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Text: I'm Jeff Kotkin, Eversource Energy's Vice President for Investor Relations.
These factors are set forth in the news release issued yesterday.
Additionally, our explanation of how and why we use certain non-GAAP measures and how those measures reconciled to GAAP results is contained within our news release and the slides we posted last night and in our most recent 10-K and 10-Q.
Speaking today will be Joe Nolan, our President and Chief Executive Officer; and Phil Lembo, our Executive Vice President and Chief Financial Officer.
Also joining us today are John Moreira, our Treasurer and Senior Vice President for Finance and Regulatory; and Jay Buth, our Vice President and Controller.
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.
First, I want to discuss last week's 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 the Southeastern Massachusetts, Cape Cod in Martha's Vineyard, areas that took the brunt of the storm.
Our internal resources were supplemented by hundreds of crews from outside the region, and we were able to essentially complete the work over this past weekend.
This experience underscores the benefits of a large T&D organization, one where resources can be shifted based on the greatest need.
Last year, it was Connecticut.
Last week, it was Massachusetts.
Next time it might be in New Hampshire.
We have 9,300 dedicated employees, all focused on providing the best possible experience for our customers.
Lessons we learned last year in Connecticut, particularly regarding communication with municipalities have been vigorously applied this year.
Our customers and community leaders have certainly noticed our enhancements, and we have received many positive comments on our storm response.
When storms have threatened us and recall that we have had glancing blows from three tropical storms this summer in 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 lost of our customers has power restored.
I believe that'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 work in a remote pandemic restricted environment for the last 18 months.
Next, I want to discuss our Connecticut rate settlement.
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.
Phil will discuss settlement specifics in a moment, but we are very grateful to PURA for the opportunity to move forward on a positive note.
Settling critical regulatory and legal disputes was a necessity to reset our relationship with key Connecticut stakeholders.
We all want the state to move ahead on addressing critical energy and climate issues.
And the outstanding disputes have the potential to delay some of this important work.
Since becoming CEO this past spring, my top priority has been to strengthen our relationship Ins' Connecticut.
I've met regularly with key state policymakers as well as business leaders and customers, underscoring our commitment to the state with 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 temporary rate docket now behind us, we can move on to other important topics, where progress has been hindered by the drain in time and resources devoted to strong ESA ES and the interim rate reduction, supporting the build-out of electric vehicle infrastructure, incenting the construction of customer-owned energy storage, installing AMI.
That is the clean energy future, and we will work together with our customers in policymakers to get there.
I'm 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 three.
Each has advanced since our last earnings call.
To start, our smaller projects, South Fork, has received its final environmental impact statement, and we expect a record of decision to be posted later this month.
BOEM's project website anticipates a decision on South Fork's construction and operating permit or COP 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, and that we expect it to be installed in the summer of 2023.
Moving to the 704-megawatt Revolution Wind project that will deliver clean power to Connecticut and Rhode Island.
BOEM continues to anticipate a COP decision in July of 2023, which would support a 2025 in-service date.
State siting hearings have commenced.
Finally, our largest project, Sunrise Wind, which will supply 924 megawatts to New York.
We are looking for federal agencies to complete their final reviews in late 2023, a schedule that would support a late 2025 in-service date.
Last week, we announced that Sunrise will be the first offshore wind project in the United States that will utilize high-voltage direct current technology.
HVDC offers advantages over AC technology when used over long distances.
In Sunrise, we'll have an approximately 100-mile submarine transmission cable from 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 to ocean tracks 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 under contract.
We continue to exercise strong fiscal discipline in using the remaining offshore acreage that we have leased from the federal government.
We did not bid into Massachusetts September RFP for up to 1,600 megawatts of offshore wind.
Current Massachusetts bidding rules discourage imaginative bid packages, Governor Baker and some Massachusetts policymakers are now recognizing that Massachusetts is not benefiting from the same level of economic development as states that place greater emphasis on infrastructure and supply chain development.
As such, the governor recently filed legislation that would eliminate the state's current price cap.
In Rhode Island, we are constructing a service vessel in the state.
In Connecticut, we are partnering with the state on 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 Hochul's administration last month and announcing the largest single offshore wind supply chain contract award in New York to support the Sunrise project.
