Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

EVERSOURCE ENERGY AND SUBSIDIARIES

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this combined Annual Report on Form 10-K. References in this combined Annual Report on Form 10-K to "Eversource," the "Company," "we," "us," and "our" refer to Eversource Energy and its consolidated subsidiaries. All per-share amounts are reported on a diluted basis. The consolidated financial statements of Eversource, NSTAR Electric and PSNH and the financial statements of CL&P are herein collectively referred to as the "financial statements." Our discussion of fiscal year 2020 compared to fiscal year 2019 is included herein. Unless expressly stated otherwise, for discussion and analysis of fiscal year 2018 items and fiscal year 2019 compared to fiscal year 2018, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in our combined 2019 Annual Report on Form 10-K, which is incorporated herein by reference.

Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.

The only common equity securities that are publicly traded are common shares of Eversource. The earnings and EPS of each business discussed below do not represent a direct legal interest in the assets and liabilities of such business but rather represent a direct interest in our assets and liabilities as a whole. EPS by business is a financial measure not recognized under GAAP, calculated by dividing the Net Income Attributable to Common Shareholders of each business by the weighted average diluted Eversource common shares outstanding for the period. Our earnings discussion also includes non-GAAP financial measures referencing our 2020 earnings and EPS excluding certain acquisition costs related to our purchase of the assets of Columbia Gas of Massachusetts and our 2019 earnings and EPS excluding the impairment charge for the NPT project.

We use these non-GAAP financial measures to evaluate and provide details of earnings results by business and to more fully compare and explain our 2020 and 2019 results without including these items. We believe the acquisition costs and the NPT impairment charge are not indicative of our ongoing costs and performance. Due to the nature and significance of these items on Net Income Attributable to Common Shareholders, we believe that the non-GAAP presentation is a more meaningful representation of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance of our business. These non-GAAP financial measures should not be considered as alternatives to reported Net Income Attributable to Common Shareholders or EPS determined in accordance with GAAP as indicators of operating performance.

Financial Condition and Business Analysis

Executive Summary

The following items in this executive summary are explained in more detail in this combined Annual Report on Form 10-K:

Earnings Overview and Future Outlook:

We earned $1.21 billion, or $3.55 per share, in 2020, compared with $909.1 million, or $2.81 per share, in 2019. Our 2020 results include after-tax acquisition costs related to our purchase of the assets of Columbia Gas of Massachusetts (CMA) of $32.1 million, or $0.09 per share. Excluding those acquisition costs, we earned $1.24 billion, or $3.64 per share, in 2020. Our 2019 results include an after-tax impairment charge of $204.4 million, or $0.64 per share, related to our former investment in the NPT project. Excluding the NPT impairment charge, we earned $1.11 billion, or $3.45 per share, in 2019.
Our electric distribution segment earned $544.0 million, or $1.60 per share, in 2020, compared with $513.3 million, or $1.59 per share, in 2019. Our natural gas distribution segment earned $134.1 million, or $0.40 per share, in 2020, compared with $96.2 million, or $0.30 per share, in 2019. Our water distribution segment earned $41.2 million, or $0.12 per share, in 2020, compared with $34.9 million, or $0.11 per share, in 2019.
Our electric transmission segment earned $502.5 million, or $1.48 per share, in 2020, compared with $256.5 million, or $0.79 per share, in 2019. Excluding the after-tax NPT impairment charge of $204.4 million, or $0.64 per share, our electric transmission segment earned $460.9 million, or $1.43 per share, in 2019.
Eversource parent and other companies had a net loss of $16.6 million, or $0.05 per share, in 2020, compared with earnings of $8.2 million, or $0.02 per share, in 2019. Excluding acquisition costs, Eversource parent and other companies earned $14.0 million, or $0.04 per share, in 2020.
We currently project 2021 non-GAAP earning guidance of between $3.81 per share and $3.93 per share, which excludes the impact of integration costs related to our purchase of the natural gas distribution assets of CMA. We also project that our long-term EPS growth rate through 2025 from our regulated utility businesses will be in the upper half of the 5 to 7 percent range.
The outbreak of COVID-19 has not resulted in significant operational or earnings impacts. We believe that we have in place, or are developing, successful mechanisms with our state regulatory commissions that allow, or will allow, us to recover our incremental costs associated with COVID-19, which include uncollectible customer receivable expenses. We are continuing to closely monitor the COVID-19 pandemic, and we continue to operate under our pandemic response plan.

Liquidity:

Cash flows provided by operating activities totaled $1.68 billion in 2020, compared with $2.01 billion in 2019. Investments in property, plant and equipment totaled $2.94 billion in 2020 and $2.91 billion in 2019. Cash totaled $106.6 million as of December 31, 2020, compared with $15.4 million as of December 31, 2019. Our available borrowing capacity under our commercial paper programs totaled $1.40 billion as of December 31, 2020.
In 2020, we issued 11,960,000 common shares, which resulted in proceeds of $929.0 million, net of issuance costs.
In 2020, we issued $2.76 billion of new long-term debt, consisting of $1.55 billion by Eversource parent, $400 million by CL&P, $400 million by NSTAR Electric, $150 million by PSNH, $190 million by NSTAR Gas, and $70 million by Yankee Gas. Proceeds from these new issuances were used primarily to fund a portion of the purchase price for the CMA asset acquisition and to pay short-term borrowings at Eversource parent, refinance investments in eligible green expenditures at NSTAR Electric, and to refinance existing indebtedness, fund capital expenditures and for general corporate purposes at CL&P, PSNH, NSTAR Gas and Yankee Gas.
In 2020, we issued dividends totaling $2.27 per common share, compared with dividends of $2.14 per common share in 2019. On February 9, 2021, our Board of Trustees approved a common share dividend payment of $0.6025 per share, payable on March 31, 2021 to shareholders of record as of March 4, 2021. The 2021 dividend represents an increase of 6.2 percent over the dividend paid in December 2020.
We project to make capital expenditures of $17.03 billion from 2021 through 2025, of which we expect $10.90 billion to be in our electric and natural gas distribution segments, $4.31 billion to be in our electric transmission segment and $0.78 billion to be in our water distribution segment. We also project to invest $1.05 billion in information technology and facilities upgrades and enhancements. These projections do not include any expected investments related to offshore wind projects.

Strategic and Regulatory Items:

On October 9, 2020, Eversource completed the acquisition of certain assets and liabilities that comprised NiSource’s natural gas distribution business in Massachusetts, CMA, for a cash purchase price of $1.1 billion, plus a target working capital amount of $69.6 million, which is subject to adjustment to reflect actual working capital as of the closing date. On October 7, 2020, the DPU approved the rate plan related to the acquisition. The approved rate stabilization plan includes base distribution rate increases of $13 million on November 1, 2021 and $10 million on November 1, 2022. The settlement agreement includes two rate base resets during an eight-year rate plan, occurring on November 1, 2024 and November 1, 2027.
On December 15, 2020, the NHPUC approved an October 9, 2020 settlement agreement that included a permanent rate increase of $45.0 million effective January 1, 2021 at PSNH. PSNH was also permitted three step increases, effective January 1, 2021, August 1, 2021, and August 1, 2022, to reflect plant additions in calendar years 2019, 2020 and 2021, respectively. The settlement agreement allowed for the effect of the permanent rate increase to be extended back to the temporary rate period. In lieu of a customer rate increase for this recoupment of revenue, the NHPUC directed a portion of the total EDIT regulatory liability to offset bill impacts to customers.
On October 30, 2020, the DPU approved an NSTAR Gas base distribution rate increase of $23.0 million effective November 1, 2020. NSTAR Gas' 2019 plant additions are allowed recovery beginning on November 1, 2021.
In January 2021, BOEM released its Draft Environmental Impact Statement (EIS) for the South Fork Wind project, which assessed the environmental, social, and economic impacts of constructing the project.

