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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Welcome to the Eversource Energy Second Quarter 2020 Results Conference Call. My name is Vanessa, and I will be your operator for today. [Operator Instructions].
I will now turn the call over to Mr. Jeffrey Kotkin. Sir, you may begin.
Thank you, Vanessa. Good morning, and thank you for joining us. I'm Jeff Kotkin, Eversource Energy's VP 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, 2019, and our Form 10-Q for the 3 months ended March 31, 2020.
Additionally, our explanation of how and why we use certain non-GAAP measures and how those measures reconcile to GAAP results is contained within our news release and the slides we posted last night and in our most recent 10-K.
Speaking today will be Phil Lembo, our Executive VP and CFO. Also joining us today are Joe Nolan, our Executive Vice President for Strategy, Customer and Corporate Relations; John Moreira, our Treasurer and Senior VP for Finance and Regulatory; and Jay Buth, our Controller.
Now I will turn to Slide 2 and turn over the call to Phil.
Thank you, Jeff, and good morning, and I'll start off by wishing all and hoping that everyone on the phone remains healthy and that your families are safe and doing well. This morning, I will cover several items, talk about the results of the second quarter 2020, review the impacts of COVID-19 on our customers and their energy use. I'll discuss recent regulatory developments, including new grid modernization proposals in Connecticut and the status of our application in Massachusetts to purchase the assets of Columbia Gas of Massachusetts. And finally, provide an update for you on our offshore wind investment partnership with Ørsted.
So let's get started on Slide 2, noting that recurring earnings were $0.76 per share in the second quarter of 2020 compared with recurring earnings of $0.74 per share in the second quarter of 2019. GAAP results, which include a charge of $0.01 per share relating to our pending acquisition of the assets of Columbia Gas, totaled $0.75 per share compared with earnings of $0.10 per share in the second quarter of 2019. And last year's results included a $0.64 per share impairment charge relating to Northern Pass.
So in the first half of 2020, our recurring earnings, excluding Columbia Gas, totaled $1.77 per share compared with recurring earnings of $1.71 per share in the first half of 2019, again, excluding the NPT impairment charge.
Turning to our business segments. Our electric distribution segment earned $0.34 per share in the second quarter of 2020 compared with $0.33 in the second quarter of last year. Improved results were driven by higher revenues, partially offset by dilution and higher O&M costs, depreciation and interest expense.
Our electric transmission segment earned $0.39 per share in the second quarter of 2020 compared with recurring earnings of $0.37 per share, again, excluding the NPT charge, in the second quarter of 2019. Improved results were driven by a higher level of investment in our transmission facilities, partially offset by dilution.
Our natural gas distribution segment earned $0.01 per share in the second quarter of 2020 compared with a slight loss in the second quarter of last year. Improved results were due to higher revenues, partially offset by O&M and depreciation as well as dilution.
Our water distribution segment earned $0.03 per share in the second quarter of 2020 compared to earnings of $0.02 per share in the second quarter of 2019. Improved results were largely due to higher revenues and lower depreciation expense.
At the Eversource parent, we lost $0.01 per share in the second quarter of 2020, excluding the Columbia Gas of Massachusetts asset acquisition costs compared to earnings of $0.02 per share in the second quarter of last year. The primary driver of the change was a lower mark-to-market earnings this year in a clean energy investment we made a number of years ago. As you may recall, this is an investment fund that matures soon, and each year, we mark that investment to market in the second quarter.
As you probably noted in our news release, you can see on Slide 3 we are reaffirming our 2020 earnings per share guidance of $3.60 to $3.70 range as well as reaffirming our long-term EPS growth rate of 5% to 7%. We expect that our existing core business will allow us to grow earnings per share around the midpoint of that range through 2024. Earnings from offshore wind and Columbia Gas asset acquisition would both be incremental to that growth. So they would have somewhat of a different profile. As we've said before, offshore wind earnings would commence in the latter years of the forecast as the turbines enter service, while we expect Columbia Gas asset acquisition to be accretive to our earnings per share starting in 2021.
From second quarter results, I'll turn to Slide 4 and our continued progress and success in operating the business during COVID-19 pandemic. Our very strong safety and reliability performance continued through the first half of the year. We've responded promptly and effectively to all the storms we've encountered, and the vast majority of our employees who either had tested positive for COVID-19 or were self-quarantined are now back to work, providing superior service to our 4 million customers. We remain on target to executing our $3 billion capital program. Through June, our capital expenditures have totaled $1.44 billion, about $30 million ahead of last year's pace.
In terms of usage, kilowatt hour sales in the second quarter were down about 1.4% overall compared with last year. But in New Hampshire, which is not decoupled, they were actually up 1.8%. New Hampshire residential sector sales were very strong due primarily to more customers being at home as well as weather. And we see that throughout the company. We had cooler-than-normal weather in the first half of the quarter and hotter and more humid-than-normal weather in late May and June.
On the natural gas side, where both Yankee Gas and NSTAR Gas are decoupled, sales in the second quarter were up about 1.7% compared with last year. And this was due to a colder April and early May weather. So on a weather-normalized basis, sales were off about 7% due to lower commercial and industrial usage.
