest project, Sunrise Wind, which will supply 924 megawatts to New York.

We are looking for federal agencies to complete their final reviews in late 2023, a schedule that would support a late 2025 in-service date.

Last week, we announced that Sunrise will be the first offshore wind project in the United States that will utilize high-voltage direct current technology.

HVDC offers advantages over AC technology when used over long distances.

In Sunrise, we'll have an approximately 100-mile submarine transmission cable from the offshore energy production area to the grid connection in Brookhaven, Long Island, New York.

We continue to project mid-teens equity returns for these three projects.

The Biden administration continues to show significant support for offshore wind in both words and actions, targeting 30,000 megawatts of offshore turbines by 2030.

We view our partnership's two ocean tracks off Massachusetts as the best offshore wind sites on the Atlantic seaboard.

Our leases are in close proximity to both the New England and New York markets.

They enjoy strong offshore winds, particularly in the winter, and they have modest ocean depths.

They can hold at least 4,000 megawatts of offshore wind turbines, far more than the approximately [1,760] (corrected by company after the call) megawatts we currently have under contract.

We continue to exercise strong fiscal discipline in using the remaining offshore acreage that we have leased from the federal government.

We did not bid into Massachusetts September RFP for up to 1,600 megawatts of offshore wind.

Current Massachusetts bidding rules discourage imaginative bid packages, Governor Baker and some Massachusetts policymakers are now recognizing that Massachusetts is not benefiting from the same level of economic development as states that place greater emphasis on infrastructure and supply chain development.

As such, the governor recently filed legislation that would eliminate the state's current price cap.

In Rhode Island, we are constructing a service vessel in the state.

In Connecticut, we are partnering with the state on a more than $200 million upgrade of the New London State Pier.

The Pier will become the premier site in the entire Northeast for staging offshore wind development.

Onshore construction is underway, which you can see from either I-95 or Amtrak's nearby Boston to New York line.

In New York, I joined members of Governor Hochul's administration last month in announcing the largest single offshore wind supply chain contract award in New York to support the Sunrise project.

The local company, Riggs Distler, will construct advanced foundation components at the port on the Hudson near Albany.

It is just the latest commitment we have made to New York, which also includes basing an offshore wind maintenance hub in Port Jefferson.

We have an excellent relationship with New York policymakers, and that is where most of our currently contracted offshore wind capacity is headed.

We look forward to bidding into future RFPs, where our strong mix of sites, skill sets, disciplined bidding strategies and Ørsted's vast offshore wind experience will make us a formidable contender in any competition that takes a broad look at the benefits of offshore wind.

Now I will turn the call over to Phil.

Thank you, Joe.

This morning I'll cover a few topics on third quarter results, details about the Connecticut settlement, an update on grid modernization, electric vehicle initiatives and to look at the natural gas outlook for the coming winter.

I'll start with our results for the quarter on Slide 4. Our GAAP earnings were $0.82 per share for the quarter, including the $0.19 charge associated with the Connecticut electric rate settlement and the $0.01 charge relating to our integration of Eversource Gas of Massachusetts.

Overall, we experienced improved operating results at the electric transmission and distribution segments and lower results at the natural gas and water segments as well as the parent and other.

Our electric transmission business earned $0.40 per share in the third quarter of 2021 compared with earnings of $0.36 in the third quarter of last year, reflecting a higher level of necessary investment in our transmission facilities.

Our electric distribution business, excluding charges related to the Connecticut rate settlement, earned $0.62 per share in the third quarter of 2021 compared with earnings of $0.60 in the third quarter of 2020.

Higher distribution revenues were partially offset by higher O&M, depreciation, interest and property taxes.

Storm-related expenses remain a headwind for us, costing us $0.01 a share in the third quarter of 2021 compared to the same period in 2020 and a total of $0.05 a share more in 2021 than last year on a year-to-date basis.