Impact of COVID-19

COVID-19 has adversely affected workers and the economy and caused volatility in the financial markets. Due to the inherent uncertainty of the unprecedented and evolving situation, we continue to closely monitor how COVID-19 related developments affect Eversource. Based on available information, we have not experienced significant impacts directly related to the pandemic that have adversely affected our current operations or results of operations. The extent of the impact to us in the future will vary and depend in large part on the duration, scope and severity of the pandemic and the timing and extent of COVID-19 relief legislation, and the resulting impact on economic, health care and capital market conditions. The future impact will also depend on the outcome of planned proceedings before our state regulatory commissions to recover our incremental costs associated with COVID-19, which include uncollectible customer receivable expenses.

Operational: We provide a critical service to our customers and have taken extensive measures to maintain its safety and reliability. We have implemented our company-wide pandemic plan, which guides our emergency response, business continuity, and the precautionary measures we are taking to ensure the safety, health, and well-being of our employees, our customers, and our communities. We continue to adjust our company-wide pandemic plan to address various scenarios, including reduced workforce levels and limited mutual aid in the event of a significant storm event, and have implemented protective measures to mitigate the impact of COVID-19 on our workforce. We have implemented work from home policies where appropriate, resulting in nearly half of our employees working remotely. For our employees performing essential functions that are required onsite, such as field crews and system operations, we have taken significant safety measures, including establishing social distancing measures, the use of personal protective equipment, increasing facility sanitization efforts, and enabling critical operations to be shifted to different control center locations if necessary. At this time, our workforce staffing levels continue to enable us to safely and reliably deliver our critical services to customers.

We continue to prepare for the re-entry of our employees working remotely. Our re-entry plan includes a multi-phase approach that is measured and gradual. The plan is informed by public health guidance with the safety of our employees and customers as our highest priority. We are in the early phase of our re-entry plan and have returned fewer than 100 remote employees to the workplace. We have had increased short duration return to work for critical business needs, such as storm response and essential training. State and federal guidelines, external conditions, and critical business priorities continue to inform the pace of our re-entry plan. Significant health and safety measures and pandemic protocols will remain in place, including social distancing requirements, the use of personal protective equipment, sanitization efforts and employee training, for all employees currently working onsite and specific plans have been developed for our eventual re-entry to the workplace.

In mid-March, we suspended non-critical work inside customer premises, which included energy audits inside our customers’ homes and businesses. These activities resumed in early July with the implementation of new health and safety guidelines for the restart of energy efficiency services to customers. This delay did not have a significant impact on our 2020 spending levels or incentives earned. As of the date of our filing, we do not expect a significant impact on our 2021 energy efficiency program spending and efforts, which assumes the continuation of energy efficiency programs throughout 2021. Actual energy efficiency spending levels will depend on the extent and duration of the pandemic.

Among the states we serve, COVID-19 had initially spread in a rapid manner in Connecticut and Massachusetts during the outbreak that began in mid-March. During the summer, these states had seen a decrease in the infection rate and daily confirmed cases, as well as more capacity in hospitals, and improved testing availability and contact tracing, as compared to the initial outbreak. Beginning in October, the spread of COVID-19 began to increase at a significant pace, surpassing infection levels from the initial outbreak, peaking in December 2020 and January 2021 in each of the states we serve. Since those peak levels, there has been a downward trend in the daily confirmed cases, infection rates and positive test rates.

Financial: Overall, our future financial position, results of operations, and cash flows could be negatively impacted by COVID-19 as it relates to the collectability of customer receivables and customer payment plans, elimination of late payment revenues, lower sales volumes primarily from PSNH's commercial and industrial customers, energy efficiency spending levels and incentives earned, and increased expenses for cleaning and supplies for personal protective equipment. Other potential negative financial impacts relate to market volatility on our equity and debt securities, access to, as well as cost of, capital resources, and the ability of various third-party vendors and suppliers to fulfill their obligations.

As of December 31, 2020, our allowance for uncollectible customer receivable balance of $358.9 million, of which $194.8 million relates to hardship accounts that are specifically recovered in rates charged to customers, adequately reflected the collection risk and net realizable value for our receivables. We continue to evaluate the adequacy of the uncollectible allowance based on an ongoing assessment of accounts receivable collections and customer payment trends, economic conditions, delinquency statistics, aging-based quantitative assessments, the impact on residential customer bills because of energy usage and change in rates, flexible payment plans and financial hardship arrearage management programs being offered to customers, and COVID-19 developments, including any potential federal governmental pandemic relief programs and the expansion of unemployment benefit initiatives, which help to mitigate the potential for increasing customer account delinquencies. Additionally, management considered past economic declines and corresponding uncollectible reserves as part of the current assessment. This evaluation has shown that our operating companies have experienced an increase in aged receivables and some lower cash collections from customers because of the moratorium on disconnections and the economic slowdown resulting from the COVID-19 pandemic.

Based upon the evaluation performed, in 2020, we increased the allowance for uncollectible accounts for amounts incurred as a result of COVID-19 by $31.5 million for Eversource ($2.8 million for CL&P, $11.0 million for NSTAR Electric, $2.3 million for PSNH and $15.4 million at our natural gas businesses). These COVID-19 related uncollectible amounts were deferred either as incremental regulatory costs or deferred through existing regulatory tracking mechanisms that recover uncollectible energy supply costs, as we believe it is probable that these costs will ultimately be recovered from customers in rates. We believe that we have in place, or are developing, successful mechanisms with our state regulatory commissions that allow, or will allow, us to recover our incremental costs associated with COVID-19, which include uncollectible customer receivable expenses, while balancing the impact on our customers’ bills and our operating cash flows.

In March 2020, Connecticut, Massachusetts and New Hampshire each established moratoria on disconnections of residential and commercial customers for non-payment for utility service. In all three states, a moratorium for lower income hardship residential customers will remain in place through the normal state regulated winter moratorium that ends in the spring of 2021. In Connecticut and New Hampshire, the moratorium for all remaining customers has expired. In Massachusetts, the moratorium on commercial utility disconnections ended on September 1, 2020 and the moratorium on residential non-hardship disconnections was extended to April 1, 2021.

We continue to work closely with our state regulatory commissions and consumer advocates on customer assistance measures, including payment plan options in order to mitigate the impact on customer rates in the future, as well as financial hardship and arrearage management programs for those customers who are unable to pay their utility bills. We developed these long-term solutions for customers in order to help minimize the extent of the impact of COVID-19 on customer receivable balances and customers’ affordability in light of the current financial impact they may experience. Our operating companies also eliminated late payment charges beginning in March 2020, with New Hampshire being the only state with a defined restart date of April 1, 2021. In 2020, we have waived $6.1 million of late payment charges that would have otherwise been recognized within revenues as a benefit to pre-tax earnings.

