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. If you'd like to ask a question, please press the appropriate key on your touchtone phone. Please note that this conference is being recorded. I will now turn the call over to Jeffrey Kotkin. Sir, you may begin.

Thank you, Cheryl. Good morning and thank you for joining us. I'm Jeffrey 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 31st, 2020 and on our Form 10-Q for the 6 months ended June 30th, 2021. 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 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 loss weeks Northeast, 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 utility 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 strong 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 in the 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 into the last of our customers has power restored. I believe 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 the Connecticut Attorney General's office, the Office of Consumer Council, and the States Industrial Consumers for being willing to sit down and work out a settlement that will yield meaningful and immediate bill credits to customers and strengthened the Connecticut focus in 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. Since becoming CEO this past spring, my top priority has been to strengthen our relationship in Connecticut. I have 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 Connecticut's temporary rate docket now behind us, we can move on to other important topics where progress has been hindered by the draining time and resources devoted to Storm Isaias and the interim rate reduction. Supporting the build-out of electric vehicle infrastructure, incentivizing 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 am going to cover some very positive developments in recent months concerning our offshore wind partnership with Orsted. 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 Southwark has received its final environmental impact statement, and we expect a decision to be posted later this month. BOEM's project website anticipates a decision on Southwark's construction and operating permit in January of 2022, and we anticipate construction beginning early next year. We continue to expect commercial operation of the 12 turbines, 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. Now 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, we continue to anticipate a cop decision in July of 2023, which would support a 2025 in-service date. State citing hearings have commenced. Finally, our largest project, Sunrise Wind, which will supply 924 megawatts, we're 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 U.S. that will utilize high voltage direct current technology. HVDC offers advantages over AC technology when used over long distances. In Sunrise, there will be 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 partnerships with Ocean Trex off of 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 760 megawatts we currently have on 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 discouraged 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 in supply chain development. As such, the governor recently filed legislation that would eliminate the state's current price gap. In Rhode Island, we're constructing a service vessel in the state. In Connecticut, we are partnering with the state on 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 the Governor'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 Distiller will construct advanced foundation components at the port on the Hudson near Albany. It's 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, and disciplined bidding strategies, alongside Orsted'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 will discuss several topics: our third quarter results, details about the Connecticut settlement, updates on grid modernization, electric vehicle initiatives, and the natural gas outlook for the upcoming winter. I will begin with our quarterly results. Our GAAP earnings were $0.82 per share for the quarter, which includes a $0.19 charge related to the Connecticut electric rate settlement and a $0.01 charge from the integration of Eversource Gas of Massachusetts. Overall, we saw improved operating results in the electric transmission and distribution segments, although the natural gas and water segments, along with our non-regulated and other areas, showed weaker performance. Our electric transmission business reported earnings of $0.40 per share in the third quarter of 2021, an increase from $0.36 in the same quarter last year, due to higher investments in our transmission facilities. The electric distribution business, excluding Connecticut rate settlement charges, earned $0.62 per share in the third quarter of 2021, compared to $0.60 in the third quarter of 2020, with higher distribution revenues offset by increased operational and tax expenses. Storm-related costs remained a challenge, costing us an additional penny per share in the third quarter of 2021 compared to the prior year, and a total of $0.05 per share more year-to-date. Our natural gas distribution business faced a loss of $0.06 per share in the third quarter of 2021, compared to a loss of $0.04 during the same time in 2020, exacerbated by the seasonal nature of customer usage. This loss has increased about 50% due to the acquisition of Columbia Gas of Massachusetts assets last October. Eversource Gas of Massachusetts recorded a loss of about $0.03 per share for the quarter, lacking a comparable amount in the previous year. It is important to note that this is the first full year for our Eversource Gas of Massachusetts franchise, and earnings estimates have varied significantly. Investors underestimated the positive contribution of $0.14 per share from EGMA in the first quarter and may have incorrectly estimated EGMA losses in the third quarter. As mentioned, EGMA lost $0.03 in the quarter, having been absent from the Eversource family in the prior year’s third quarter. With a complete year of performance available, I anticipate that future estimates will more accurately reflect earnings patterns for this franchise. Our Water Distribution Business, Aquarion, earned $0.05 per share in the third quarter of 2021, down from $0.07 in the third quarter of 2020. This decline was mainly due to the sale of the Massachusetts water system in July 2020. The $17.5 million earned in our water segment during this quarter represents a normalized level for this segment. Our parent and other segment earned $0.01 per share in the third quarter of 2021, down from $0.03 in the same quarter last year, primarily due to a higher effective tax rate, which was 24.8% in the third quarter of 2021 compared to 23.7% in the previous year. Turning to our EPS guidance on Slide 5, we reaffirm the $3.81 to $3.93 EPS estimate provided in February, excluding $0.25 per share of charges related to the Connecticut settlement and transition costs associated with integrating the Columbia Gas of Massachusetts assets into the Eversource