Our natural gas distribution business lost $0.06 per share in the third quarter of 2021 compared with a loss of $0.04 in the third quarter of 2020.

Given the seasonal nature of customer usage, natural gas utilities tend to record losses over the summer months, our natural gas segment loss is now about 50% larger as a result of the acquisition of Columbia Gas of Massachusetts assets back in last October.

And as you recall, we now refer to that franchise as Eversource Gas of Massachusetts.

So, Eversource Gas of Massachusetts lost about $0.03 per share in the quarter.

It had no comparable amount in the third quarter of 2020.

I think it's important to point out here that given this is the first full year for our Eversource Gas of Massachusetts, or EGMA franchise, modeling its quarterly earnings contribution has varied widely across street estimates, at least the ones that I've seen.

Just as some investors underestimated the $0.14 per share positive contribution from EGMA in the first quarter, I believe there may have been some underestimate of EGMA losses in the third quarter.

As I said, EGMA lost $0.03 in the quarter, and it was not part of the Eversource family in the third quarter of 2020.

I'd say going forward with a year's track record behind us, I'm sure that the estimates will better reflect the earnings pattern we have for that franchise going forward.

Our water distribution business, Aquarion, earned $0.05 per share in the third quarter of 2021 compared with earnings of $0.07 in the third quarter of 2020.

The lower results were due primarily to the absence of the Hingham, Massachusetts water system that we sold at the end of July of 2020.

The $17.5 million that we earned at our water segment in the third quarter of 2021 is the more normalized level for that segment.

Our parent and other earned $0.01 per share in the third quarter of 2021 compared with earnings of $0.03 in the third quarter of 2020.

Lower earnings were primarily due to a higher effective tax rate.

Our consolidated rate was 24.8% in the third quarter of 2021 compared with 23.7% in the third quarter of 2020.

Turning to Slide 5. You can see that we have reiterated the $3.81 to $3.93 EPS guidance that we issued in February.

That range excludes the $0.25 per share of charges related to our Connecticut settlement and storm-related bill credits that we recognized in the first quarter of this year, as well as the transition costs related to the integration of the former Columbia Gas of Massachusetts assets into the Eversource system.

Also, we project long-term EPS growth in the upper half of the range of 5% to 7% through 2025.

Excluding the positive impact that we expect from our offshore wind projects, that growth is largely driven by our $17 billion 5-year capital program and continued strong operational effectiveness throughout the business.

For reference, our 5-year capital forecast is shown in the appendix.

And through September 30, our capital expenditures totaled $2.3 billion.

From the financial results, I'll turn to our recently approved Connecticut settlement on Slide #6.

Earlier, Joe provided you with an overview.

I'll just add a few additional details.

The settlement calls for $65 million in rate credits to CL&P customers over the course of December of 2021 and January of 2022.

And that's about -- in total, $35 per customer over the 2 months for the typical residential customer.

It provides another $10 million of shareholder paid benefits to customers who are most in need of help with their energy bills.

Further, as part of the settlement, we will withdraw our superior court appeal of the $28.4 million total storm-related credits that customers first saw on their bills in September of '21.

So, these [credits] (corrected by company after the call) will continue.

They'll continue to flow back to customers through August of next year.

As part of the settlement, the 90-basis point indefinite reduction of CL&P's distribution ROE will not be implemented.

Additionally, the current 9.25% ROE and capital structure will remain in effect.

This will avoid an appeal of the interim rate reduction and we will withdraw the pending appeal of the 90-basis point reduction.

CL&P cannot implement new base distribution rates before January 1, 2024.

Parties to the settlement agreed that this review satisfies the statutory requirement in Connecticut that all electric and natural gas distribution company rates be reviewed once every 4 years.

That's to determine whether they're just and reasonable.

So, as a result, the next statutorily mandated review would be in late 2025.

Since CL&P's last distribution rate case was effective in May of '18, the company's actual ROEs have generally ranged between 8.6% and 9%, with the latest reported quarter at 8.6%.