For the year ended December 31, 2020, net incremental costs incurred as a result of COVID-19 totaled $35.2 million and related to uncollectible expense that impacts earnings, facilities and fleet cleaning, sanitizing costs and supplies for personal protective equipment, net of cost savings. We have deferred $24.0 million of these net incremental COVID-19 costs on the balance sheet, of which $15.8 million of that deferral related to uncollectible expense that impacts earnings and $8.2 million related to cleaning and supplies for personal protective equipment. Incremental COVID-19 expenses that reduced pre-tax earnings totaled $11.1 million on the statement of income. For further information on Connecticut, Massachusetts and New Hampshire COVID-19-related regulatory developments, see "Regulatory Developments and Rate Matters - COVID-19 Regulatory Dockets" included in this Management’s Discussion and Analysis.

An extended economic slowdown has resulted in lower demand for electricity, natural gas and/or water by our commercial and industrial customers. However, fluctuations in retail sales volumes for CL&P, NSTAR Electric, Yankee Gas, NSTAR Gas, EGMA, and our Connecticut water distribution business do not materially impact earnings due to their respective state regulatory commission-approved distribution revenue decoupling mechanisms. Overall, our risk of exposure to lower demand and resulting lost sales revenues is limited as our regulated utilities are under cost-of-service rates with revenue decoupling mechanisms (with the exception of PSNH) and a significant portion of uncollectible expenses are tracked for ultimate recovery. Our revenue decoupling mechanisms allow us to recover an annual revenue stream that is decoupled from actual customer usage, and each is reconciled each year as part of our annual decoupling filing in each respective jurisdiction.

We continue to monitor Eversource parent’s and our operating companies’ ability to access the global capital and credit markets. At the onset of the pandemic in the United States, liquidity in the commercial paper credit market began to deteriorate rapidly. However, federal legislative actions, including actions taken by the Federal Reserve, have provided sufficient liquidity and stabilization of the credit markets. An extended economic slowdown could result in Eversource parent and our operating companies finding difficulty in accessing necessary capital resources and incurring higher costs for those capital resources. At this time, based on available information and the current market trends, we believe we will continue to have access to needed liquidity and capital resources to successfully execute our projected capital expenditures and strategies. We expect our existing borrowing availability under our commercial paper programs, our existing revolving credit facilities that serve to backstop those commercial paper programs, in addition to access to the debt and equity markets, will be sufficient to meet our future liquidity and capital resource needs.

Earnings Overview

Consolidated: Below is a summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Common Shareholders and diluted EPS.


	For the Years Ended December 31,
	2020				2019				2018
(Millions of Dollars, Except Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share
Net Income Attributable to Common Shareholders (GAAP)	$	1,205.2	$	3.55	$	909.1	$	2.81	$	1,033.0	$	3.25

Regulated Companies (non-GAAP)	$	1,223.3	$	3.60	$	1,105.3	$	3.43	$	1,006.7	$	3.17
Eversource Parent and Other Companies (non-GAAP)	14.0		0.04		8.2		0.02		26.3		0.08
Non-GAAP Earnings	$	1,237.3	$	3.64	$	1,113.5	$	3.45	$	1,033.0	$	3.25
Acquisition-Related Costs (after-tax) (1)	(32.1)		(0.09)		—		—		—		—
Impairment of Northern Pass Transmission (after-tax)	—		—		(204.4)		(0.64)		—		—
Net Income Attributable to Common Shareholders (GAAP)	$	1,205.2	$	3.55	$	909.1	$	2.81	$	1,033.0	$	3.25

Regulated Companies: Our regulated companies comprise the electric distribution, electric transmission, natural gas distribution and water distribution segments. A summary of our segment earnings and EPS is as follows:


	For the Years Ended December 31,
	2020				2019				2018
(Millions of Dollars, Except Per Share Amounts)	Amount		Per Share		Amount		Per Share		Amount		Per Share
Net Income - Regulated Companies (GAAP)	$	1,221.8	$	3.60	$	900.9	$	2.79	$	1,006.7	$	3.17

Electric Distribution	$	544.0	$	1.60	$	513.3	$	1.59	$	455.4	$	1.44
Electric Transmission, excluding Northern Pass Transmission impairment (Non-GAAP)	502.5		1.48		460.9		1.43		427.2		1.34
Natural Gas Distribution, excluding Acquisition-Related Costs (non-GAAP)	135.6		0.40		96.2		0.30		93.2		0.29
Water Distribution	41.2		0.12		34.9		0.11		30.9		0.10
Net Income - Regulated Companies (Non-GAAP)	$	1,223.3	$	3.60	$	1,105.3	$	3.43	$	1,006.7	$	3.17
Acquisition-Related Costs (after-tax) (1)	(1.5)		—		—		—		—		—
Impairment of Northern Pass Transmission (after-tax)	—		—		(204.4)		(0.64)		—		—
Net Income - Regulated Companies (GAAP)	$	1,221.8	$	3.60	$	900.9	$	2.79	$	1,006.7	$	3.17

(1) These costs are associated with our acquisition and integration of the assets of Columbia Gas of Massachusetts. Additional integration costs related primarily to the integration and transition of systems, are expected in 2021.

Our electric distribution segment earnings increased $30.7 million in 2020, as compared to 2019, due primarily to base distribution rate increases at CL&P effective May 1, 2020 and May 1, 2019, at NSTAR Electric effective January 1, 2020, and at PSNH effective July 1, 2019, higher earnings from CL&P's capital tracker mechanism due to increased electric system improvements, and the impact of the PSNH rate settlement agreement approved in December 2020. The earnings increase was partially offset by higher operations and maintenance expense (primarily attributable to higher storm restoration costs), higher depreciation expense, higher property tax expense, higher interest expense, and the absence of the 2019 recognition of carrying charges on PSNH's 2013 through 2016 storm costs approved for recovery.

Our electric transmission segment earnings increased $246.0 million in 2020, as compared to 2019, due primarily to the absence in 2020 of the 2019 impairment of NPT, which resulted in an after-tax charge of $204.4 million, or $0.64 per share. Excluding the NPT impairment charge, earnings increased $41.6 million in 2020, as compared to 2019, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure and a higher benefit from the annual billing and cost reconciliation filing with FERC.

Our natural gas distribution segment earnings increased $37.9 million in 2020, as compared to 2019, due primarily to base distribution rate increases at Yankee Gas effective January 1, 2020 and at NSTAR Gas effective November 1, 2020, the addition of Eversource Gas Company of Massachusetts (EGMA), higher earnings from capital tracker mechanisms due to continued investments in natural gas infrastructure, and lower interest expense due to a property tax settlement. EGMA's natural gas distribution business earned $13.9 million from October 9, 2020 through December 31, 2020. The earnings increase was partially offset by higher operations and maintenance expense and higher depreciation expense.

Our water distribution segment earnings increased $6.3 million in 2020, as compared to 2019, due primarily to an after-tax gain of $3.5 million on the sale of the water system and treatment plant of the Hingham, Massachusetts business, higher revenues from our Connecticut business' capital tracker mechanism due to increased infrastructure improvements, and a gain on the sale of land, partially offset by higher property tax expense and a higher effective tax rate.

Eversource Parent and Other Companies: Eversource parent and other companies earnings decreased $24.8 million in 2020, as compared to 2019, due primarily to the costs of the CMA asset acquisition recorded at Eversource parent of $30.6 million in 2020. Excluding the CMA asset acquisition costs, earnings increased $5.8 million due primarily to a higher return at Eversource Service as a result of increased investments in property, plant and equipment, and lower employee-related costs, partially offset by lower unrealized gains associated with our equity method investment in a renewable energy fund.

Liquidity

Cash totaled $106.6 million as of December 31, 2020, compared with $15.4 million as of December 31, 2019.