System. We also project long-term EPS growth of 5% to 7% through 2025, excluding the expected positive impact from our Offshore Wind projects. This growth is primarily driven by our $17 billion five-year capital program and sustained strong operational effectiveness. By September 30th, our capital expenditures totaled $2.3 billion. Next, I will discuss our recently approved Connecticut settlement, shown on Slide 6. As Joe mentioned earlier, the settlement includes $65 million in rate credits for CL&P customers over December 2021 and January 2022, averaging about $35 per customer during these months for typical residential customers. Additionally, there will be $10 million in shareholder-funded benefits for customers needing assistance with energy bills. The settlement will also end our appeal regarding the $28.4 million total storm-related credits that customers first saw in their bills in September 2021. These credits will continue until August next year. The proposed 90-basis-point reduction of CL&P’s distribution rates will not be implemented, and the current capital structure with a 9.25% ROE will remain in effect. CL&P cannot introduce new base distribution rates before January 1, 2024, and the next mandated review for electric and natural gas distribution rates will occur in late 2025. Since CL&P's last distribution rate case became effective in May 2018, actual ROEs have generally ranged between 8.6% and 9%, with the latest quarter at 8.6%. We have mechanisms to recover costs for certain new investments aimed at improving reliability and grid modernization. However, we will not obtain additional revenues to offset rising wages, employee benefits, property taxes, and other inflationary costs. Despite these challenges, we are committed to providing excellent service to our nearly 1.3 million CL&P customers while efficiently managing our operations. Now, moving on to our grid modernization, AMI, and electric vehicle initiatives in Connecticut and Massachusetts on Slide 7. On October 15th, CL&P submitted a final electric vehicle program design document for PURA review, which includes a proposed budget and implementation plan for residential managed charging, targeting a launch date of January 1, 2022, to help meet the state’s goal of having at least 125,000 electric vehicles on the road by the end of 2025. Regarding AMI in Connecticut, CL&P is preparing to file an updated proposal to have all customers on AMI by the end of 2025, which will require replacing over 800,000 meters over the coming years, involving an estimated capital investment of nearly $500 million. In Massachusetts, as noted during our July earnings call, we submitted a nearly $200 million grid modernization plan to regulators for the period from 2022 through 2025, with the majority being capital investment. We expect a ruling by the second quarter of 2022. Our Massachusetts AMI program is under review by the Massachusetts Department of Public Utilities, with a decision anticipated in 2022, proposing about $575 million in capital investments over multiple years. Similarly, in Massachusetts, the DPU is evaluating an extension of our electric vehicle program, involving about $200 million in investments over the next four years, with approximately $68 million classified as capital investments. We expect a decision on this by mid-2022. Now, addressing queries about the impact of rising natural gas prices on this winter's electric and natural gas supplies and prices, I will first discuss supplies. Our three natural gas distribution companies must ensure adequate natural gas access to serve firm customers during the coldest days recorded over the last 30 years. We achieve this through firm capacity contracts across multiple interstate pipelines and storage, both within and outside our service area. Our regulators in Connecticut and Massachusetts have been proactive in permitting us to maintain significant LNG storage capacity, providing us with roughly 6.5 billion cubic feet connected to our distribution system. We've also acquired additional firm delivery capacity in recent years, reinforcing our reliability for winter supplies. Regarding pricing, our natural gas sources consist of both stored gas at fixed prices and pipeline gas from the Marcellus Shale basin, priced based on NYMEX indices. Due to our firm pipeline capacity, we can access Marcellus-related pricing rather than the higher New England city gate price. However, even Marcellus prices are elevated this year, and we expect the commodity portion of natural gas bills to increase about 20% compared to last winter's low prices. Including distribution charges, we anticipate an average increase of about 15% in natural gas heating bills, equating to an approximate $30 monthly rise for typical heating customers across our distribution companies. While this increase is notable, it's still lower than the more than 30% hike facing propane customers and close to 60% for home heating oil. Usage is a significant factor, and though we've had mild weather so far this fall, colder months could push up costs further. We're proactively discussing with our regulators options to spread the recovery of certain charges to mitigate bill impacts. Additionally, we're enhancing communication to ensure customers understand the broader factors affecting their bills and encouraging them to utilize our energy efficiency programs and payment options effectively. On the electric side, the situation differs. Natural gas power plants dominate the New England market year-round, except during the coldest days. Rising natural gas prices are significantly influencing power prices. About 60% to 65% of our electric load is purchased directly from third-party suppliers, while 35% to 40% remains through our franchises. For those customers, although they will encounter higher prices, their contracts for power purchase in various tranches throughout the year provide some protection. However, due to winter natural gas constraints, we expect an increase in retail electric prices of about $0.02 to $0.03 per kilowatt hour in January, resulting in an additional $20 to $25 monthly increase for typical residential customers compared to last winter. Rates for our New Hampshire customers will remain unchanged until February, so they will not face any immediate impact. While most residential customers do not rely on electricity for heating, we understand that any rise in energy bills can strain household budgets. We've intensified efforts to promote the availability of over $500 million a year for energy efficiency initiatives across our states. It’s worth noting that wholesale electric prices were exceptionally low in 2020, making the percentage increases this year more pronounced, as they are compared to historically low baselines. Lastly, increases or decreases in the energy component of our electric bills are simply passed through dollar-for-dollar, as our role is solely to provide this procurement service to our customers. Thank you for joining us this morning. I will now turn the call back over to Jeff for questions.