In our water segment, which is also decoupled in Connecticut, unit sales were up 7.1% in the second quarter this year largely due to customers irrigating their properties during a very hot and dry month of June. We are not shutting off customers for nonpayment. We continue that program. Connecticut and New Hampshire have implemented varying schedules for when shutoff moratoria will be lifted. In Massachusetts, we're working -- we're part of a group that's working now to review policies regarding payment plans and shutoffs for nonpayments, and there are no due dates but ending the moratorium at this time. So despite the moratoria in place across the company, the impact of COVID-19 on our overall receivable balance has been manageable to date.
COVID-19 and sales -- I'll now turn to Slide 5, the recent developments around our ongoing rate reviews. We have 2 general review spending. Hearings in the NSTAR Gas rate review in Massachusetts concluded a month ago, and final reply briefing will take place in August. We continue to expect a decision by the end of October with new rates effective November 1.
In New Hampshire, hearings in the Public Service of New Hampshire rate review start later, I guess, in the month of August with a final decision in November. New rates would be effective December 1, we expect, but would be retroactive to July 1, 2019, when a temporary rate increase of $28 million took effect.
From the rate reviews, I'll now turn to grid modernization and the filing we're making in Connecticut right today, later on today. As I've mentioned on past calls, the Public Utilities Regulatory Authority, or PURA, has opened 11 dockets to look at modernizing the electric grid in Connecticut to accommodate customers' higher expectations for reliability and technology and to provide both increased resilience and a path to help the state reduce its carbon footprint by at least 80% by the year 2050. Today, we and other parties are filing proposals in 3 of the 11 dockets.
As you can see on Slide 6, the most capital-intensive proposal we're making is related to automated meter infrastructure, or AMI, for Connecticut Light & Power customers. Our filing will present a comprehensive analysis of the costs as well as the technological, operational and environmental benefits of implementing AMI. Moreover, as I've said in the past, our current AMR metering technology is ending -- nearing the end of its useful life, and we'll need to replace about 800,000 meters one way or another over the next 5 years. It would involve capital investments that would be reviewed by PURA as part of their ongoing evaluation.
In addition to AMI, we are seeking the support of -- to support the state of Connecticut in targeting to have about 125,000 electric vehicles on the road by the year 2025. Our proposal combines rebates and infrastructure investments over a 3-year period, enabling 2,500 homes to be wired for electric vehicle charging and for 3,000 additional charge ports to be enabled in multifamily dwellings, commercial centers, various destination locations and other places. We would not own the charge ports themselves, but we would invest in the backbone to get the power to the vehicles.
Finally, we are proposing a program to incentivize the installation of 30 megawatts of storage among CL&P's residential customers and 20 megawatts on the commercial/industrial side. This program would not involve capital investment by CL&P, and we are requesting a modest level of success-based incentive similar to our energy efficiency programs.
We expect PURA to facilitate an extensive review and public comment period over the balance of this year on all our proposals as well as other proposals that are likely to be submitted by utility and nonutility parties today.
In Massachusetts, we continue to implement the grid modernization plan authorized by regulators more than 2 years ago. We expect to complete the authorized projects, including infrastructure to connect 3,500 charge ports and utility storage projects on Cape Cod and Martha's Vineyard, in 2021. In mid-2021, we'll be filing a new 3-year plan with implementation in the 2022 through 2024 time period.
In addition to the regulatory proceedings I just reviewed, we've made significant progress on our acquisition of the assets of Columbia Gas of Massachusetts. Slide 7 reviews the key elements of the acquisition. We'll pay $1.1 billion in cash for the assets. The cash will come from the combination of the issuance of new parent equity and debt. We raised the equity portion in mid-June when we sold 6 million shares and netted just over $500 million in proceeds. We're very pleased with the investor interest in the issuance, which was nearly 3x oversubscribed and priced without a discount to the prior days closed. We'll fund the debt portion of the purchase price from a future parent long-term debt issuance. We're very confident the transaction will be accretive to Eversource shareholders in 2021, the first full year after closing, and be very positive for Columbia Gas customers.
Slide 8 reviews the principal elements of our DPU filings. I want to emphasize that this transaction provides both local ownership to one of the largest gas delivery systems in Massachusetts and a pathway for 330,000 customers to benefit from Eversource's award-winning energy efficiency program, our strong safety record and high level of customer service and reliability. We truly believe it is a win for customer -- Columbia Gas customers, the communities and for the state as a whole.
The DPU filings, which are available on our investor website under the Rate Case Update section, includes a settlement between the state's Attorney General, Governor Baker's Department of Energy Resources, a low-income coalition, NiSource and Eversource. We've asked the DPU to approve the application by September 30. The DPU has scheduled virtual public hearings August 25 and August 27 to take up the matter.
The settlement structures an 8-year rate plan with modest rate increases on November 1, 2021 and 2022, respectively. There are additional base rate resets November 1, 2024. And in 2027, that will be related to the level of investment we expect to make in the Columbia system.