Short-Term Debt - Commercial Paper Programs and Credit Agreements: Eversource parent has a $2.00 billion commercial paper program allowing Eversource parent to issue commercial paper as a form of short-term debt. Eversource parent, CL&P, PSNH, NSTAR Gas, Yankee Gas and Aquarion Water Company of Connecticut are parties to a five-year $1.45 billion revolving credit facility, which terminates on December 6, 2024. On October 21, 2020, Eversource parent and EGMA entered into a short-term $550 million revolving credit facility, which terminates on October 20, 2021. These revolving credit facilities serve to backstop Eversource parent's $2.00 billion commercial paper program.

NSTAR Electric has a $650 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. NSTAR Electric is also a party to a five-year $650 million revolving credit facility, which terminates on December 6, 2024. The revolving credit facility serves to backstop NSTAR Electric's $650 million commercial paper program.

The amount of borrowings outstanding and available under the commercial paper programs were as follows:


	Borrowings Outstanding as of December 31,				Available Borrowing Capacity as of December 31,				Weighted-Average Interest Rate as of December 31,
(Millions of Dollars)	2020		2019		2020		2019		2020		2019
Eversource Parent Commercial Paper Program	$	1,054.3	$	1,224.9	$	945.7	$	225.1	0.25	%	1.98	%
NSTAR Electric Commercial Paper Program	195.0		10.5		455.0		639.5		0.16	%	1.63	%

There were no borrowings outstanding on the revolving credit facilities as of December 31, 2020 or 2019.

On May 15, 2020, CL&P and PSNH entered into uncommitted line of credit agreements, which will expire by May 14, 2021. The CL&P agreements total $450 million and the PSNH agreements total $300 million. There are no borrowings outstanding on either the CL&P or PSNH uncommitted line of credit agreements as of December 31, 2020.

Amounts outstanding under the commercial paper programs are included in Notes Payable and classified in current liabilities on the Eversource and NSTAR Electric balance sheets, as all borrowings are outstanding for no more than 364 days at one time.

Intercompany Borrowings: Eversource parent uses its available capital resources to provide loans to its subsidiaries to assist in meeting their short-term borrowing needs. Eversource parent records intercompany interest income from its loans to subsidiaries, which is eliminated in consolidation. Intercompany loans from Eversource parent to its subsidiaries are eliminated in consolidation on Eversource's balance sheets. As of December 31, 2020, there were intercompany loans from Eversource parent to PSNH of $46.3 million, and to a subsidiary of NSTAR Electric of $21.3 million. As of December 31, 2019, there were intercompany loans from Eversource parent to CL&P of $63.8 million, to PSNH of $27.0 million, and to a subsidiary of NSTAR Electric of $30.3 million. Intercompany loans from Eversource parent are included in Notes Payable to Eversource Parent and classified in current liabilities on the respective subsidiary's balance sheets.

Long-Term Debt Issuance Authorizations: On January 27, 2020, the DPU approved NSTAR Gas' request for authorization to issue up to $270 million in long-term debt through December 31, 2021. On July 31, 2020, the NHPUC approved PSNH's request for authorization to issue up to $200 million in long-term debt through December 31, 2020. On December 14, 2020, NSTAR Electric filed a petition with the DPU for authorization to issue $1.6 billion in long-term debt through December 31, 2023. On December 16, 2020, Aquarion Water Company of Connecticut filed an application with PURA for authorization to issue $100 million in long-term debt through December 31, 2021.

Long-Term Debt Issuances and Repayments: The following table summarizes long-term debt issuances and repayments:


(Millions of Dollars)	Issuance/(Repayment)		Issue Date or Repayment Date	Maturity Date	Use of Proceeds for Issuance/ Repayment Information
CL&P:
0.75% Series A First Mortgage Bonds	$	400.0	December 2020	December 2025	Refinanced short-term borrowings, funded capital expenditures and working capital
NSTAR Electric:
3.95% 2020 Debentures	400.0		March 2020	April 2030	Refinanced investments in eligible green expenditures, which were previously financed in 2018 and 2019
5.10% Series E Senior Notes	(95.0)		March 2020	March 2020	Paid at maturity
PSNH:
2.40% Series U First Mortgage Bonds	150.0		August 2020	September 2050	Refinanced short-term borrowings, funded capital expenditures and working capital
Other:
Eversource Parent 3.45% Series P Senior Notes	350.0		January 2020	January 2050	Paid short-term borrowings
Eversource Parent 3.45% Series P Senior Notes (1)	300.0		August 2020	January 2050	(2)
Eversource Parent 0.80% Series Q Senior Notes	300.0		August 2020	August 2025	(2)
Eversource Parent 1.65% Series R Senior Notes	600.0		August 2020	August 2030	(2)
Eversource Parent 2.50% Series I Senior Notes	(450.0)		February 2021	March 2021	Paid on par call date in advance of maturity date
NSTAR Gas 4.46% Series N First Mortgage Bonds	(125.0)		January 2020	January 2020	Paid at maturity
NSTAR Gas 2.33% Series R First Mortgage Bonds	75.0		May 2020	May 2025	Refinanced existing indebtedness, funded capital expenditures and for general corporate purposes
NSTAR Gas 3.15% Series S First Mortgage Bonds	115.0		May 2020	May 2050	Refinanced existing indebtedness, funded capital expenditures and for general corporate purposes
NSTAR Gas 9.95% Series J First Mortgage Bonds	(25.0)		December 2020	December 2020	Paid at maturity
Yankee Gas 4.87% Series K First Mortgage Bonds	(50.0)		April 2020	April 2020	Paid at maturity
Yankee Gas 2.90% Series R First Mortgage Bonds	70.0		September 2020	September 2050	Refinanced existing indebtedness, funded capital expenditures and for general corporate purposes
Aquarion Water Company of Massachusetts, Inc. and Aquarion Water Capital of Massachusetts, Inc. various term loans and general mortgage bonds	(32.2)		July 2020	Various	Redeemed long-term debt in conjunction with the sale of assets to the Town of Hingham, Massachusetts

(1) These senior notes are part of the same series issued by Eversource parent in January 2020. The aggregate outstanding principal amount of these senior notes is now $650 million.

(2) The proceeds from these Eversource parent issuances funded a portion of the purchase price for the CMA asset acquisition and refinanced short-term borrowings.

In January 2021, PSNH provided a redemption notice to the holders of the PSNH 4.050% Series Q First Mortgage Bonds that PSNH will redeem the $122 million of bonds on March 1, 2021, the par call date, in advance of the June 1, 2021 maturity date.

Rate Reduction Bonds: PSNH's RRB payments consist of principal and interest and are paid semi-annually. PSNH paid $43.2 million of RRB principal payments and $20.2 million of interest payments in 2020, and $52.3 million of RRB principal payments and $26.8 million of interest payments in 2019.

Common Share Issuances and 2019 Forward Sale Agreement: On June 15, 2020, Eversource completed an equity offering of 6,000,000 common shares at a price per share of $86.26. Eversource used the net proceeds of this offering to fund a portion of the purchase of the assets of CMA that closed on October 9, 2020. The issuance of these common shares resulted in proceeds of $509.2 million, net of issuance costs.