There are some tracking mechanisms that will allow us to recover costs associated with certain new investments over the coming years, such as those to improve reliability or implement grid modernization initiatives, but we will not be able to obtain any additional revenues to offset higher wages, employee benefits costs, property taxes and other inflationary items.

We'll continue to provide superior service to our nearly 1.3 million CL&P customers, while also effectively managing our operations.

It will certainly be a challenge, but one, I know that our entire CL&P and Eversource team is up to meeting.

From the Connecticut settlement, I'll turn to our various grid mod, AMI, electric vehicle initiatives in Connecticut and Massachusetts.

So first, I'll turn to Slide 7 and cover the Connecticut programs.

On October 15th, CL&P filed final electric vehicle program design documents for PURA review and approval, including a proposed budget and program implementation plan for residential managed charging.

PURA will conduct a review process with a final decision targeted for December 8th.

The program is planned to launch January 1 of 2022 and will support the state's target of having at least 125,000 electric vehicles on the road by the end of 2025.

In terms of AMI, in Connecticut, CL&P is preparing to file an updated proposal based on a straw proposal from PURA to have all our customers on AMI by the end of 2025.

To do that, we'll have to replace more than 800,000 meters over the next several years.

Altogether, moving CL&P fully to AMI would involve a capital investment of nearly $500 million, we estimate, in meters and communication-related technologies.

In Massachusetts on Slide 8, as we mentioned on our July earnings call.

We've submitted a nearly $200 million grid modernization plan to regulators for the 2022 through 2025 period.

The vast majority of that investment would be capital.

We expect a ruling on the entire program by the second quarter of 2022.

Our Massachusetts AMI program is now being evaluated by the Massachusetts Department of Public Utilities, with a decision expected in 2022.

It would involve about $575 million of capital investments over multi-years from 2022 through 2027.

And like Connecticut, would provide significant customer service, reliability, energy efficiency, grid modernization and demand management improvements.

Also in Massachusetts, the DPU is evaluating an extension of our electric vehicle program.

The extension would provide investments of nearly $200 million over the next 4 years, with about $68 million being capital investments.

We currently expect a decision on this by mid-2022.

Turning to Slide 9. We've been receiving regular questions over the past couple of months about the impact of higher natural gas prices on this winter's electric and natural gas supplies and prices.

So, I'll first start with supplies.

First, what do we have to supply?

Our three natural gas distribution companies are required to have access to enough natural gas to be able to serve our firm customers on the coldest day in the last 30-year period.

So, we accomplish that through a combination of firm capacity contracts across multiple interstate pipeline systems and through storage, both inside and outside of our service territory.

Our regulators in Connecticut and Massachusetts have had the foresight to allow us to maintain significant in region LNG storage in Waterbury, Connecticut and Hopkinton and Acushnet, Massachusetts, as well as various facilities that we purchased as part of the Columbia Gas of Massachusetts transaction.

Altogether, these facilities provide us with storage connected to our distribution system of nearly 6.5 billion cubic feet.

Our regulators have also permitted us to acquire additional firm delivery capacity that was added to the Algonquin system in recent years through the AIM and Atlantic Bridge expansion projects.

We've also acquired additional firm capacity on the Tennessee and Portland pipelines.

So, from a reliability standpoint and supplies, we consider ourselves very well prepared for the winter.

In terms of price, our natural gas sources include a combination of stored gas, where the price has been fixed and pipeline gas from the Marcellus Shale Basin that is priced based off of NYMEX-related indices.

Because of our firm pipeline capacity, we are able to purchase at the Marcellus-related price, not at the New England Citygate price.

You can see on the slide that we have in our deck, that there's a significant difference in pricing between the two.

Nonetheless, even the Marcellus price is higher this year.

And as of now, we expect the commodity portion of natural gas bills to be approximately 20% higher than last winter's extremely low levels due to COVID.