These investments are separate from the pipe replacement capital tracker that all Massachusetts natural gas distribution companies have implemented to help accelerate the replacement of older cast iron and unprotected steel pipe. And we expect Columbia to continue to replace about 45 miles of its older pipe annually.
The agreement maintains Columbia's currently authorized equity component of its capital structure of 53.25% but raises the authorized return on equity from currently at 9.55% to 9.7%. As I mentioned earlier, we fully expect the transaction to be accretive in 2021 and to be incrementally accretive in each of the following years.
Based on the integration planning we've undertaken to date, we also remain confident that the transaction would be very beneficial to Columbia Gas customers and communities. As you can see on the slide, we'll provide the DPU with a status report on the Columbia system by September of next year. That report will provide a blueprint of enhancements we'll make to ensure that Columbia's 330,000 customers receive the same level of safe and reliable service that our existing 550,000 natural gas distribution company -- customers receive in Massachusetts and Connecticut.
Turning now to Slide 9 in our offshore wind partnership with Ørsted. On June 9, the Federal Bureau of Ocean Energy Management, or BOEM, released its cumulative impact study concerning potential development of about 22,000 megawatts of offshore wind generation along the Atlantic seaboard. This was an important step in BOEM's evaluation process for the different applications that have been filed to date, including 2 of our joint proposals with Ørsted, one of those being South Fork, the other Revolution Wind.
The study reviewed the impact of the projects which BOEM expects to be developed over the next decade. Impacts were graded from major to negligible, I guess, on their scale. The level of impacts identified in the report were anticipated by the offshore wind industry. They were primary reason that the 4 developers in the 6 ocean tracks off in Massachusetts, including our partnership with Ørsted, proposed a 1 nautical mile by 1 nautical mile spacing for all turbines in the region. A cumulative impact study found that such spacing would at least partially mitigate the impact on fisheries and navigation. The cumulative impact study was supported by the Coast Guard's earlier conclusion that a proposed turbine spacing, which is the widest in the world for offshore wind, was adequate to support safe navigation in search and rescue efforts.
Fisheries mitigation plans proposed through other agencies such as the Rhode Island Coastal Resource Management Commissioner will further mitigate impacts on fisheries by providing compensation for fishermen for negative impacts resulting from the wind farms. The response to the analysis by the public was, I'd say, largely positive with a renewed emphasis on the very significant contributions these turbines will make to carbon emission reductions in the Northeast.
Five public comment sessions on the impact study were held in the summer, and written comments were due on Monday this week. BOEM is expected to make a final decision on the Vineyard Wind application on December 18. And as you recall, Vineyard Wind is the first New England project in the queue. We expect that later this summer, BOEM will release its schedule for federal agency review of South Fork. And as we disclosed in the Q1 earnings call, we believe it is very unlikely that South Fork will enter service before the end of 2022, so after that date.
On the other projects, we were able to resume survey work in June in New York state to support our Sunrise Wind filing with BOEM. We continue to expect that filing to be made later this year. And finally, last week, New York issued an RFP for up to 2,500 megawatts of offshore wind. Bids are due on this RFP by October 20, with awards to be made by the end of this year to ensure the winners can benefit from expiring federal tax credits. We and Ørsted expect to bid into that RFP. Sunrise Wind partnership, one more than half of New York's initial offshore wind RFP in 2019.
That concludes my comments, and I'll turn the call back to Jeff for Q&A.
And I will return the call to Vanessa just to remind you about how to enter the Q&A queue.
[Operator Instructions].
Thank you, Vanessa. Our first question this morning is from Shar from Guggenheim.
So just a couple of questions here. Focusing on the core business, I mean you provided an in-depth slide on the Connecticut grid mod filing you had this week. And you've also stated in the past that the total AMI opportunity in Connecticut and Massachusetts is a little over $1 billion of CapEx that would be incremental to plan.
So if we sort of take this incremental opportunity, pair it with the accretive Columbia Gas deal, does it support sort of the top end? Or are we in a situation where the actual growth guide can actually change to maybe 6% to 8%? So I guess how do we -- how should we sort of think about the shape that you kind of highlighted, especially when you're layering in offshore wind and you're rolling growth forward? So is it a function of supporting a higher end of that growth? Or does the actual CAGR change in time?
Thanks for your question, Shar. The answer to that is the grid modernization program in Connecticut is really still in the midst of a process to review the 11 categories. And really, the goals are to eliminate the barriers to grow in the state's green economy, transition into a decarbonized future, enabling customers to access resilient, reliable, secure energy. So the PURA process is underway, and the exact details of that won't be developed until we move through the entire process. So depending on -- I guess it's premature to provide a guidance there, but as we move through the process with PURA, the programs will become clear. The spending levels would become clear. Sort of the time periods will become clear. And then it would be -- we'd be able to kind of slot those into the plan.
But certainly, if you're making smart investments in growing rate base to benefit customers like we do and are able to keep your costs under control and you have a benefit of an accretive transaction, that should help bolster your earnings potential and growth prospects going forward.