The local company, Riggs Distler, will construct advanced foundation components at the port on the Hudson near Albany.
It is just the latest commitment we have made to New York, which also includes basing an offshore wind maintenance hub in Port Jefferson.
We have an excellent relationship with New York policymakers, and that is where most of our currently contracted offshore wind capacity is headed.
We look forward to bidding into future RFPs, with our strong mix of sites, skill sets, discipline bidding strategies and offsets vast offshore wind experience will make us a formidable contender in any competition that takes a broad look at the benefits of shore winds.
I'll start with our results for the quarter slide four.
Our GAAP earnings were $0.82 per share for the quarter, including the $0.19 charge associated with the Connecticut electric rate settlement and the $0.01 charge relating to our integration of Eversource gas of Massachusetts.
Overall, we experienced improved operating results at the electric transmission and distribution segments and lower results at the natural gas and water segments as well as the parents and other.
Our electric transmission business earned $0.40 per share in the third quarter of 2021 compared with earnings of $0.36 in the third quarter of last year, reflecting a higher level of necessary investment in our transmission facilities.
Our electric distribution business, excluding charges related to the Connecticut rate settlement, earned $0.62 per share in the third quarter of 2021 compared with earnings of $0.60 in the third quarter of 2020.
Higher distribution revenues were partially offset by higher O&M, depreciation, interest and property taxes.
Storm-related expenses remain a headwind for us, costing us $0.01 a share in the third quarter of 2021 compared to the same period in 2020 and a total of $0.05 a share more in 2021 than last year on a year-to-date basis.
Our natural gas distribution business lost $0.06 per share in the third quarter of 2021 compared with a loss of $0.04 in the third quarter of 2020.
Given the seasonal nature of customer usage, natural gas utilities tend to record losses over the summer months, our natural gas segment now -- our natural gas segment loss is now about 50% larger as a result of the acquisition of Columbia Gas of Massachusetts assets back in last October.
And as you recall, we now refer to that franchises as Eversource Gas of Massachusetts.
So Eversource Gas of Massachusetts lost about $0.03 per share in the quarter.
It had no comparable amount in the third quarter of 2020.
I think it's important to point out here that given this is the first full year for our Eversource Gas of Massachusetts or EGMA franchise, modeling its quarterly earnings contribution has varied widely across street estimates, at least the ones that I've seen.
Just to some investors underestimated the $0.14 per share positive contribution from EGMA in the first quarter.
I believe there may have been some underestimate of EGMA losses in the third quarter.
As I said, EGMA lost $0.03 in the quarter, and it was not part of the Eversource family in the third quarter of 2020.
I'd say going forward with a year's track record behind us, I'm sure that the estimates will better reflect the earnings pattern we have for that franchise going forward.
Our water distribution business, Aquarion, earned $0.05 per share in the third quarter of 2021 compared with earnings of $0.07 in the third quarter of 2020.
The lower results were due primarily to the absence of the Hingham, Massachusetts water system that we sold at the end of July of 2020.
The $17.5 million that we earned at our water segment in the third quarter of 2021 is more on -- a more normalized level for that segment.
Our parent and other earned $0.01 per share in the third quarter of 2021 compared with earnings of $0.03 in the third quarter of 2020.
Lower earnings were primarily due to a higher effective tax rate.
Our consolidated rate was 24.8% in the third quarter of 2021 compared with 23.7% in the third quarter of 2020.
Turning to slide five.
You can see that we have reiterated the $3.81 to $3.93 earnings per share guidance that we issued in February.
That range excludes the $0.25 per share of charges related to our Connecticut settlement and storm-related bill credits that we recognized in the first quarter of this year as well as the transition costs related to the integration of the former Columbia Gas of Massachusetts assets into the Eversource system.
Also, we project long-term earnings per share growth in the upper half of the range of 5% to 7% through 2025.
Excluding the impact of the positive impact that we expect from our offshore wind projects.
That growth is largely driven by our $17 billion five-year capital program and continued strong operational effectiveness throughout the business.
For reference, our five-year capital forecast is shown in the appendix.
And through September 30, our capital expenditures totaled $2.3 billion.
