Eversource Energy (ES) — Q2 2020 Earnings Call Transcript

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. I hope everyone on the call is healthy and that your families are doing well. This morning, I will discuss several topics, including the second quarter results of 2020 and the effects of COVID-19 on our customers and their energy consumption. I’ll also review recent regulatory developments, including new proposals for grid modernization in Connecticut and the status of our application in Massachusetts to acquire the assets of Columbia Gas of Massachusetts. Lastly, I will provide an update on our offshore wind investment partnership with Ørsted. So let’s begin with Slide 2, where recurring earnings were $0.76 per share in the second quarter of 2020, compared to $0.74 per share in the second quarter of 2019. GAAP results, which include a $0.01 charge per share related to our acquisition of Columbia Gas, amounted to $0.75 per share, in contrast to earnings of $0.10 per share in the second quarter of 2019. Last year's results included a $0.64 impairment charge pertaining to Northern Pass. In the first half of 2020, our recurring earnings, excluding Columbia Gas, totaled $1.77 per share compared to $1.71 per share in the first half of 2019, also excluding the NPT impairment charge. Now, looking at our business segments, our electric distribution segment earned $0.34 per share in the second quarter of 2020 compared to $0.33 in the same period last year. This improvement was driven by higher revenues, though partially offset by dilution and increased O&M costs, depreciation, and interest expense. Our electric transmission segment earned $0.39 per share in the second quarter of 2020, as opposed to $0.37 per share in the second quarter of 2019 when excluding the NPT charge. This increase was due to a higher level of investment in our transmission infrastructure, again partially offset by dilution. Our natural gas distribution segment earned $0.01 per share in the second quarter of 2020 compared to a slight loss in the same period last year. The improvement stemmed from higher revenues, though offset by O&M and depreciation costs along with dilution. Our water distribution segment earned $0.03 per share in the second quarter of 2020, compared to $0.02 per share in the second quarter of 2019, largely influenced by higher revenues and lower depreciation expenses. At the Eversource parent level, we lost $0.01 per share in the second quarter of 2020, excluding Columbia Gas acquisition costs, in contrast to earnings of $0.02 per share in the same quarter last year. This change was primarily driven by lower mark-to-market earnings this year on a clean energy investment made years ago, which is a fund maturing soon. As mentioned in our news release, on Slide 3, we are reaffirming our 2020 earnings per share guidance of $3.60 to $3.70, as well as our long-term EPS growth rate of 5% to 7%. We expect that our existing core business will allow us to grow earnings around the midpoint of that range through 2024. Incremental growth will come from offshore wind and the Columbia Gas acquisition. Offshore wind earnings are expected to begin in the later years of the forecast as the turbines come online, while we anticipate the Columbia Gas acquisition to positively impact our EPS starting in 2021. Moving on to Slide 4, I want to highlight our ongoing success in managing the business during the COVID-19 pandemic. Our strong safety and reliability performance has continued throughout the first half of the year. We've effectively and promptly responded to all storms we've faced, and nearly all employees who tested positive for COVID-19 or were in self-quarantine are now back to work, providing excellent service to our 4 million customers. We are on track to execute our $3 billion capital program, with our capital expenditures totaling $1.44 billion through June, which is about $30 million ahead of last year's pace. Regarding usage, overall kilowatt hour sales in the second quarter were down approximately 1.4% compared to last year. However, in New Hampshire, which is not decoupled, sales actually increased by 1.8%. The residential sales