Okay. Got it. And then just one last question is the Connecticut assembly members sent a letter to PURA earlier this week requesting they suspend the rate increases that went into effect that you guys suspend on July 1. PURA took this as like a formal motion for reconsideration and will rule on the motion after considering sort of comments. Any thoughts there and expectations on this development?
Sure. Certainly, there's been some press related to customer concerns about high bills in Connecticut, and I can assure you that we have in the past and we continue to work with our customers in a broad sense, in one-on-one, really to reduce bills. We have a variety of customer care programs. We have extensive and we are extending financial assistance programs to help customers manage and reduce future bills. We have award-winning energy efficiency programs and support for that. As I mentioned in my script that there's a moratorium, there's no shutoff. We're not shutting off customers, and we're working diligently to help customers in this pandemic situation.
I will say that the bills in general are due to much -- the higher bills are due to much hotter weather this June, really, and more customers working at home. I think we're all doing that. Residential sales at Connecticut Light & Power spiked in June. Really, the residential kilowatt hours were 26% higher this June versus last June, and 36% kilowatt hour usage was 36% higher than May.
So a customer gets one bill and they see it, then they get the next bill and they see an increase. But there's been a 36% increase in usage. That's really driven by -- I'd say, 85% or more is driven by this record level of usage. In fact, anecdotally, the weather has still been hot afterwards. I mean we've been going through some heat waves, and we've been setting some -- the record levels of temperature. So really, there's some additional items. We have a contract to provide payment and subsidy, some might say, to Millstone Nuclear Plant. We had some transmission true-ups that we do that's really just to reflect an under-collection of transmission.
So overall, sort of on a rate standpoint, the rate overall on a customer's bill is only up about 3.5%. And I think when you look at the impacts of the Millstone, without that, we didn't have that contract, the actual rate would have been about $5 lower for a typical customer. So the -- I think, certainly, there's a reaction. People are hurting. We want to help, be a part of the solution here. And usage is the driver. So our energy efficiency programs and other programs that we have are going to come to the forefront. So we're working closely with all our customers, with the regulators and other folks to get the message out about the drivers and what can be done to help mitigate usage in the future.
Next question is from James Thalacker from BMO Capital Markets.
Real quick question on Columbia, and I don't want to put the cart before the horse or get too granular, but as we're thinking about the accretion, I know you've spoken about it being accretive in the next 12 months post the close. But as we think about kind of, say, maybe a mid-30s kind of net income that was being booked when NiSource was running it and then there's some shared services, can you talk a little bit about how quickly you think those shared services will sort of roll off? Any sort of guidance you can give us on kind of what the magnitude of that was? And finally, I guess, just when do you think you could get -- at least approach that kind of allowed ROE that you guys have settled on in that 9.7% range?
Okay. Well, thank you for the question. And really, we're very excited with this transaction. Really, the primary heating source in Massachusetts, gas is really good. It displaces dirtier oil that's being used for heating. So in terms of expanding the gas footprint, we believe that the gas delivery infrastructure is critical to own in the state going forward. So this transaction is very positive from a customer and a company standpoint.
As you can imagine, we're in the midst now of our integration efforts with Columbia. We did enter into, I'd say, a very constructive settlement agreement with the parties. I discussed that the approval is expected by the end of September. We're still in the process of parsing out what functions we can take over on day 1, what functions we're going to need to have a transition agreement, how those -- how that transition agreement will work, over what time period.
So we should say, I'm not putting the cart before the horse, but I think our expectation, and I'd be disappointed if we weren't able to earn our authorized returns within a few years there that we have some incremental costs and some processes to improve right from the get-go and knowing our track record for our ability to do that. I'd say very quickly, we should be able to make those processes hum, I'd say, into our Eversource process. So again, I'd be disappointed if we weren't able to get up to that level within a few years.
Okay. Great. And just one last, I guess, question, just rounding that up. The amount of debt that you guys have to do to sort of complete the transaction is pretty de minimis, but I was just wondering if you guys had put any sort of interest rate swaps or sort of locked in the interest rate on that at this point.
We use a variety of -- you can hedge some rates. You could just try to look at your debt profile in terms of identifying times to go. So I'd say that in general, we're not big on swaps and we do a little bit more plain vanilla sort of, I'd say, long-term debt financing.
Got it. More part of your sort of your omnibus debt financing you do for the corporation.
Yes, exactly. It's similar to how we do it with the rest of the corporation.
Our next question is from Sophie Karp from KeyBanc.
Congrats on the quarter. So I wanted to chat maybe a little bit about the offshore wind and the progress there. And just are there any concerns with everything that's been going on in the supply chain with the availability of equipment? Or if has anything changed, I guess, with respect to how the supply chain is developing in the U.S.? And how much equipment is available from outside of the U.S. given all of the disruptions we are seeing from the pandemic?
Good question, Sophie. We -- certainly, the step 1 in this process is putting together a compelling bid to win an RFP that is both at an appropriate level for -- to achieve our mid-teens return target. Sort of step 2 is getting through all the -- getting through the permitting application processes that we're saying. But a key element of the construction plan is certainly the supply chain that you pointed out. And I can assure you that from the joint venture standpoint, from our team working on the project, Ørsted's team, that, that is a priority to stay connected to suppliers, to understand what the queues are, how we can manage those queues to effectively deliver.