Prices were pretty low last year and well below levels we experienced a decade ago after Hurricane Katrina struck the Gulf of Mexico and Louisiana.

Overall, including the distribution charge, we expect natural gas heating bills will be up about 15% on average.

That's about $30 a month on average for a typical heating customer compared to last winter.

And that's an average across our three natural gas distribution companies.

While a 15% increase is significant it is far less than the more than 30% increase that propane heating customers are facing and the 60% increase that's out there for home heating oil as the alternatives for customers.

Of course, a primary determinant of the total bill is usage, right?

The autumn has been quite mild here in New England, thus far, and natural gas usage has been particularly low.

Nonetheless, a bitterly cold month of December or January could cause natural gas costs to increase.

Recognizing the stress that this situation could place on customers.

We've been proactive.

We've suggested to our regulators that we spread out the recovery of certain charges in the distribution portion of our bill to moderate the potential bill impacts where possible.

We're also taking additional proactive steps and working closely with regulators so that customers understand the current price environment and take actions to address it.

We're intensifying our communications to be sure customers understand the bigger picture macro factors affecting natural gas bills.

And we are urging customers to take advantage of our nationally recognized energy efficiency programs and leverage payment options that we have available.

So, on the electric side, it's a bit different.

Natural gas power plants are on the margin in New England year-round, really, except for the coldest days of the year.

So, rising natural gas prices are significantly affecting power prices.

Between 60% and 65% of our electric load is bought by customers directly from third-party suppliers.

For the 35% to 40% of our load that continues to buy through our franchises, Connecticut Light & Power, NSTAR Electric and Public Service of New Hampshire, this is mostly residential load and customers will see higher prices, but they are partially protected by the fact that we contract for power in multiple tranches throughout the year.

So, lower cost tranches from our purchases earlier for 2022 will offset some of the higher priced tranches that we purchased more recently.

Due to wintertime natural gas constraints in New England, our customers normally see a $0.015 to $0.02 per kilowatt-hour increase in their retail electric prices in January, an increase that usually reverses as we move into the summer.

This January, customers in Massachusetts and Connecticut are likely to experience an additional $0.02 to $0.03 increase due to higher gas prices driving power production.

This would be an additional $20, $25 per month for a typical residential customer compared with last winter.

For our New Hampshire customers, the rates remain in effect until February, so there's really no impact at this stage for our New Hampshire customers.

While the vast majority of our residential customers do not use electricity for space heating, we recognize that any increase in energy bills adds stress to the household budget.

And we've redoubled our efforts again to urge customers to take advantage of the more than $500 million that we have available on energy efficiency initiatives that we provide customers throughout our states each year.

I should note that similar to natural gas prices, wholesale electric prices were extremely low in 2020.

In fact, they were at a 10-year low.

So, the percentage increase that we're reporting here comes off some very low base numbers from last year.

As a reminder, increases and/or decreases in the energy component of our electric bills are pass-throughs, dollar-for-dollar pass-throughs.

We earn nothing on providing the procurement service for customers.

So, thank you very much for joining us this morning.

I'll turn the call back over to Jeff for Q&A.

Thank you, Phil.

And I'm going to return the call to Cheryl, just to remind you how to enter your questions.

(Operator Instructions)

Thank you, Cheryl.

Our first question this morning is from Jeremy Tonet from JPMorgan.

Thanks for the update there.

You covered a lot of ground.

Maybe just starting off with Connecticut a little bit more here.

But just wondering, if you could provide a little bit more color on how you think about -- how you're planning to manage the rate freeze in Connecticut?

And how we should be thinking about go forward and earned ROE?

And when you think you might end up filing the next case there?

Well, Jeremy, thank you for the question.

As I mentioned, Connecticut Light & Power and NSTAR Electric, Public Service of New Hampshire, the Eversource family has a strong track record for managing operations in an effective manner, and we'll continue to do that throughout all of our franchises, Connecticut included.