in New Hampshire were particularly strong, mainly due to more customers being at home and favorable weather conditions. We experienced cooler-than-normal weather early in the quarter and then hotter and more humid weather in late May and June. In the natural gas segment, where both Yankee Gas and NSTAR Gas are decoupled, sales in the second quarter rose by about 1.7% compared to last year, driven by colder weather in April and early May. On a weather-normalized basis, sales dropped about 7% due to decreased commercial and industrial usage. In our water segment, which is decoupled in Connecticut, unit sales increased by 7.1% in the second quarter, primarily due to customers irrigating their properties during a hot and dry June. We are not shutting off customers for nonpayment, maintaining that policy. Connecticut and New Hampshire have different schedules for when shutoff moratoriums will be lifted. In Massachusetts, we’re collaborating with a group reviewing policies on payment plans and shutoffs for nonpayment, with no due dates currently ending the moratorium. Despite these moratoriums, the impact of COVID-19 on our overall receivables has been manageable so far. Regarding recent developments in our ongoing rate reviews, I’ll turn to Slide 5. We have two general reviews ongoing. Hearings for the NSTAR Gas rate review in Massachusetts concluded a month ago, with final reply briefings scheduled for August. We expect a decision by the end of October, with new rates effective November 1. In New Hampshire, the Public Service of New Hampshire rate review hearings will begin later in August, with a final decision anticipated in November. New rates would take effect on December 1 but would be retroactive to July 1, 2019, when a temporary $28 million rate increase occurred. From the rate reviews, I'll now turn to grid modernization and the filing we're making in Connecticut 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 three 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 nearing the end of its useful life, and we'll need to replace about 800,000 meters one way or another over the next five years. This 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 the state of Connecticut to target about 125,000 electric vehicles on the road by the year 2025. Our proposal combines rebates and infrastructure investments over a three-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 non-utility parties today. In Massachusetts, we continue to implement the grid modernization plan authorized by regulators more than two 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 three-year plan with implementation during 2022 through 2024. 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 three times oversubscribed and priced without a discount to the prior day's close. 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 customers, 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, include 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 on August 25 and August 27 to take up the matter. The settlement structures an eight-year rate plan with modest rate increases on November 1, 2021 and 2022, respectively. There are additional base rate resets on November 1, 2024. 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. 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 will 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 two 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 was anticipated by the offshore wind industry. They were the primary reason that the four developers in the six ocean tracks off Massachusetts, including our partnership with Ørsted, proposed a one nautical mile by one 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 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. 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. 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. 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. 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 that the winners can benefit from expiring federal tax credits. We and Ørsted expect to bid into that RFP. Sunrise Wind partnership won 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.