In June 2019, Eversource completed an equity offering consisting of 5,980,000 common shares issued directly by the Company and 11,960,000 common shares issuable pursuant to a forward sale agreement with an investment bank. Under the forward sale agreement, 11,960,000 common shares were borrowed from third parties and sold by the underwriters. The forward sale agreement allowed Eversource, at its election and prior to May 29, 2020, to physically settle the forward sale agreement by issuing common shares in exchange for net proceeds at the then-applicable forward sale price specified by the agreement (initially, $71.48 per share) or, alternatively, to settle the forward sale agreement in whole or in part through the delivery or receipt of shares or cash. The forward sale price was subject to adjustment daily based on a floating interest rate factor and would decrease in respect of certain fixed amounts specified in the agreement, such as dividends.

Eversource issued 6,000,000 common shares under the forward sale agreement in December 2019. On March 23, 2020, Eversource physically settled a portion of the forward sale agreement by delivering 1,500,000 common shares in exchange for net proceeds of $105.7 million. Subsequently, on March 26, 2020, Eversource physically settled the remaining portion of the forward sale agreement by delivering 4,460,000 common shares in exchange for net proceeds of $314.1 million. The forward sale price used to determine the cash proceeds received by Eversource was calculated based on the initial forward sale price, as adjusted in accordance with the forward sale agreement.

The March and June 2020 common share issuances of 5,960,000 and 6,000,000, respectively, resulted in total proceeds of $929.0 million, net of issuance costs. The June and December 2019 common share issuances of 5,980,000 and 6,000,000, respectively, resulted in total proceeds of $852.3 million. These issuances were reflected in shareholders’ equity and as financing activities on the statements of cash flows.

Issuances of shares under the forward sale agreement were classified as equity transactions. Accordingly, no amounts relating to the forward sale agreement were recorded in the financial statements until settlements took place. Prior to any settlements, the only impact of the forward sale agreement to the financial statements was the inclusion of incremental shares within the calculation of diluted EPS using the treasury stock method. See Note 21, "Earnings Per Share," to the financial statements for information on the forward sale agreement’s impact on the calculation of diluted EPS.

Eversource used the net proceeds received from the direct issuance of common shares and the net proceeds received from settlement of the forward sale agreement to repay short-term debt under the commercial paper program, to partially fund the purchase of the assets of CMA, to fund capital spending and clean energy initiatives, and for general corporate purposes.

Cash Flows: Cash flows provided by operating activities totaled $1.68 billion in 2020, compared with $2.01 billion in 2019. Operating cash flows were unfavorably impacted by the timing of cash collections on our accounts receivable, the timing of collections for regulatory tracking mechanisms primarily related to transmission costs and the impact of the CL&P temporary rate suspension, and cash payments made in 2020 for storm restoration costs of approximately $196 million related to Tropical Storm Isaias. Also contributing to the unfavorable impact was the absence of $68.8 million in DOE Phase IV proceeds received by CYAPC and YAEC in 2019. Partially offsetting these unfavorable impacts were the favorable timing of cash payments made on our accounts payable, the absence of a $29.0 million payment made in 2019 to the DOE by CYAPC to partially settle its pre-1983 spent nuclear fuel obligation, and a decrease of $10.3 million in Pension and PBOP contributions made in 2020, as compared to 2019.

Our receivables, net of reserves, on the balance sheet have increased $206.5 million ($58.3 million at CL&P, $56.3 million at NSTAR Electric, and $20.0 million at PSNH) in 2020, as compared to 2019, due primarily to an increase in delinquent receivables from customers attributable to the moratorium on disconnections and the economic slowdown resulting from the COVID-19 pandemic. Receivables, net of reserves, also increased due to the addition of EGMA of $65.8 million as of December 31, 2020.

Cash flows provided by operating activities totaled $2.01 billion in 2019, compared with $1.83 billion in 2018. The increase in operating cash flows was due primarily to a decrease in 2019 of approximately $148 million of major storm restoration cost payments, $116 million in lower payments made in 2019 to the DOE by CYAPC to partially settle its pre-1983 spent nuclear fuel obligation, and a $73.2 million decrease in pension and PBOP cash contributions made in 2019, as compared to 2018. Also contributing to the increase were $102.8 million of lower income tax payments made in 2019, as compared to 2018, $68.8 million in DOE Phase IV litigation proceeds received by CYAPC and YAEC in 2019, and the timing of cash collections on our accounts receivables. Partially offsetting these favorable impacts were the timing of collections for regulatory tracking mechanisms, which were significantly impacted by the timing of collections of purchased power and transmission costs at NSTAR Electric, and the timing of accounts payable cash payments and other working capital items.

In 2020, we paid cash dividends of $744.7 million and issued non-cash dividends of $22.8 million in the form of treasury shares, totaling dividends of $767.5 million, or $2.27 per common share. In 2019, we paid cash dividends of $663.2 million and issued non-cash dividends of $22.8 million in the form of treasury shares, totaling dividends of $686.0 million, or $2.14 per common share. Our quarterly common share dividend payment was $0.5675 per share in 2020, as compared to $0.535 per share in 2019. On February 9, 2021, our Board of Trustees approved a common share dividend payment of $0.6025 per share, payable on March 31, 2021 to shareholders of record as of March 4, 2021. The 2021 dividend represents an increase of 6.2 percent over the dividend paid in December 2020.

Beginning in 2019, Eversource issues treasury shares to satisfy awards under the Company's incentive plans, shares issued under the dividend reinvestment and share purchase plan, and matching contributions under the Eversource 401k Plan.

In 2020, CL&P, NSTAR Electric and PSNH paid $69.5 million, $262.0 million and $22.3 million, respectively, in common stock dividends to Eversource parent.

Investments in Property, Plant and Equipment on the statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized and deferred portions of pension and PBOP expense. In 2020, investments for Eversource, CL&P, NSTAR Electric and PSNH were $2.94 billion, $834.0 million, $907.0 million and $342.6 million, respectively.

On October 9, 2020, Eversource completed the CMA asset acquisition for a cash purchase price of $1.1 billion plus a target working capital amount of $69.6 million, which is subject to adjustment to reflect actual working capital as of the closing date. The purchase price included in investing cash outflows on the statement of cash flows of $1.11 billion reflects the payment to NiSource, which excludes restricted cash accounts Eversource funded of $56.8 million. For further information, see "Business Development and Capital Expenditures - Acquisition of Assets of Columbia Gas of Massachusetts" included in this Management’s Discussion and Analysis.

Eversource, CL&P, NSTAR Electric and PSNH each uses its available capital resources to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends, and fund other corporate obligations, such as pension contributions. Eversource's regulated companies recover their electric, natural gas and water distribution construction expenditures as the related project costs are depreciated over the life of the assets. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity and debt used to finance the investments. The current growth in Eversource's construction expenditures utilizes a significant amount of cash for projects that have a long-term return on investment and recovery period, totaling approximately $2.94 billion in cash capital spend in 2020. In addition, Eversource's investments in its offshore wind business totaled $237.8 million in 2020, which are recognized as long-term assets. These factors have resulted in current liabilities exceeding current assets by $1.78 billion, $316.3 million, and $271.3 million at Eversource, NSTAR Electric and PSNH, respectively, as of December 31, 2020.

As of December 31, 2020, $1.02 billion of Eversource's long-term debt, including $450.0 million, $250.0 million, $282.0 million, and $40.2 million for Eversource parent, NSTAR Electric, PSNH, and Aquarion, respectively, will mature within the next 12 months. The current portion of long-term debt on the Eversource balance sheet also includes $31.0 million related to fair value adjustments from our various business combinations that will be amortized within the next 12 months and have no cash flow impact. Eversource, with its strong credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. Eversource, CL&P, NSTAR Electric and PSNH will reduce their short-term borrowings with operating cash flows or with the issuance of new long-term debt, determined by considering capital requirements and maintenance of Eversource's credit rating and profile.