So, as I mentioned, the last reported quarterly ROE in Connecticut was just under 8.7%.

I think it was 8.61% or 8.6%.

So even though we're allowed a 9.25% ROE, we've been operating underneath that measure since the settlement in 2018.

So, I would expect that we'll continue to operate that franchise effectively.

I can't really predict at this moment what an ROE might look like there, but I can assure you that we're going to do everything possible to first provide customers with the outstanding service that they deserve, and we fully expect to deliver, and do that in an efficient and effective way.

In terms of when we file our next rate case, the ink is just dry on the settlement, and we can't go in, there's nothing that we can implement before 2024.

And as I said, with the 4-year legislative requirement, we wouldn't be mandated to be in there until 2025.

So, we haven't really thought about that at this point.

We're thinking about how we operate our franchises in an effective manner for customers.

Got it.

And maybe pivoting over towards offshore here.

Now that we have schedules across all three of your projects, when do you think it might be an appropriate to give increased disclosures here on the project economics.

And specifically, how do you think about, I guess, the roll forward guidance here for long-term EPS growth given that offshore wind is going to be hitting kind of earnings growth run rates going forward?

Yes, it's a great question and one that we've been asked, and we've been thinking about -- what our expectation is, we generally would update our long-range plans in February with our year-end results, and then we'll talk about our forecast.

So, we plan to do that again this year.

We'll roll forward our forecast like we've done in the past, drop a year, add a year out to 2026.

And as you point out, given the schedule of the projects, we're going to see significant contribution from the bigger projects in that time frame.

So, the expectation is that as we roll out that next forecast in February, there would be more clarity, more transparency, more information on that segment.

So that they'll be able to either model it in a way that you want, in a way that makes sense.

So I'd say that we're getting close to that, and the expectation is that in our February update we'll roll the wind in in a more, I guess, discrete -- in a more definitive way.

Got it.

That's helpful.

Just real last quick one, if I could.

It looks like Eversource didn't participate in the most recent Massachusetts RFP process.

And would you be able to talk about, I guess, next opportunities do you see to add incremental projects and just any high-level thoughts on the broader industry returns at this point?

Yes.

Thanks, Jeremy.

It's Joe.

I'll take that.

Massachusetts is unique in that they are looking for the lowest price.

They're not looking for economic development opportunities like some of the other states.

That is now changing.

The governor is very, very interested in economic development and opportunities in this business.

When you look at states like New York that are dedicated to, I was in upstate New York for a pretty big announcement around foundations, which -- it's nice to bring some of the supply chain here to America.

And that was a big, big step, I think, for offshore wind.

Opportunities we're seeing for offshore wind RFPs in 2022, we're looking at New York, potential in Connecticut, as well as in Rhode Island and Massachusetts.

So, I think there's opportunities everywhere.

I think the first one you'll see will be New York.

They are very, very aggressive with their targets, and that's a place that we know will put out another big RFP.

Thanks, Jeremy.

Next question is from Steven Fleishman from Wolfe.

So just in terms of supply chain issues and the like, could you just talk to how you're feeling about the current schedules for your three main projects and managing right now?

Yes, Steve, this is Phil.

We talked about -- this has certainly been a topic that people have been interested in as well as the project and the company.

So we feel like we're in a very good position in terms of our contracting for what substations or turbines or foundations, what we have in place for strategy, for vessels, et cetera.

So, our supply chain exposure, I'd say there is some supply chain exposure, but we've done a very good job in solidifying most of that to not make it an issue for us.

So, as I've talked about before, there are puts and takes for all these projects.

So, some costs maybe move in one direction and other things are moving in a different direction.

So taking all that, if there are price changes or if there are schedule impacts, all of that allows us to be confident in the schedules that we've put out to date and in our estimate and our expectations that these projects will earn in the mid-teens in terms of ROEs.