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, you provided an in-depth slide on the Connecticut grid modernization filing you had this week. You 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. If we sort of take this incremental opportunity and 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 guidance could change to maybe 6% to 8%? How should we sort of think about the shape that you highlighted, especially when layering in offshore wind and rolling growth forward? Is it a function of supporting a higher end of that growth? Or does the actual CAGR change over time?

Thank you for your question, Shar. The grid modernization program in Connecticut is currently in the process of reviewing the 11 categories. The objectives are to remove obstacles to growth in the state's green economy, transitioning to a decarbonized future while providing customers with access to resilient, reliable, and secure energy. The PURA process is ongoing, and the specific details will only emerge as we progress through it. Providing guidance at this stage is premature, but as we move forward with PURA, the programs, spending levels, and timelines will become clearer. We will be able to incorporate those into our plan. Making strategic investments to expand our rate base to benefit customers, while keeping costs manageable and taking advantage of an accretive transaction, should enhance our earnings potential and growth prospects in the future.

Got it. And then just one last question is about the Connecticut assembly members who sent a letter to PURA earlier this week requesting they suspend the rate increases that went into effect that you guys suspended on July 1. PURA took this as a formal motion for reconsideration and will rule on the motion after considering 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 assure you that we have in the past and continue to work with our customers generally, on a one-on-one basis, to reduce bills. We have a variety of customer care programs. We have extensive 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, there's a moratorium, and we're not shutting off customers. We're working diligently to help customers in this pandemic situation. I will say that higher bills are due to much hotter weather this June, really, and more customers working at home. Residential sales at Connecticut Light & Power spiked in June. Residential kilowatt hours were 26% higher this June versus last June, and 36% kilowatt hour usage was 36% higher than May. A customer gets one bill and sees it, then the next bill sees an increase. But there has been a 36% increase in usage, and that's really driven by records. Anecdotally, the weather has still been hot afterwards. We've been going through some heatwaves. The bills are due to other factors, including our contract to provide payment to Millstone Nuclear Plant and some transmission true-ups that reflect an under-collection of transmission. Overall, from a rate standpoint, the bills overall are only up about 3.5%. When looking at the impacts of Millstone, without that contract, the actual rate would have been about $5 lower for a typical customer. There's a reaction. People are hurting. We want to help, and usage is the driver. So our energy efficiency programs and other programs are coming to the forefront. We're working closely with all our customers and regulators to communicate 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. 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 closure. But as we think about a mid-30s kind of net income that was being booked when NiSource was running it, can you talk a little bit about how quickly you think those shared services will roll off? Any guidance you can give us on the magnitude of that? Finally, when do you think you could get at least approach that kind of allowed ROE that you settled on in that 9.7% range?

Thank you for the question. We're very excited about this transaction. The primary heating source in Massachusetts, gas is very good as it displaces dirtier oil that's being used for heating. We're in the midst of our integration efforts with Columbia. We entered into a constructive settlement agreement with the parties. 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 one, what functions will require a transition agreement, and how that transition agreement will work over what time period. I'm not putting the cart before the horse, but I would be disappointed if we weren't able to earn our authorized returns within a few years. We have some incremental costs and some processes to improve immediately, knowing our track record for our ability to do that. I'd say very quickly, we should be able to make those processes integrate into our Eversource process. I would be disappointed if we weren't able to get up to that level within a few years.

Okay, great. Just one last question rounding that up. The amount of debt that you have to complete the transaction is minimal, but I was just wondering if you had put any interest rate swaps or locked in the interest rate on that at this point.

We utilize various methods to hedge some rates and assess opportunities for issuing debt. Generally, we tend not to use swaps and typically favor a more straightforward approach to long-term debt financing.

Got it. More as part 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. I wanted to chat maybe a little bit about offshore wind and the progress there. Are there any concerns with everything going on in the supply chain with the availability of equipment? Has anything changed, I guess, regarding how the supply chain is developing in the U.S., and how much equipment is available from outside of the U.S. given the disruptions we are seeing from the pandemic?

Good question, Sophie. The first step in this process is putting together a compelling bid to win an RFP that is both at an appropriate level to achieve our mid-teens return target. The second step is to get through all the permitting application processes. A key element of the construction plan is certainly the supply chain that you pointed out. I can assure you that from the joint venture standpoint, from our team working on the project, Ørsted's team, that this is a priority to stay connected to suppliers, to understand what the queues are, and how we can manage those queues to deliver effectively. I can't guarantee there won't be supply delays due to COVID-19, but overall, I'm comfortable that we've had a high degree of interest and oversight over the supply chain, allowing us to stay on top of the current situation.

Okay. That sounds fair. The overall expectation would be that the development costs would decline as we have more of these projects under development and more coming online as turbines get larger. Is this trend something that can be accelerated by COVID, you think, because of greater industrial capacity availability?

Yes. I believe that regardless of COVID, the supply chain costs are coming down. The trend over the last several years has been costs on the downslope as turbines have been getting larger. That's a trend that's been evident despite the pandemic. If additional manufacturing or industrial capabilities are available that now can retool to accommodate offshore wind, that could provide more opportunities to accelerate that trend.

Our next question is from Durgesh from Evercore.

Can you comment on the kinds of bill increases you are proposing, percentage bill increases, in the eight-year plan for Massachusetts?

I didn't catch the last part. In the eight-year rate plan?

In the eight-year rate plan in the Columbia Gas of Massachusetts settlement that you filed. Just wondering what impacts you are proposing to customer bills.