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

Thank you. We will now begin the Q&A session. If you would like to ask a question, please follow the provided instructions.

Thank you, Cheryl. Our first question this morning is from Jeremy Tonet from JPMorgan. Good morning, Jeremy.

Good morning. Thanks for the update; it covered a lot of ground. I'd like to delve a bit deeper into Connecticut. Could you provide more insight into how you plan to manage the rate freeze in Connecticut and your outlook on earned ROE going forward? Additionally, when do you anticipate filing the next case there?

Well Jeremy, thank you for the question. As I mentioned, Connecticut Light and Power and Star Electric, Public Service in New Hampshire, the Eversource family has a strong track record of 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 8.661% or 8.66%. So even though we're allowed 9.25% ROE, we've been sort of 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 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 four-year sort of legislative requirement, we wouldn't mandate it to be in there until 2025. 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.

Thank you for that. Now, focusing on offshore, since we have schedules set for all three projects, when would it be suitable to provide more detailed disclosures regarding the project economics? Additionally, how do you view the ROFO guidance in relation to long-term EPS growth, considering that Offshore Wind is going to impact our earnings and fund rates moving forward?

That's a great question, and we've been considering it. We generally update our long-range plans in February alongside our year-end results, and we will discuss our forecast during that time. We intend to do this again this year, rolling forward our forecast as we've done previously by dropping a year and adding a year out to 2026. As you mentioned, due to the schedule of the projects, we expect significant contributions from larger projects during that time frame. Therefore, as we present the next forecast in February, we anticipate providing more clarity, transparency, and information about that segment, allowing for better modeling. We are getting close to that, and we expect to present the information in a more definitive manner in our February update.