We expect the future operating cash flows of Eversource, CL&P, NSTAR Electric and PSNH, along with our existing borrowing availability and access to both debt and equity markets, will be sufficient to meet any working capital and future operating requirements, and capital investment forecasted opportunities.

Credit Ratings: A summary of our corporate credit ratings and outlooks by S&P, Moody's, and Fitch is as follows:


	S&P		Moody's		Fitch
	Current	Outlook	Current	Outlook	Current	Outlook
Eversource Parent	A-	Stable	Baa1	Stable	BBB+	Stable
CL&P	A	Stable	A3	Stable	A-	Stable
NSTAR Electric	A	Stable	A1	Stable	A	Stable
PSNH	A	Stable	A3	Stable	A-	Stable

A summary of the current credit ratings and outlooks by S&P, Moody's, and Fitch for senior unsecured debt of Eversource parent and NSTAR Electric, and senior secured debt of CL&P and PSNH is as follows:


	S&P		Moody's		Fitch
	Current	Outlook	Current	Outlook	Current	Outlook
Eversource Parent	BBB+	Stable	Baa1	Stable	BBB+	Stable
CL&P	A+	Stable	A1	Stable	A+	Stable
NSTAR Electric	A	Stable	A1	Stable	A+	Stable
PSNH	A+	Stable	A1	Stable	A+	Stable

Business Development and Capital Expenditures

Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized and deferred portions of pension and PBOP expense (all of which are non-cash factors), totaled $3.06 billion in 2020, $3.06 billion in 2019, and $2.86 billion in 2018. These amounts included $239.1 million in 2020, $239.0 million in 2019, and $184.6 million in 2018 related to information technology and facilities upgrades and enhancements, primarily at Eversource Service and The Rocky River Realty Company.

Electric Transmission Business: Our consolidated electric transmission business capital expenditures decreased by $75.8 million in 2020, as compared to 2019. A summary of electric transmission capital expenditures by company is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	2020		2019		2018
CL&P	$	402.9	$	459.5	$	465.5
NSTAR Electric	366.8		379.7		334.3
PSNH	193.9		190.4		194.2
NPT	—		9.8		29.4
Total Electric Transmission Segment	$	963.6	$	1,039.4	$	1,023.4

Eastern Massachusetts Transmission Projects: These projects consist of a portfolio of electric transmission upgrades in southern New Hampshire, northern Massachusetts and continuing into the greater Boston metropolitan area, of which 28 upgrades are in Eversource's service territory (two in New Hampshire and 26 in Massachusetts). The two New Hampshire upgrades, including the Merrimack Valley Reliability Project, have been placed in service, and 23 Massachusetts upgrades have been placed in service. On December 17, 2019, the Massachusetts Siting Board issued a favorable decision on the Sudbury-Hudson Reliability Project, the last project requiring such approval. On January 17, 2020, the Town of Sudbury and Protect Sudbury, a community group, appealed the decision to the Massachusetts Supreme Judicial Court. Oral arguments are scheduled for March 1, 2021. The majority of remaining upgrades are under construction and are expected to be placed in service in 2022. We estimate our portion of the investment will be approximately $750 million, of which $525 million has been spent and capitalized through December 31, 2020.

Southeastern Massachusetts Transmission Projects: These projects consist of a portfolio of electric transmission and substation upgrades in southeastern Massachusetts, including Cape Cod, required to reinforce the Southeastern Massachusetts transmission system and bring the system into compliance with applicable national and regional reliability standards. ISO-NE reassessed the need for projects that had yet to be constructed and reconfirmed the need for the majority of the originally identified reinforcements in July 2020. Twelve upgrades in Eversource's service territory were reconfirmed, and a single upgrade was deemed to no longer be required. Of the twelve upgrades, four require siting approvals from the Massachusetts regulatory agencies, of which one has received approval, two are before the agencies and one, a joint project with National Grid, has yet to be filed. Three substation projects will be permitted locally, three projects are under construction and two projects have been placed in-service. We estimate our portion of the investment will be approximately $175 million, of which $28 million has been spent and capitalized through December 31, 2020.

Hartford-Area Transmission Projects: This portfolio of projects consisted of 27 projects in the Hartford, Connecticut area. In the third quarter of 2020, the final projects were placed in service and as of December 31, 2020, CL&P has spent and capitalized $303 million in costs associated with this portfolio. Additional restoration costs in the first quarter of 2021 will bring the total investment to approximately $304 million.

Seacoast Reliability Project: The Seacoast Reliability Project consisted of a 13-mile, 115kV transmission line within several New Hampshire communities, using a combination of overhead, underground and underwater line designs that helped meet the growing demand for electricity in the Seacoast region. The project was placed in service on May 29, 2020 and resulted in an investment of approximately $124 million.

Ready Path Solution: The Ready Path Solution was chosen in 2020 by ISO-NE as part of the first competitive solicitation for reliability upgrades in New England to meet the energy shortfall that will be created with the retirement of the Mystic Generating Station in Massachusetts in 2024. Our portion of the portfolio consists of installing new equipment at Eversource’s existing North Cambridge Substation with an estimated investment of approximately $14 million. The project is advancing permitting and engineering with construction scheduled to start in 2021.

All project costs are anticipated to be fully recoverable through transmission rates.

Distribution Business: A summary of distribution capital expenditures is as follows:


	For the Years Ended December 31,
(Millions of Dollars)	CL&P		NSTAR Electric		PSNH		Total Electric		Natural Gas		Water		Total
2020
Basic Business	$	233.4	$	195.1	$	52.4	$	480.9	$	88.2	$	10.9	$	580.0
Aging Infrastructure	179.9		237.1		80.2		497.2		391.3		115.5		1,004.0
Load Growth and Other	77.8		110.8		21.3		209.9		65.6		0.8		276.3
Total Distribution	491.1		543.0		153.9		1,188.0		545.1		127.2		1,860.3
Solar	—		1.4		—		1.4		—		—		1.4
Total	$	491.1	$	544.4	$	153.9	$	1,189.4	$	545.1	127.2		$	1,861.7

2019
Basic Business	$	228.7	$	201.0	$	47.3	$	477.0	$	71.2	$	15.0	$	563.2
Aging Infrastructure	224.5		255.5		90.8		570.8		315.2		93.9		979.9
Load Growth and Other	59.6		89.4		16.8		165.8		66.8		1.5		234.1
Total Distribution	512.8		545.9		154.9		1,213.6		453.2		110.4		1,777.2
Solar	—		7.5		—		7.5		—		—		7.5
Total	$	512.8	$	553.4	$	154.9	$	1,221.1	$	453.2	$	110.4	$	1,784.7

2018
Basic Business	$	256.3	$	217.7	$	69.3	$	543.3	$	72.9	$	17.0	$	633.2
Aging Infrastructure	151.6		133.3		73.0		357.9		280.2		81.1		719.2
Load Growth and Other	79.7		94.3		15.6		189.6		51.4		3.6		244.6
Total Distribution	487.6		445.3		157.9		1,090.8		404.5		101.7		1,597.0
Solar and Other	—		53.4		0.9		54.3		—		—		54.3
Total	$	487.6	$	498.7	$	158.8	$	1,145.1	$	404.5	$	101.7	$	1,651.3

For the electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant. Aging infrastructure relates to reliability and the replacement of overhead lines, plant substations, underground cable replacement, and equipment failures. Load growth and other includes requests for new business and capacity additions on distribution lines and substation additions and expansions.