So I can't guarantee that there isn't a supply date that somebody might not be able to make because of COVID-19. But I'd say, overall, I'm comfortable that we've had a high degree of high-level interest and oversight over the supply chain so that we're on top of the current situation.
Okay. Okay. No, that sounds fair. And I guess, overall, the expectation would be that the development costs would decline as we have more of these projects under development and more coming online and turbines are getting larger. Is this trend sort of something that can be accelerated even more by COVID, you think, because of greater industrial capacity availability maybe? Is that something that we talked about? Or is that fair?
Yes. I think that COVID or no COVID, I think the supply chain costs are coming down. And I think the trend over the last several years has been costs on the downslope turbines getting larger. So I'd say that that's been a trend that's been there despite the pandemic. And whether or not there's additional manufacturing or industrial capabilities to who are doing something else that now can retool to move into offshore wind, I think that could only be even more helpful. So think there's an underlying trend of bigger and less expensive overall. And possibly, as you suggest, with additional capacity that some manufacturers have, that could even provide more opportunities to accelerate that trend.
Our next question is from Durgesh from Evercore.
Can you perhaps comment on what kind of bill increases, I'm thinking percentage bill increases, are you proposing in the 8-year plan in Massachusetts?
I didn't catch the last, in the what plan?
In the 8-year rate plan in the Columbia Gas of Massachusetts settlement that you filed. Just wondering if you can share with us what impacts are you proposing to customer bills.
Okay. So yes, good question. I'm sorry, I didn't catch the back part of that. But essentially, as I talked about, there's no change until 2021 and 2022. So there's really -- in the near term for Columbia Gas transaction, we're not proposing to make any change, that those changes get implemented over the following year and the year after that. So really, there's -- the normal course of business in terms of Massachusetts Gas activities is that aside from the base distribution rate, we have this accelerated pipe replacement, we call GSEP, gas system enhancement program. And that's where I mentioned that I would expect that Columbia will continue with about 45 miles of pipe replacement over the course of -- over the -- as annual pipe replacement. So really, there's no increase until November of '21 and November of '22, and I'd say those increases are modest at that point.
Understood. Very helpful color. And then just can you remind us of your current consolidated tax-paying status? And then if that changes with the Columbia gas acquisition?
We are a taxpayer. We had -- we've always talked about being a taxpayer in the neighborhood of $100 million in that standpoint. So we still continue to be that. We might be, in 2020, more in the $150 million, $160 million range in terms of federal and state taxes combined. So that's -- with Columbia, certainly, if you have -- there's net income there that would -- that could change your tax position, but that's the position we're in. We've been a taxpayer, and in 2020, slightly elevated from where we had been before. So we might be in the $150 million, $160 million range in terms of cash tax.
Perfect. And just one really quick one. Anything in particular on the -- I appreciate water business is decoupled in small portion of your earnings power. But anything in particular in terms of COVID trends there which are different from the electric gas? I mean are you seeing the same dynamic, residential being higher, commercial industrial being lower? But anything in particular different on the water side than -- compared to electric gas real quick?
No. There really isn't, on the COVID front, any difference. The same safety protocols in place, the same kind of people working from home issues of usage. The only -- the other thing we've seen, again, it's not COVID related, it's just because of the hot humid weather and lack of rain, people were -- have been using more water for irrigation purposes, but nothing on the COVID side that's different.
Our next question is from Jeremy Tonet from JPMorgan.
Just want to start off with offshore wind again here. New York recently upped the RFPs and it's now seeking 2,500 megawatts of capacity here. The deadline seems like it's coming up this fall for proposals. I imagine this could be of interest to Eversource. And just wondering if you could comment on the market dynamics, how you see that -- they've evolved in these type of competitive bidding process over time. It seems like they've been pretty aggressive bids. I'm just wondering what your thoughts are on here and what's your strategy.
Thank you for the question. Our strategy is one that targets financial discipline and financial returns that are at the higher end of our return profile. So that would be in the mid-teens level. So we work actively with Ørsted, and we develop joint proposals. I can assure you that we -- in our proposals, we look to uncover every rock, so to speak, in terms of what's included in that proposal, both from a financial and nonfinancial sort of economic development standpoint.
So most of these proposals have a financial element to them and a -- sort of an economic development element to them. So we work effectively with our partner to do that. Certainly, there have been other participants, there are some players who purchased leases in the recent lease auction by the Federal Government that are now in the game, I'd say, to prepare RFPs. Our approach has not been to chase those or to win a bid, but to be disciplined and to focus what we do well and bid accordingly.
Got it. That's helpful. In the first scheduled technical conference to explore whether existing policy can accommodate future offshore wind growth, just wondering if you could refresh us on your thoughts on how you see your transmission asset position here. And do you think you can accommodate future growth? Just any thoughts on that in general would be helpful.