So, there are a number of factors that come at you every day on these projects, and we still feel good about the schedules and the return estimates.

Okay.

Because I know the Empire Wind project, which I think was awarded at the same time as Sunrise, is now saying late '26, but obviously, different people, different situations.

So, and then I think they've had some issues with like the New York ISO interconnect agreement.

So, it sounds like you're not seeing that kind of delay.

No, Steve, this is Joe.

We are not, I mean, they did announce a delay.

We do not expect any similar delays on our projects.

We have good visibility on it.

We feel very confident.

Great.

And then maybe just high level, the Biden Infra Plan, The Reconciliation one.

Could you talk to if there's anything broadly in there that would impact the way you're looking at your plan in terms of just new credits, cash flows?

Anything that you're most focused on?

Yes.

Obviously, we would like to take advantage of tax credits to help our customers in any way we can as well as improve our projects, but that's really what our focus would be on the Biden plan.

All right.

Thanks, Steve.

Next question is from Julien from Bank of America.

I appreciate the opportunity to connect.

So, let me start with a higher-level question for you guys.

Obviously, looking at the outcome of the election in Maine here, how are you thinking about the Massachusetts renewable procurement at large?

I know it's very fresh here, but any prospects for revisiting perhaps some of the legacy projects that we've all talked about for a long time?

And/or, frankly, revisiting alternatives to long distance transmission given the pushback in New Hampshire and Maine, historically, here?

And maybe the same -- so the same might apply to gas and Access Northeast while we're at it as well?

Yes.

Julien, thanks for the question.

If the question is, are we going to dust off Northern Pass, the answer is no.

We will not dust that off.

Is there an opportunity for projects?

I think there's definitely an opportunity in Massachusetts around wind.

I think the governor's appetite for additional renewable projects, his desire to change the legislation, which requires it to be lower than the previous RFP is definitely on the table.

We've had discussions not only with the governor but with key legislative leaders around this.

And I think that if they see challenges up there, I would not be surprised if we see some bids out there, RFPs out there in the near term.

In terms of what our future holds for other types of opportunities in this space.

I think it's premature.

I mean, I don't think they're finished counting the votes in Maine, but we'll certainly take a good hard look at that and see what opportunities might be available.

Got it.

All right.

Fair enough.

And it sounds like Access Northeast not necessarily in the same vein on the table.

But if I can pivot then a little bit more locally, right, talking to Massachusetts situated opportunities.

I mean how are you thinking about enabling distributed resources themselves.

There's been some interesting filings in various dockets here that seem to suggest some pretty meaningful opportunities for you all vis-a-vis just simply interconnection, whether that's on the distribution or transmission side.

And I'm also cognizant that you update your outlook with fourth quarter here, but any initial thoughts there around distributed assets and enabling them?

I'll just tell you that our interests on this issue around the smart grid in allowing folks to interconnect and AMI.

All of those are shared agendas with our key regulators, policymakers in Connecticut and Massachusetts, particularly.

And I think we talked about Connecticut, what happened down there on our settlement.

I think this really starts the opportunity for us to really begin to look at AMI and the smart grid and opportunities for unlocking access or greater access to renewables and distributed generation for folks that are -- eager to interconnect.

So, I do think you'll see a lot of activity in 2022.

I'll let Phil talk a little bit around the financial piece of it.

Yes.

So, Julien, as you suggest, we do update in February as we've all discussed.

And I think what -- in the area that we're looking at, we refresh all of our plans, all of our investment activity.

So in the area of transmission, certain categories, I'd say broadly that we would expect to take another look at and identify opportunities that may exist, just or maybe in three different categories, one being just the end-of-life asset replacement kinds of projects.

What do we have out there?

What do we have expectation-wise?

Certainly, electrification is a category.

The states have targets.

We have to enable those targets to be met.

So, there could be additional transmission in that category.