For the natural gas distribution business, basic business addresses daily operational needs including meters, pipe relocations due to public works projects, vehicles, and tools. Aging infrastructure projects seek to improve the reliability of the system through enhancements related to cast iron and bare steel replacement of main and services, corrosion mediation, and station upgrades. Load growth and other reflects growth in existing service territories including new developments, installation of services, and expansion.

For the water distribution business, basic business addresses daily operational needs including periodic meter replacement, water main relocation, facility maintenance, and tools. Aging infrastructure relates to reliability and the replacement of water mains, regulators, storage tanks, pumping stations, wellfields, reservoirs, and treatment facilities. Load growth and other reflects growth in our service territory, including improvements of acquisitions, installation of new services, and interconnections of systems.

Acquisition of Assets of Columbia Gas of Massachusetts: On October 9, 2020, Eversource acquired certain assets and liabilities that comprised NiSource’s natural gas distribution business in Massachusetts, which was previously doing business as CMA, pursuant to an asset purchase agreement (the Agreement) entered into on February 26, 2020 between Eversource and NiSource Inc. (NiSource). The cash purchase price was $1.1 billion, plus a target working capital amount of $69.6 million, which is subject to adjustment to reflect actual working capital as of the closing date that has not yet been finalized. Eversource financed the asset acquisition through a combination of debt and equity issuances in a ratio that was consistent with our consolidated capital structure. The natural gas distribution assets acquired from CMA were assigned to EGMA, an indirect wholly-owned subsidiary of Eversource formed in 2020. The LNG assets acquired from CMA were assigned to Hopkinton LNG Corp. EGMA distributes natural gas to approximately 332,000 residential, commercial and industrial customers with over 5,000 miles of natural gas distribution pipeline across more than 60 communities in Massachusetts, adding to the approximately 303,000 natural gas customers that Eversource already serves in Massachusetts.

The transaction required approval by the DPU, the Maine Public Utilities Commission, the FERC, and the Federal Communications Commission, and review under the Hart-Scott-Rodino Act.

The liabilities assumed by Eversource under the Agreement specifically excluded any liabilities (past or future) arising out of, or related to, the fires and explosions that occurred on September 13, 2018 in Lawrence, Andover and North Andover, Massachusetts related to the delivery of natural gas by CMA, including certain subsequent events, all as described and in the DPU's Order on Scope dated December 23, 2019 (D.P.U. 19-141) (the Greater Lawrence Incident or GLI). The liabilities assumed also excluded any further emergency events prior to the closing of the acquisition related to the restoration and reconstruction with respect to the GLI, including any losses arising out of, or related to, any litigation, demand, cause of action, claim, suit, investigation, proceeding, indemnification agreements or rights. Eversource did not assume any of CMA's or NiSource Inc.'s third party debt obligations or notes payable.

EGMA Rate Settlement Agreement: On October 7, 2020, the DPU approved a rate settlement agreement, which requested approval of the February 26, 2020 asset purchase agreement between Eversource and NiSource, as well as a rate stabilization plan, among other items. The settlement agreement included an authorized regulatory ROE of 9.70 percent as of January 1, 2021, a 53.25 percent equity component of its capital structure, and established rate base equal to $995 million as of the closing on October 9, 2020.

The approved rate stabilization plan includes base distribution rate increases of $13 million on November 1, 2021 and $10 million on November 1, 2022. The settlement agreement includes two rate base resets during an eight-year rate plan, occurring on November 1, 2024 and November 1, 2027. The two rate base resets adjust distribution rates to account for capital additions (including the roll-in of GSEP capital additions), depreciation expense, property taxes, and return on rate base for capital additions placed into service through December 31, 2023, for the first rate base reset occurring on November 1, 2024, and through December 31, 2026, for the second rate base reset occurring on November 1, 2027. Notwithstanding the two distribution rate increases, the two rate base reset provisions, and potential adjustments for qualifying exogenous events, EGMA agreed not to file for an increase or redesign of distribution base rates effective prior to November 1, 2028.

The settlement agreement also permits EGMA to seek recovery of both transaction and integration costs as a result of the asset acquisition after December 31, 2026, subject to DPU review and approval, and subject to certain conditions, such as demonstrating savings resulting from the acquisition.

Projected Capital Expenditures: A summary of the projected capital expenditures for the regulated companies' electric transmission and for the total electric distribution, natural gas distribution and water distribution for 2021 through 2025, including information technology and facilities upgrades and enhancements on behalf of the regulated companies, is as follows:


	Years
(Millions of Dollars)	2021		2022		2023		2024		2025		2021 - 2025 Total
CL&P Transmission	$	443	$	264	$	204	$	206	$	173	$	1,290
NSTAR Electric Transmission	469		462		426		331		385		2,073
PSNH Transmission	153		189		223		224		153		942
Total Electric Transmission	$	1,065	$	915	$	853	$	761	$	711	$	4,305
Electric Distribution	$	1,269	$	1,309	$	1,353	$	1,289	$	1,229	$	6,449
Natural Gas Distribution	824		925		974		937		789		4,449
Total Electric and Natural Gas Distribution	$	2,093	$	2,234	$	2,327	$	2,226	$	2,018	$	10,898
Water Distribution	$	149	$	143	$	154	$	162	$	171	$	779
Information Technology and All Other	$	217	$	249	$	211	$	194	$	176	$	1,047
Total	$	3,524	$	3,541	$	3,545	$	3,343	$	3,076	$	17,029

The projections do not include investments related to offshore wind projects. Actual capital expenditures could vary from the projected amounts for the companies and years above.

Offshore Wind Business: Our offshore wind business includes ownership interests in North East Offshore and Bay State Wind, which together hold PPAs and contracts for the Revolution Wind, South Fork Wind and Sunrise Wind projects, as well as offshore leases issued by BOEM. Our offshore wind projects are being developed and constructed through a joint and equal partnership with Ørsted. This partnership also participates in new procurement opportunities for offshore wind energy in the Northeast U.S.

Eversource has a 50 percent ownership interest in North East Offshore, which holds the Revolution Wind and South Fork Wind projects, as well as a 257 square-mile ocean lease off the coasts of Massachusetts and Rhode Island. Eversource also has a 50 percent ownership interest in Bay State Wind, which holds the Sunrise Wind project. Bay State Wind's separate 300-square-mile ocean lease is located approximately 25 miles south of the coast of Massachusetts adjacent to the North East Offshore area. In aggregate, the Bay State Wind and the North East Offshore ocean lease sites jointly-owned by Eversource and Ørsted could eventually develop at least 4,000 MW of clean, renewable offshore wind energy. As of December 31, 2020, Eversource's total equity investment balance in its offshore wind business was $887.1 million, an increase of $237.8 million, as compared to 2019.

We are preparing our final project designs and advancing the appropriate federal, state and local siting and permitting processes along with our offshore wind partner, Ørsted, all of which is competitively sensitive. We currently expect to make investments in our offshore wind business of approximately $300 million to $500 million during 2021, subject to advancing our final project designs and federal, state and local permitting processes.