Sure. I think it goes in phases. And certainly, in our region, so in New England, as you know, there's been many large power plant retirements, whether they be nuclear or coal or oil plants that have retired over the last several years. And those retirements have been -- happened to be in locations that are very conducive for offshore wind to make landfall to connect into. So there's good onshore interconnection capabilities as a result of those. I'd say, there's robust switchyards, things like that. We've invested a considerable amount of money in our transmission system over the last decade to upgrade and make it more resilient.
So I'd say, in the near term, for what's on the drawing board, I think that aside from specific locations, if you're landing in a specific location, you might need to do a specific upgrade. But in the big picture standpoint, I think the interconnection points, the transmission system in this region capable of handling the RFPs that are out there. If -- x years down the road, if those -- there's more and more and more desire for offshore wind and more interconnection points needed, you may run into constraints where the interconnection locations that have capacity now may get used up.
So I guess from a timing standpoint, in the near term, I'd say, the transmission investments are more localized depending on the landing place and what that substation might look like. So in a big picture standpoint, we're in good shape. But as time goes on, the capacity could be used up and require additional transmission investment.
Got it. So fair to say in the near term, you don't see any sizable transmission project needs, maybe at some point over time but nothing sizable transmission in the near term?
Well, they could -- as I said, there could be a specific substation. When you say sizable, there's not billions of dollars, but you could have substation upgrades 50s millions, hundreds of millions of dollars or something like that, but that would be specific to the location of where the landing interconnection point is. So I'd say it's kind of location specific and not a broad investment.
Our next question this morning is from Mike Weinstein from Crédit Suisse.
I just wanted to ask about the -- as you think about the new gas business from Columbia, is that additive to the 6% to 8% growth rate over time? Or is that in line with that growth rate considering the accretion that's going to happen off the bat bringing up the ROE?
Well, Mike, as you know, our growth rate is 5% to 7%.
I'm sorry, 5% to 7%, 5% to 7%.
I'm glad you think -- that's why we're such a high-performing company there. 5% to 7%...
Going to get more sleep.
But as I may have said earlier that, certainly, as that property gets to be, I'd say, hitting on all cylinders once we can get all the integration efforts done, we're no longer using transition service agreement, we're able to move all the functions over to an Eversource system, et cetera, that we feel very good about being able to get to the allowed returns that are in the settlement. And as you know, summon hasn't been approved yet.
So -- but my -- if you look at our history of being able to operate effectively, our operations team does a fantastic job in terms of keeping our system up and running, whether it be, as we say, a blue sky day or whether it be a trouble on the system, keeping the gas flowing, investing appropriately so that we can reduce O&M that -- right now, the contribution from Columbia is not in our guidance number. So that is going to be helpful. It's going to add to whatever number we had having Columbia in there because it's accretive transaction.
Do you think it will be additive to that growth rate, though, going forward as you roll -- especially as you roll forward your CapEx plans and your growth rate by the next year?
Yes. I think it's more probable to be additive, right, to either move it up in the range or help -- go above that, but we're not making any determination of that at this time. But certainly, there's financial benefits of the transaction, as I mentioned, as well as customer, community and state benefits to us moving in on that system. So we feel it will be additive to the story.
Great. And on Connecticut grid mod, how has that -- the financing for that program? And is that reflected in your current plans? Or -- especially since some of that goes out beyond the current 5-year plan, has all that been already reflected in the plan? Or is that going to require some more financing plans approved?
So just to be clear on the grid mod across the 3 states. The only grid modernization investment that is in our current plan is in Massachusetts where we have approval, spend $233 million on a variety of programs, including battery storage, EV infrastructure, technology enhancements, et cetera. So there's nothing in our plan right now for New Hampshire or Connecticut. And the reason for that is there's been no approval of any plans there. So as -- so to answer your question directly, there's no financing need because we don't have anything in the plan right now for grid modernization of the Massachusetts.
If, in fact, we go through the processes in the various states and programs develop and spending gets identified, then we'll have to determine what that does to the investment plan, whether -- how we're going to finance that, et cetera. But right now, there's nothing in the plan, so there's no financing associated with it.
Next question is from Paul Patterson from Glenrock.
So back to the Connecticut grid mod, I apologize if I missed this. How should we think about that impacting rates? I know you got some CapEx, but also maybe there might be some savings with AMI. Can we get a little bit of a sense about how that works?
Yes. I think that it depends on what the size of the programs are that the PURA would approve going forward. So it's really difficult to answer specifically what that is. I mean some of the spending we're going to have to do -- as I mentioned, we're going to have to replace our meters anyway. So if we work on an AMI program, that we'll be buying AMI meters instead of other meters, so how much of that is incremental, what level of battery storage or EV infrastructure does the state want. So right now, it would just be hypothetical. And until we get some approval from the -- from PURA, there's really no impact in -- on rates because there's no programs in place in Connecticut right now.
Overall, I'd say, overall, if you look at the Massachusetts example, it's modest in the sense of the spending. It's $233 million over a multiyear period, so it's less than $100 million a year type of thing. So even if you took that kind of approach, it's not going to have a dramatic impact.