And the third category and one that you highlight is connecting distributed energy resources to the grid, upgrades that are required to connect, either currently contracted offshore wind or future offshore wind into the service territory.

There's a large desire for offshore wind across New England, New York and making sure that we have the connectability or interconnections and the transmission to not be a bottleneck for that, there's likely to be some increased investment needed on the system.

So, I'd say those are the types of things that I think you'll see when we roll out our update in February in those categories.

Got it.

All right.

Well, we shall wait for what those numbers amount to.

But I wish you the best of luck.

Talk to you soon.

Thanks, Julien.

Thank you.

Next question is from David Arcaro from Morgan Stanley.

I was wondering, if you could just give an update on the equity needs?

Apologies if I missed it in the prepared remarks, but just latest thinking on the amount and timing of equity here?

Yes, David, this is Phil.

There's been no change in what our equity needs are going forward at this stage.

So that would mean that from what we had announced previously a few years ago, there's $700 million of equity that we would plan to issue on some sort of ATM or at-the-market type of program.

That goes throughout our current forecast, our current forecast goes through 2025.

So, there's no specific timing of that at this point.

And we continue to issue original issue shares from our dividend reinvestment, equity comp type of things, and that's $100 million a year.

So, there's been no change, and that's where we are, no increase or change in those needs.

Okay.

Got it.

Understood.

And then I had a question on the turbine installation vessel that you're contracting with Dominion.

Just wondering, if you could talk a little bit about the amount of time there is between using that vessel for your projects, Sunrise and Revolution, and then moving to Dominion's in 2026?

Just if there's any risk that you would lose access to the vessel in the case of any project delays or how you're thinking about that?

Yes.

So, thank you, I'll take that.

That vessel, it's first port of call is going to be New London.

We have an opportunity to use that vessel for both projects Sunrise as well as Revolution Wind.

It will not be ready for South Fork.

There's enough of a cushion in there to allow for us to complete those projects.

In addition, there's a day-for-day delay opportunity.

So, if the vessel is delayed coming into New London, we are the first customer that would be pushed out on the other end.

So, we do not anticipate any issues around the use of that state-of-the-art vessel.

I mean that is an extraordinary vessel.

It carries six wind turbine assemblies.

New London is only 70 miles from our lease area.

So, we think it's the most efficient way to install our wind turbines, and we're really excited about that.

I had an opportunity to spend a little time with the Dominion folks and the vessel is on track, and some of our folks will head down and check on the progress, but it's going to be quite a piece of equipment.

Thanks, David.

Our next question is from Sophie Karp from KeyBanc.

So I guess going back to Connecticut, I'm just kind of curious -- I appreciate the overall CapEx forecast is unchanged, but kind of shifting the timing of some projects maybe between states, one of the levers you can pull here to manage your earned ROE in the next two years there?

Or what are some of the levers you can pull to offset inflationary pressures and just overall normal cost of investment there?

So Sophie, I think as I've said in the past and we've commented on, our investments in our operations are geared to meeting our customer expectations.

So investments that we make in our system are driven by what our customer needs are, how do we reinforce the system, how do we provide -- we might be able to make a capital investment that offsets some O&M costs.

So that's also good for customers.

So, our focus on our investment needs, whether they be transmission, distribution, gas, electric, water are on, first and foremost, what does it do for customers.

So, we wouldn't be looking at moving around investments into other areas for other reasons other than how it meets customer needs.

There are levers, as I said, -- I'd put our track record up against anybody's in the industry in terms of managing our operations in an efficient and effective manner.

How we integrate EGMA into our family is going to provide some uplift.

We have opportunities there.

And how we roll out programs in an effective manner.

So, I'd say that we are focused on managing our operations to meet the customer needs.

I mean that will be the lever that we have to get to where we want to get to in terms of our earnings profile.

Got it.

Good.

