Philip J. Lembo
Executive Vice President and Chief Financial Officer at Eversource Energy
Thank you, Joe. This morning I'll cover a few topics on third quatre results details about the Connecticut sell in, an update on grid monetization, electric vehicle initiatives and to look at natural gas outlook for the coming winter. 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 EPS guidance that we issued in February. That range excludes the $0.25 per share of charges related to our Connecticut settlement and storm-related bill credits that we recognized in the first quarter of this year as well as the transition costs related to the integration of the former Columbia Gas of Massachusetts assets into the Eversource system. Also, we project long-term EPS growth in the upper half of the range of 5% to 7% through 2025. Excluding the 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. So first, I'll turn to slide seven and cover the Connecticut programs. 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 off of 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 been proactive. 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. So thank you very much for joining us this morning.
I'll turn the call back over to Jeff for Q&A.