Okay. What -- with respect to Millstone, did I hear you correctly, that's $5 a month effectively of the bill increase that's causing such a stern to Connecticut right now?
Well, what I said was in Connecticut -- and you can imagine, right, that we're all working from home. I'm working from home. I'm sure you're working from home. And so people are not used to having their air conditioner around all day. I know that before I left in the morning, I'd adjust my temperature of my thermostat or have your nest adjusted because you're not there. And now people are there 24/7, and it's been really -- it's been hot. And I said that weather is really the -- has caused the increase in usage, I mean, in the bill. I mean 36% more usage from our -- kind of in our residential customer segment than the previous month. So you were using 36% more than you were using in May and June. And if you want to go back to last year, June to June, you're using 26% more. So either way, you're using a lot more. And really, the weight -- as the bill is the rate times the usage, so the usage is up dramatically, the rate in the calculation is up about 3.5%. If you look at the total rate, the distribution charge, the energy charge has gone down.
So what I said was Millstone, there's -- we have a requirement to buy power out of Millstone is a charge on the bill for that purchase. And what I said in terms of the $5 was if that wasn't there, if we weren't buying that power there, that the typical customer bill -- like EEI says 700 kilowatt hours is kind of a typical customer. If you were to take that typical customer bill, it would have gone down by $5, so -- as opposed to increasing.
So that is a part of it. Usage is a part of it. We had some transmission under collection, but you move into the next period to collect. So all those things combined are impacting the customers' bill. And we're trying to work with the customers and regulators, whatever, on this. First of all...
I know you are. I know you guys take it very seriously. I guess all I'm sort of wondering, though, is that this is a little unusual in that we've had legislative leadership. We've got this letter. We've got the PURA almost immediately responding. We're seeing -- we look -- as you know, we're looking around the country and what have you. When we see this, it is rather -- one of the things that's come up in the media is this focus on Millstone. But then also, as you know, we've got offshore wind. We've got other calls coming in.
And I'm just wondering, I'll just lay it out here, how do you guys see -- I know you guys are trying to manage it. I know you guys are doing energy efficiency and what have you, but how should we think about when we see something like this? Is it just sort of a blip? In other words, all the things that you're talking about is a perfect storm here thing? Or should we think about perhaps other efforts or issues to manage the situation over time, if you follow what I'm saying?
I do. I follow what you're saying. We take bill impact very seriously. Any decision we make for investment opportunity, we fully assess the bill impacts. At the end of the day, customers are paying for these investments. And we have a responsibility, and we take it very seriously to make sure that the impacts there are not significant and not -- that the price -- the cost of the improvement is worth it.
And if you -- really, we -- if you look at our history, I put our track record up against anybody in terms of ability to take costs out of the system. We -- post merger, we took 5% O&M out of the business every year, over $250 million. When we've been in for recent rate reviews, the headline story has been our O&M costs today as part of the rate filing are less, not by inflation, just absolutely less today than they were 10 years ago. And our service is 30% to 40% or more higher.
So we take it seriously to keep our costs down. And if we're putting capital in, that O&M comes out and so -- but it is something that -- we look at impacts on a custom bill. But I do think to your kind of analogy, it is a bit of a perfect storm in the sense of everybody is home, the weather has been extraordinarily hot, and I think the usage is really what the driver is. And I think as people see what the real components of the change were, that the governor, the legislature, the regulators, the customers will have a better appreciation that it's more related to usage than anything. 80% to 90% of it is usage related.
Next question is from Ryan Levine from Citi.
Do you see any green hydrogen or other hydrogen-based opportunities to leverage your platform? And have you started to pursue any of these potential opportunities?
Thanks for the question. And certainly, hydrogen has been sort of in the news or it's a topic and whether it be transportation or other usage. And I'd say we're in the phase now. We're evaluating the possible usage of hydrogen and various aspects of our business, again, whether it be an alternative for transportation or whether it be for some other component of introducing it to our gas distribution infrastructure. So I'd say, at this stage, we're tracking its progress globally and we'll keep an eye on it. But we have not, say, identified any specific applications at this stage.
Okay. And maybe just one follow-up. On that point, are you looking at anything to integrate some of your wind development opportunities with hydrogen? Or is it more for the LDC and transportation [indiscernible]?
Well, as I said, we're tracking all possible applications there. But there haven't been any specific identified on the offshore wind side at this stage.
Next question is from Julien from Bank of America.
So perhaps just to wrap up the start of the call here. On the timing for updates with CMA and otherwise, would the expectation you're going to roll in CMA accretion into the 4Q roll forward? And then as you think about some of these other CapEx items, we'll probably make it into the next iteration in '22. I'm just thinking about the Connecticut en masse, both on the AMI and the EV storage process. Just when do you expect to make these updates and roll forward and integrate it all at once, if you will? Perhaps going back to the core of Shar's question, if you will.