Got it, that's helpful just real ask 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 because they prioritize the lowest price over economic development opportunities unlike some other states, but that is changing. The Governor is very interested in economic development and opportunities in this sector. States like New York are committed to moving forward; I was recently in upstate New York for a significant announcement regarding foundations, which is a positive step towards bringing some of the supply chain back to America. This is a major advancement for offshore wind opportunities, especially as we look at RFPs. In 2022, we are exploring potential projects in New York, Connecticut, Rhode Island, and Massachusetts. There are opportunities everywhere, and the first we will likely see is NIOC. They are very ambitious with their targets, and that's where we expect to see another significant RFP.

Thanks, Jeremy. Next question is from Steve Fleishman from Wolfe. Good morning, Steve.

Hey. Good morning. 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 that right now?

Yes, Steve. This is Phil. Good morning. We talked about this certainly about a topic that people have been interested in, as well as the project and the Company. We feel we're in a very good position in terms of our contracting for both substations or turbines or foundations, what we have in place for strategy for vessels, etc. 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. As I've talked about before, there are puts and takes for all these projects, so some costs may move in one direction and other things are moving in a different direction. 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 ROE. There are a number of factors that come at you every day, 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 situation. And then I think they've had some issues with the New York ISO interconnect agreement, so it sounds like you're not seeing that kind of delay.

No, Steve, this is Joe. They did announce that delay, but we do not expect any similar delays on our projects. We have good visibility on that and feel very confident.

Great. And then maybe just high level. The Biden infrastructure plan; 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 are most focused on?

We would like to take advantage of tax credits to assist our customers and enhance our projects. Our main focus will be on that aspect of the Biden plan.

Alright. Thanks, Steve. Appreciate it. The next question is from Julien for Bank of America. Good morning, Julien.

Hey, good morning to you, thanks for the time. Appreciate the insights. Let me start with a higher level of 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? And 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?

Good morning, Julien. So the same might apply to the gas and Access Northeast while we're at it as well. Yes. Good morning, 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 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 here, RFP out here 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. Fair enough. It sounds like Access Northeast not necessarily in the same vein on table, but if I can pivot a little bit more locally, right? Talking about 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 seemed 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 the fourth-quarter here. But any initial thoughts there around distributed assets and enabling them?

Our interests in the smart grid, interconnections, and advanced metering infrastructure align with our key regulators and policymakers, especially in Connecticut and Massachusetts. We previously discussed our recent settlement in Connecticut, which opens up opportunities for us to explore advanced metering infrastructure and the smart grid, enhancing access to renewables and distributed generation for those looking to connect. Expect to see increased activity in 2022. I'll now pass it over to Phil to discuss the financial aspects.

Julien, as you suggest, we do update in February, as we've discussed. And I think the area that we're looking at, we refreshed 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 are maybe in three different categories. One being just these end-of-life asset replacement projects. What do we have out there? What do we have in expectation-wise? Certainly electrification is a category. The States have targets we have to meet. 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 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 and New York, and making sure that we have the connectivity or interconnections and the transmission to not be a bottleneck for that. That is likely to be some increased investment needed on the system. I'd say those are the types of things that I think you'll see when we rollout our update in February in those categories.

Got it. Alright. We shall wait for what those numbers amount to. But I wish you the best of luck guys.

Thanks, Julien.

Thank you.

Next question is from David Arcaro from Morgan Stanley. Good morning, David.

Hey, good morning. Thanks for taking my question. 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, this $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. So 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 about $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 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 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.