From the financial results, I'll turn to our recently approved Connecticut settlement on slide number six.
Earlier, Joe provided you with an overview.
I'll just add a few additional details.
The settlement calls for $65 million in rate credits to CL&P customers over the course of December of 2021 in January of 2022.
And that's about -- in total, $35 per customer over the two months for the typical residential customer.
It provides another $10 million of shareholder pay benefits to customers who are most in need of help with their energy bills.
Further, as part of the settlement, we will withdraw our superior court appeal of the $28.4 million total storm-related credits that customers first saw in their bills in September of 2021.
So these customers will continue.
They'll continue to flow back to customers through August of next year.
As prior of the settlement, the 90 basis point indefinite reduction of CL&P's distribution ROE will not be implemented.
Additionally, the current 9.25% ROE and capital structure will remain in effect.
This will avoid an appeal of the interim rate reduction and will withdraw the pending appeal of the 90 basis point reduction.
CL&P cannot implement new base distribution rates before January one, 2024.
Priorities to the settlement agreed that this review satisfies the statutory requirement in Connecticut that all-electric and natural gas distribution company rates be reviewed once every four years.
That's to determine whether they're just unreasonable.
So as a result, the next statutory mandated review would be in late 2025.
Since CL&P's last distribution rate case was effective in May of 2018, the actual -- the company's actual ROEs have generally ranged between 8.6% and 9%, with the latest reported quarter at 8.6%.
There are some tracking mechanisms that will allow us to recover costs associated with certain new investments over the coming years, such as those to improve reliability or implement grid modernization initiatives, but we will not be able to obtain any additional revenues to offset higher wages, employee benefits costs, property taxes and other inflationary items.
We'll continue to provide superior service to our nearly 1.3 million CL&P customers will also be effectively managing our operations.
It will certainly be a challenge, but one, I know that our entire CL&P and Eversource team is up to meeting.
From the Connecticut settlement, I'll turn to our various grid mod, AMI, electric vehicle initiatives in Connecticut and Massachusetts.
On October 15, CL&P filed a final electric vehicle program designed documents for PURA review and approval, including a proposed budget and program implementation plan for residential managed charging.
PURA will conduct a review process with a final decision targeted for December the eight.
The program is planned to launch January one of 2022, and will support the state's target of having at least 125,000 electric vehicles on the road by the end of 2025.
In terms of AMI, in Connecticut, CL&P is preparing to file an updated proposal based on a straw proposal from Pier to have all our customers on AMI by the end of 2025.
To date, we'll need to replace more than 800,000 meters over the next -- to do that, we'll have to replace over 800,000 meters over the next several years.
Altogether, moving CL&P fully to AMI would involve a capital investment of nearly $500 million we estimate in meters and communication related technologies.
In Massachusetts on slide eight, as we mentioned on our July earnings call.
We've submitted nearly $200 million grid modernization plan to regulators for the 2022 through 2025 period.
The vast majority of that investment would be capital.
We expect a ruling on the entire program by the second quarter of 2022.
Our Massachusetts AMI program is now being evaluated by the Massachusetts Department of Public Utilities, with a decision expected in 2022.
It would involve about $575 million of capital investments over multi-years from 2022 through 2027.
And like Connecticut, would provide significant customer service, reliability, energy efficiency, grid modernization and demand management improvements.
Also in Massachusetts, the DPU is evaluating an extension of our electric vehicle program.
The extension would provide investments of nearly $200 million over the next four years, with about $68 million being capital investments.
We currently expect a decision on this by mid-2022.
Turning to slide nine.
We've been receiving regular questions over the past couple of months about the impact of higher natural gas prices on this winter's electric and natural gas supplies and prices.
So I'll first start with supplies.
First, what do we have to supply?
Our three natural gas distribution companies are required to have access to enough natural gas to be able to serve our firm customers on the coldest day in the last 30-year period.
So we accomplished that through a combination of firm capacity contracts across multiple interstate pipeline systems and through storage, both inside and outside of our service territory.
Our regulators in Connecticut and Massachusetts have had the foresight to allow us to maintain significant in region LNG storage in Waterbury, Connecticut.
And Hopkinton and Acushnet, Massachusetts as well as various facilities that we purchased as part of the Columbia gas of Massachusetts transaction.