Yes. Thanks for your question, Julien, and I hope you're doing well. The timing lines up just as you say, that in terms of the expectation for any real finalization of programs, et cetera, out -- in the Connecticut grid modernization, we'll be getting approval for Columbia at the end of September. So it all sort of neatly times up -- times together so that we can roll it into the update that we do in the fourth quarter. So that would be my thinking at this stage. If something would happen to change that, but I think the base thinking is that they would all be rolled into the next update.
Excellent. All right. And then quickly on the offshore, I don't want to beat this up too much, but can you just define the parameters of what's the opportunity for you all, just in terms of timing the size of the project when you think about your own lease size availability and how that lines up against the resource RFP that they're looking for? I just want to kind of frame the timing, the synergies and the total size as you see it today. Again, I'm not going to hold you to it, just broadly the parameters.
Well, a couple of the general parameters are our two lease areas can develop, say, 4,000 megawatts of offshore wind. We currently have 1,710 megawatts of offshore wind under contract. So just -- not quite half of the lease areas are under contract right now. So in terms of what's available to us, we have kind of a 4,000 megawatt opportunity we've identified up and down the New England states included. And then if you include New York into that, that there's more capacity that is being sought by the states than what the lease -- all the leases combined have the opportunity to produce. So we think that our leases are well situated in terms of their proximity to shore. Our leases are well situated in terms of ocean depth. Our leases are well situated in terms of wind speed.
So we think that -- and plus we're into those leases at a small amount of money compared to the $130-plus million that the recent lease owners bought their leases at. So -- but from a cost standpoint, from a lease location and size, I think the opportunity is still very strong for us in the future and the RFPs that are out there are only going to get more as we go forward.
Timing settlements on New Hampshire, lastly?
So we have a rate proceeding in New Hampshire. It has been -- it was delayed a bit, I'd say, from the COVID situation. But we're looking to finalize that later in this year, probably in November, with rates effective in December. But as you recall, in New Hampshire, it's kind of a 2-phase process. So we received temporary rates in July of 2019. So whenever we get the final rate decision, they kind of go retroactive back to that point. So -- but the -- to answer your question directly, the final decision is we're looking at the November time frame with the rates effective December 1.
Next question is from David Arcaro from Morgan Stanley.
I was wondering if you could run through the equity needs in the forecast right now. And was also curious if you would anticipate that CapEx associated with growing the Columbia Gas business over time and the kind of yet to be approved Connecticut grid mod CapEx would also potentially need any additional equity on top of the base plan.
Thanks for the question, David. Hope you and your family are doing well. So what's in our plan right now is about $700 million of equity needs to support our plan that we've laid out that goes through 2024. So in that plan, Columbia was not in that plan. So we did a separate financing for Columbia. But going forward, we'll have to incorporate Columbia into our plan going forward.
And then as I mentioned earlier, we do not currently have any spending for Connecticut or New Hampshire grid modernization in the plan. So the $700 million supports the current $14 billion CapEx plan that we have. As we look to update that going forward, we're going to have to consider cash flow, cash from operations, what we have maturing, what we might need to do. So I'd say that's to be determined and would be disseminated when we update the -- our plan at the Q4 call.
It looks like we have one more questioner in the call -- in the queue. Travis Miller from Morningstar.
Just two quick ones on Columbia. One, what is the pipe replacement CapEx as a share of the total CapEx? That's the first one. And then second one, if you're able to close by the end of October, would there be any material earnings impact this year from Columbia?
So I'll answer the second question first. No, nothing material. We expect to close soon after getting approval from the DPU. There could be a few months of operations in the numbers, but I'd say nothing material is expected for those for that time frame.
In terms of the exact percentage of GSEP to total, I'm going to have to get you the information on that. I don't have that off the top of my head, Travis, but we can get back to you on that.
Okay. No problem. And then two quick ones on offshore wind. One with the New York RFPs, is there any chance that you guys could be more competitive, either lower cost or better synergies, with Sunrise Wind relative to other bidders who might have no stake there right now in New York? And then that was the first one. And then second, New Jersey has thrown out a whole bunch of big numbers on offshore, would you be interested in doing anything in New Jersey?
So in terms of the second part of your question, our lease areas really are best suited for New Eng to reach any RFPs that go on in New England or into New York. So New Jersey would be a bit far for our lease areas to be truly effective in reaching. So I'd say New Jersey would not be part of our strategy.
In terms of our competitive position, yes, I mean I'd like to think we'd be competitive anywhere, whether we have a contract or even if we don't. I mean that -- and certainly, there are advantages of having contracts. There's advantages of having plans already in place and an understanding of the area. But I think that I am thrilled that our partner is the worldwide leader in offshore wind development with Ørsted. We're the -- I'd like to think the very -- in a leadership role in terms of our transmission and our local knowledge and ability. So I like our chances whether we already have existing contracts or don't have existing contracts to win RFPs that come out. But certainly, there are advantages if you do have contracts in place, I'd say.
All right. And that wraps up all the questions for today. So we want to thank you very much for joining us. And please follow through with any e-mails or questions by phone if you have any. Have a great day and a great weekend.
Thank you.
Thank you. Ladies and gentlemen, this concludes our conference. Thank you for your participation. You may now disconnect.