Yes, good question. I'm sorry, I didn't catch the back part. Essentially, as I talked about, there's no change until 2021 and 2022. So in the near term, for the Columbia Gas transaction, we're not proposing to make any change. Those changes will be implemented in the following years. The normal course of Massachusetts Gas activities, aside from the base distribution rate, involves the accelerated pipe replacement program. As I mentioned, I would expect Columbia to continue with about 45 miles of pipe replacement annually. So overall, there's no increase until November of 2021 and November of 2022, and I'd say those increases are modest at that point.

Understood. Very helpful color. Can you remind us of your current consolidated tax-paying status? And will that change with the Columbia Gas acquisition?

We are a taxpayer. We've always talked about being a taxpayer in the neighborhood of $100 million. We still continue to be that. In 2020, we might be more in the $150 million to $160 million range in terms of federal and state taxes combined. With Columbia, certainly, if you have net income there, that could change your tax position, but that's the position we're in. We've been making a tax payment, and in 2020, slightly elevated from where we were before.

Perfect. And just one quick question regarding your water business. I appreciate that the water business is decoupled in a small portion of your earnings power. But are there any COVID trends there that differ from the electric or gas? Are you seeing the same dynamic with residential being higher and commercial/industrial being lower? Is there anything different on the water side compared to electric and gas?

No, there really isn't on the COVID front. The same safety protocols are in place, and the same kind of issues are there with working from home. The only difference is the hot humid weather and lack of rain have led people to use more water for irrigation purposes. But nothing on the COVID side that's different.

Our next question is from Jeremy Tonet from JPMorgan.

I want to start off with offshore wind again. New York recently upped the RFPs and is now seeking 2,500 megawatts of capacity. The deadline seems like it's coming up this fall for proposals. I imagine this could be of interest to Eversource. Can you comment on the market dynamics and how you see that evolving in these competitive bidding processes?

Thank you for the question. Our strategy targets financial discipline and returns that are at the higher end of our return profile. We actively work with Ørsted to develop joint proposals, and I can assure you that in our proposals, we thoroughly investigate everything included, both financially and from an economic development standpoint. Certainly, other participants have purchased leases in recent lease auctions, but our approach has been to maintain discipline and focus on what we do well and bid accordingly.

That's helpful. In the first scheduled technical conference to explore whether existing policy can accommodate future offshore wind growth, could you provide your thoughts on your transmission asset position and whether you think you can accommodate future growth?

I believe it goes in phases. In New England, there have been many large power plant retirements, including nuclear, coal, and oil plants that have retired over the last several years. Those retirements have occurred in locations very conducive for offshore wind to connect. There's good onshore interconnection capabilities as a result of those. We have invested considerably in our transmission system over the last decade to upgrade and make it more resilient. In terms of the near term, I think the interconnection points and transmission system in this region are capable of managing the RFPs out there. X years down the road, there's the risk that the interconnection locations may be used up. In the near term, the vast majority of transmission investments needed are location-specific.

Our next question is from Mike Weinstein from Crédit Suisse.

I just wanted to ask about how you consider the new gas business from Columbia. Is that additive to the 5% to 7% growth rate over time, or is it in line with that growth rate considering the accretion that's going to happen off the bat?

As you know, our growth rate is 5% to 7%. I would be glad to reiterate that. It's important to note that once that property is operating smoothly, and once we complete integration efforts, we are optimistic about reaching the authorized returns from the settlement. The contribution from Columbia is not currently reflected in our guidance number, but it will be beneficial. The Columbia transaction will be helpful, accretive, and contribute positively.

Do you think it will be additive to that growth rate, especially as you roll forward your CapEx plans?

Yes. It will likely be additive, either moving it up in the range or providing an opportunity to exceed the growth rate. We're not making any definitive determinations at this time. There are clear financial benefits to the transaction and customer and community advantages regarding our entry into that system. On the Connecticut grid modernization program, how has that financing for that program been reflected in your current plans? Some of that goes out beyond the current five-year plan.