Although, these facilities provide us with -- altogether, these facilities provide us with storage connected to our distribution system of nearly 6.5 billion cubic feet.
Our regulators have also permitted us to acquire additional firm delivery capacity that was added to the Algonquin system in recent years through the AIM and Atlantic Bridge expansion projects.
We've also acquired additional firm capacity on the Tennessee and Portland pipelines.
So from a reliability standpoint and supplies, we consider ourselves very well prepared for the winter.
In terms of price, our natural gas sources include a combination of stored gas, where the price has been fixed and pipeline gas from Marcellus Shale basin that is price based on NYMEX related indices.
Because our firm pipeline capacity, we are able to purchase at the Marcellus related price, not at the New England Citygate price.
You can see on the slide that we have in our deck, that there's significant difference in pricing between the two.
Nonetheless, even the Marcellus price is higher this year.
And as of now, we expect the commodity portion of natural gas bills to be approximately 20% higher than last winter's extremely low levels due to COVID, prices were pretty low last year and well below levels we experienced a decade ago after Hurricane Katrina struck the Gulf of Mexico and Louisiana.
Overall, including the distribution charge, we expect natural gas heating bills will be up about 15% on average.
That's about $30 a month to the average for a typical heating customer compared to last winter.
And that's an average across our three natural gas distribution companies.
While a 15% increase is significant it is far less than the -- more than 30% increase that propane heating customers are facing and really a 60% increase that's out there for home heating oil as the alternatives for customers.
Of course, a primary determinant of the total bill is usage, right?
The autumn has been quite mild here in New England, thus far, and natural gas usage has been particularly low.
Nonetheless, a bitly cold month of December or January could cause natural gas cost to increase.
Recognizing the stress that this situation could place on customers.
We've suggested to our regulators that we spread out the recovery of certain charges in our distribution portion of our bill to moderate the potential bill impacts where possible.
We're also taking additional proactive steps and working closely with regulators so that customers understand the current price environment and take actions to address it.
We're intensifying our communications to be sure customers understand the bigger picture macro factors affecting natural gas bills.
And we are urging customers to take advantage of our nationally recognized energy efficiency programs and leverage payment options that we have available.
So on the electric side, it's a bit different.
Natural gas power plants are on the margin in New England year-round, really, except for the coldest days of the year.
So rising natural gas prices are significantly affecting power prices.
Between 60% and 65% of our electric load is bought by customers directly from third-party suppliers.
For the 35% to 40% of our load that continues to buy through our franchises, Connecticut Light & Power, NSTAR Electric and Public Service in New Hampshire, this is mostly residential load and customers will see higher prices, but they are partially protected by the fact that we contract for power in multiple tranches throughout the year.
So lower cost tranches from our purchases earlier in 2022 will offset some of the higher priced tranches that we purchased more recently.
Due to wintertime natural gas constraints in New England, our customers normally see $0.015 to $0.02 per kilowatt hour increase in their retail electric prices in January, an increase that usually reverses as we move into the summer.
This January customers in Massachusetts and Connecticut elected to experience an additional $0.02 to $0.03 increase due to higher gas prices driving power production.
This would be an additional $20, $25 per month for a typical residential customer compared with last winter.
Our New Hampshire customers, the rates remain in effect until February, so there's really no impact at this stage for our New Hampshire customers.
While the vast majority of our residential customers do not use electricity for space heating, we recognize that any increase in energy bills add stress to the household budget.
And we've redoubled our efforts again to urge customers to take advantage of the more than $500 million that we have available on energy efficiency initiatives that we provide customers throughout our states each year.
I should note that similar to natural gas prices, wholesale electric prices were extremely low in 2020.
In fact, they were at a 10-year low.
So the percentage increase is -- that we're reporting here comes off some very low base numbers from last year.
As a reminder, increases and/or decreases in the energy component of our electric bills, our pass-throughs dollar-for-dollar pass-throughs, we earn nothing on providing the procurement service for customers.

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compname reports q3 earnings per share $0.82.
q3 earnings per share $0.82.
today reaffirmed its previously disclosed 2021 earnings per share (eps) projection of $3.81 to $3.93 per share.

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