Thank you. I'll address that. The vessel's first port of call will be New London. We have the chance to utilize it for both Sunrise and Revolution Wind. However, it won't be ready for Southwark. There is enough of a buffer to ensure we can complete those projects. Additionally, if there is any delay with the vessel arriving in New London, our first customer would experience a corresponding delay on the other end. We do not foresee any issues with employing that advanced vessel. It's remarkable, equipped to carry six wind turbine assemblies. New London is just 70 miles from our lease area, making it the most efficient method for installing our wind turbines. We are very enthusiastic about this. I've also had the chance to connect with the Dominion team, and the vessel is on schedule. Some of our team will visit to monitor the progress, and it will be quite an impressive piece of equipment.

Okay, great. Thanks so much.

Alright, thanks, David. Our next question is from Sophie Karp from KeyBanc. Morning Sophie.

Good morning. And thank you for taking my questions. Going back to Connecticut, I'm just kind of curious. I appreciate the overall capex forecast is unchanged, but kind of shift in the timing of some projects, maybe between phase one of the levers you can pull here to manage, or in that arena the next few years there or what are some of the levers you can pull to offset inflationary pressures and just overall normal course of investments there?

Sophie, as I've mentioned before, our investments and operations are focused on meeting our customers' expectations. The investments we make in our system are based on customer needs. We aim to reinforce the system and provide value. We might make a capital investment that helps offset some operational costs, which benefits customers. Our investment focus, whether in transmission, distribution, gas, electric, or water, prioritizes what it does for customers. We won't be reallocating investments for reasons unrelated to meeting their needs. There are various strategies we can employ. I believe our record in managing operations efficiently and effectively stands strong within the industry. Integrating EGMA into our operations will provide additional benefits and create opportunities as we implement programs effectively. Therefore, we are committed to managing our operations to address customer needs, which will be the key to achieving our desired earnings profile.

Got it. What are you currently observing, aside from energy costs? Specifically, I'm interested in the overall situation regarding materials, labor, and the impact of inflationary pressures within your regulated franchises. Is this becoming significant enough to require certain measures to counteract, or are you noticing a fairly positive trend? How should we perceive this at the moment?

I would say it has had an impact, but it's not been significant. Over a year ago, the supply chain team, which is part of the financial organization, began working closely with our engineers and operations team. At the beginning of this pandemic, many companies favored a just-in-time delivery model. However, we made a deliberate choice over a year ago to avoid that approach and to build up our inventories of poles, transformers, wire, cable, and other items. If we don't have something in our facility, we have arrangements with our suppliers to keep it on their property. We're utilizing a lot of it. As Joe mentioned regarding the storm, we go through a significant amount of poles and wire during such events, but that has not been an issue for us as we have had the supplies available. That said, we are monitoring the situation closely; there are certain types of equipment becoming harder to obtain, not necessarily the entire item but perhaps just a specific component that is unavailable. Therefore, we have also broadened our supplier base and varied the locations of those suppliers. While there have been some delays in certain products, they have not had a materially significant impact on us.

Thank you. If I could ask one more question about the gas supply situation, could you provide details on what percentage of your normal demand is currently hedged between physical storage and capacity contracts? Also, have you considered proposing to regulators the construction of additional storage facilities given the current circumstances?

I'd say about one-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 the city gate pricing. 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 are 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. It matters in terms of storm response, but it matters in this case too because we can operate the synergies by moving those two companies together, between NSTAR Gas in Massachusetts and Eversource Gas of Massachusetts. 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. 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.

Thank you. Next question is from Travis Miller from Morningstar. Good morning, Travis.

Good morning, everyone, and thank you. On the offshore transmission, it sounds like you have a lot of the pieces in place for the Southwark project if I heard you correctly. What's the status of the transmission side of the other projects that you have going?

I'm not sure we understand the question, Travis. Are you asking about the status of the transmission side?

Transmission refers to the connections between offshore projects and the land.

Thanks, Travis. All of those projects, including the permitting, siting, and applications, are progressing smoothly. We have not encountered any issues, and everything is on track. Each project is clearly defined and moving forward.

Okay, great. That's all I had. Thanks so much.

Thanks, David. 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 email. Thank you.

Thank you, ladies and gentlemen, this concludes today's conference. Thank you for your participation. You may now.