We need to consider the capital requirements moving forward. In Massachusetts, the approved investment is $233 million over a multi-year period. Nothing is currently in the plans for New Hampshire or Connecticut regarding grid modernization spending. Hence, currently, there aren’t any financing needs.

With respect to Millstone, did I hear you correctly that that's a $5 a month increase effectively that's causing concern in Connecticut?

What I mentioned was that in Connecticut, we are experiencing higher bills due to several factors. People are working from home and using more air conditioning because of the increased temperatures, leading to a significant rise in usage. We observed a 26% increase in residential kilowatt hour usage when comparing this June to last June. The higher consumption is the primary reason behind the rising bills, even though the distribution and energy charges have decreased overall. The bill increase is partly due to our contract for Millstone, which if not included, would have reduced a typical bill by $5.

You’re trying to manage this carefully. Given the external factors, do you foresee any other efforts needed to manage the situation over time?

We take bill impact seriously. Our history shows we've effectively managed costs, reducing operations and maintenance expenses without sacrificing service. The recent demand surge relates to people working from home and the unusually hot weather driving residential usage. We are working with customers and regulators to clarify the reasons behind these billing changes.

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?

Yes, hydrogen has been a topic in the news, and we’re evaluating its possible applications in our business, including opportunities for transportation or introducing it into our gas distribution infrastructure. We are tracking its progress globally and will keep an eye on it. However, we have not yet identified specific applications.

On that point, are you looking at anything to integrate some of your wind development opportunities with hydrogen?

As I said earlier, we're tracking all possible applications, but at this stage, we haven't identified any specific integration of offshore wind with hydrogen.

Our next question is from Julien from Bank of America.

On the timing for updates with CMA and otherwise, would the expectation be to roll in CMA accretion into the fourth-quarter roll forward? What’s your expectation regarding CapEx items and when you think updates will be integrated?

The timing aligns as you say; we expect to get the approvals for Columbia at the end of September. It seems to fit nicely together to be rolled into our update in the fourth quarter. That's my thinking at this stage, provided nothing changes.

Can you define the parameters regarding your project opportunity size and timing based on your own lease size availability? How does that align with resource RFPs?

Our two lease areas can develop approximately 4,000 megawatts of offshore wind. We currently have 1,710 megawatts under contract. We believe our leases are well-positioned in proximity to shore, ocean depth, and wind speed. We entered into those leases at a significantly lower cost compared to others. Hence, our opportunities remain strong to win future RFPs. Regarding timing in New Hampshire, we have a rate proceeding that has been delayed due to COVID-19. We're looking at finalizing it later this year, probably in November, with rates effective in December. The temporary rates were established in July 2019, and the final decision will be retroactive.

Our next question is from David Arcaro from Morgan Stanley.

Could you run through the equity needs in the forecast right now? Will CapEx associated with growing the Columbia Gas business require additional equity?

Currently, our plan anticipates about $700 million in equity needs to support our plan through 2024. Columbia was not included in that plan, as we did a separate financing for it. We do not have currently planned spending for Connecticut or New Hampshire grid modernization. So the $700 million pertains to our existing $14 billion CapEx plan. Any updates regarding future cash flows will be communicated during our Q4 call.

It looks like we have one more question 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? And if you're able to close by the end of October, would there be any material earnings impact this year from Columbia?

No, nothing material is expected right away related to Columbia. We expect to close soon after DPU approval. And in terms of GSEP to total, I need to get you that information, as I don’t have it immediately handy.

No problem. Regarding offshore wind, is there a chance you could be more competitive with Sunrise Wind relative to other bidders?

Regarding New Jersey, we believe our lease areas are better suited for New England and New York RFPs. New Jersey would be less effective for us. We expect to be competitive regardless of our existing contracts, as Ørsted is the world leader in offshore wind development.

Thank you all for joining us. Please follow up via email or phone with any further questions. Have a great day and a great weekend.

Thank you.