And just what are you seeing, like, right now, I guess, aside from the energy costs, just overall like materials, labor type of inflationary pressures within your regulated franchises?

Is that something that is becoming material and it requires, I guess, some efforts to offset?

Or are you seeing that within the maybe a pretty decent trajectory?

How should we think about that right now?

I'd say it's had an impact, but I wouldn't say it's been significant.

A year ago, the supply chain team who is in the financial organization works very closely with our engineers and our operating folks.

And at the start of this pandemic, I think a lot of companies like to have a just-in-time sort of delivery model.

We made a conscious decision over a year ago to not do that, to have -- to actually build up our inventories: poles, transformers, wire, cable, all those types of things.

And if it's not in our facility, we have provisions with our suppliers to keep it on their property.

And we're using a lot of it.

I mean, we have had -- Joe talked about storms right at the beginning.

We go through a lot of poles and wire, et cetera, when there's a storm and that's not been a factor for us.

We've had the supplies available to us.

Now having said that, we certainly have our eyes on it.

There are types of equipment that are getting more difficult, and it may not be the whole piece of equipment.

It could just be the plastic component of something we can't get.

And so, we've also expanded the types of suppliers we have and where the suppliers are located and that type of thing.

So, it has had an impact.

I'd be fooling myself or anybody to say we haven't had some delays with some products, but they haven't been a material significant impact to us.

Got it.

And if I may squeeze one more on the gas supply situation.

I'm just kind of curious if you could quantify for us between the gas storage, physical storage and capacity contracts, what percentage of your normal demand, I guess, is hedged at this point in time.

And given the situation, have you given any thought to maybe bringing to your regulators proposals to build more storage facilities on your system?

Yes, I'd say about a third of it.

If you look at what we have in storage and what's fixed, I'd say it's about a-third of that supply.

And as I mentioned, the remaining part of the supply, we have the capability.

We have the pipeline contracts to obtain it, and we have the capability of obtaining it from a lower-priced region than a Citygate pricing.

So, in terms of incremental storage, we do have programs that we do have in place to refurbish some of our LNG facilities or make sure that they're operating at the maximum capacity.

But we haven't looked to expand those facilities.

We naturally expanded them just by the acquisition or the purchase of Columbia Gas of Massachusetts almost doubling the storage capacity that we have as an entity.

And as Joe mentioned, size matters in this case, too.

I mean, it matters in terms of storm response, but it matters in this case, too, because we can operate, there's synergies by moving those two companies together between NSTAR Gas in Massachusetts and Eversource Gas of Mass.

We can use contracts better than each company could have used them individually, and we can use our storage better than either company could.

So there's some natural benefits for us.

So, that was a point that we made in terms of getting the deal approved at the DPU.

So, I guess that is a way of saying we've increased the ability to have storage, but we're not looking to build anything extra at this point.

Thank you, Sophie.

Next question is from Travis Miller from Morningstar.

On the offshore transmission, it sounds like you have a lot of the pieces in place for the South Fork project, if I heard you correctly.

What's the status of the transmission side of the other projects that you have going?

Can you -- I'm not sure we understand the question, Travis, you say the status of the transmission side.

Transmission -- the connections, interconnections between the offshore projects and land essentially?

Sure.

Thanks, Travis.

I'll take that.

Yes, all of those projects, all of the permitting and the siting and applications are all in motion.

We haven't had any bumps in the road and they're all on track.

So, everything has a line of sight on it.

It is in motion.

Okay.

Okay.

Great.

And then in Connecticut, you talked about the trackers there.

About what percent of the CapEx that you have over the next couple of years is subject to those trackers that you talked about?

It's about half.

It's about half of our spend.

Thanks, Travis.

And that was the last question we have this morning.

So, we want to thank you all for joining us today.

We look forward to seeing many of you at the EEI Conference next week.

And if you have any follow-up questions, please either call or e-mail.

Thank you.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for your participation.

You may now disconnect.