The following table provides a summary of the Eversource and Ørsted major projects with announced contracts:


Wind Project	State Servicing	Size (MW)	Term (Years)	Price per MWh	Pricing Terms	Contract Status
Revolution Wind	Rhode Island	400	20	$98.43	Fixed price contract; no price escalation	Approved
Revolution Wind	Connecticut	304	20	(1)	Fixed price contracts; no price escalation	Approved
South Fork Wind	New York (LIPA)	90	20	$160.33	2 percent average price escalation	Approved
South Fork Wind	New York (LIPA)	40	20	$86.25	2 percent average price escalation	(3)
Sunrise Wind	New York (NYSERDA)	880	25	$110.37 (2)	Fixed price contract; no price escalation	Approved

(1) The pricing for the Revolution Wind contracts in Connecticut has not been publicly disclosed.

(2) Index Offshore Wind Renewable Energy Certificate (OREC) strike price.

(3) The Long Island Power Authority (LIPA) agreed to expand the original 20-year PPA from 90 MW to 130 MW through an amendment to the original agreement. The amendment is awaiting final approval from the New York Comptroller's Office.

Our offshore wind projects are subject to receipt of federal, state and local approvals necessary to construct and operate the projects. The federal permitting process is governed by BOEM, and state approvals are required from New York, Rhode Island and Massachusetts. Significant delays in the siting and permitting process resulting from the timeline for obtaining approval from BOEM and the state and local agencies, as well as the impact of COVID-19, could adversely impact the timing of these projects' in-service dates.

Federal Siting and Permitting Process: The South Fork Wind project has commenced the federal siting and permitting process with the filing of its Construction Operations Plan (COP) application with BOEM in 2018. The first major milestone in the BOEM review process is an issuance of a Notice of Intent to complete an Environmental Impact Statement (NOI), which South Fork Wind received in 2018. In August 2020, we received the final review schedule from BOEM regarding South Fork Wind’s COP approval. In January 2021, BOEM released its Draft Environmental Impact Statement (EIS) for the South Fork Wind project, which assessed the environmental, social, and economic impacts of constructing the project. Identified impacts were negligible to major adverse impacts to marine and terrestrial archaeological resources and to historic, and non-historic visual resources from project construction and operations. The Draft EIS also analyzed four alternatives to be evaluated as part of the process. Each of the identified alternative configurations had a similar level of environmental impacts, and if an alternative configuration was selected, the South Fork Wind project would still meet the contractual output under its PPA. A Final EIS is expected in the third quarter of 2021 and a final decision is expected in January 2022.

Based on BOEM’s final review schedule and final United States Army Corps of Engineers approval, we expect to start construction on South Fork in early 2022. South Fork Wind is designated as a “Covered Project” pursuant to Title 41 of the Fixing America’s Surface Transportation Act (FAST41) and a Major Infrastructure Project under Section 3(e) of Executive Order 13807, which provides greater federal attention on meeting the project’s permitting timelines.

Revolution Wind and Sunrise Wind filed their COP applications with BOEM in March 2020 and September 2020, respectively. Both projects received FAST41 designation in 2020. We are awaiting BOEM to outline its timeline for completing the review of each of the Revolution Wind and Sunrise Wind COPs in an NOI, which we expect to receive in 2021.

State and Local Siting and Permitting Process: South Fork Wind commenced the New York state siting process in 2018. On September 17, 2020, South Fork Wind filed a Joint Proposal in the New York State Article VII siting application. Amongst other things, the Joint Proposal included proposed mitigations to certain environmental, community and construction impacts associated with constructing electrical infrastructure. South Fork Wind was initially joined by PSEG Long Island and several citizens advocacy organizations. On October 9, 2020, the Joint Proposal was signed by the New York Departments of Public Service, Environmental Conservation, Transportation and State as well as the Office of Parks, Recreation and Historic Preservation. Hearings in the state siting process concluded in December 2020 and a decision is expected in mid-2021.

On September 10, 2020, the Town of East Hampton and the East Hampton Town Trustees announced that they had reached an agreement with South Fork Wind to issue the necessary easements and other real estate rights necessary to construct the South Fork Wind project. The Town approved the easements on January 21, 2021 and Trustees approved the lease on January 25, 2021.

State permitting applications in Rhode Island for Revolution Wind and in New York for Sunrise Wind were filed in December 2020. The Revolution Wind application was deemed complete on January 22, 2021 and the preliminary hearing is set for March 22, 2021.

Projected In-Service Dates: Based on BOEM’s confirmed permit schedule outlining when BOEM will complete its review of the South Fork Wind COP, we now expect the South Fork Wind project to be in-service by the end of 2023. For Revolution Wind and Sunrise Wind, we do not have a definitive timeline on when we will receive BOEM’s NOIs. At this time, we believe that it is unlikely that the projected in-service dates of the end of 2023 and the end of 2024 for Revolution Wind and Sunrise Wind, respectively, will be met. We are currently awaiting the receipt of BOEM’s NOIs for Revolution Wind and Sunrise Wind, which we expect to receive in 2021, in order to conclude on projected in-service dates.

FERC Regulatory Matters

FERC ROE Complaints: Four separate complaints were filed at the FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (collectively, the Complainants). In each of the first three complaints, filed on October 1, 2011, December 27, 2012, and July 31, 2014, respectively, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2005 and sought an order to reduce it prospectively from the date of the final FERC order and for the separate 15-month complaint periods. In the fourth complaint, filed April 29, 2016, the Complainants challenged the NETOs' base ROE billed of 10.57 percent and the maximum ROE for transmission incentive (incentive cap) of 11.74 percent, asserting that these ROEs were unjust and unreasonable.

The ROE originally billed during the period October 1, 2011 (beginning of the first complaint period) through October 15, 2014 consisted of a base ROE of 11.14 percent and incentives up to 13.1 percent. On October 16, 2014, the FERC set the base ROE at 10.57 percent and the incentive cap at 11.74 percent for the first complaint period. This was also effective for all prospective billings to customers beginning October 16, 2014. This FERC order was vacated on April 14, 2017 by the U.S. Court of Appeals for the D.C. Circuit (the Court).

All amounts associated with the first complaint period have been refunded. Eversource has recorded a reserve of $39.1 million (pre-tax and excluding interest) for the second complaint period as of both December 31, 2020 and 2019. This reserve represents the difference between the billed rates during the second complaint period and a 10.57 percent base ROE and 11.74 percent incentive cap. The reserve consisted of $21.4 million for CL&P, $14.6 million for NSTAR Electric and $3.1 million for PSNH as of both December 31, 2020 and 2019.

On October 16, 2018, FERC issued an order on all four complaints describing how it intends to address the issues that were remanded by the Court. FERC proposed a new framework to determine (1) whether an existing ROE is unjust and unreasonable and, if so, (2) how to calculate a replacement ROE. Initial briefs were filed by the NETOs, Complainants and FERC Trial Staff on January 11, 2019 and reply briefs were filed on March 8, 2019. The NETOs' brief was supportive of the overall ROE methodology determined in the October 16, 2018 order provided the FERC does not change the proposed methodology or alter its implementation in a manner that has a material impact on the results.

The FERC order included illustrative calculations for the first complaint using FERC's proposed frameworks with financial data from that complaint. Those illustrative calculations indicated that for the first complaint period, for the NETOs, which FERC concludes are of average financial risk, the preliminary just and reasonable base ROE is 10.41 percent and the preliminary incentive cap on total ROE is 13.08 percent.

If the results of the illustrative calculations were included in a final FERC order for each of the complaint periods, then a 10.41 percent base ROE and a 13.08 percent incentive cap would not have a significant impact on our financial statements for all of the complaint periods. These preliminary calculations are not binding and do not represent what we believe to be the most likely outcome of a final FERC order.

On November 21, 2019, FERC issued Opinion No. 569 affecting the two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted a new methodology for determining base ROEs. Various parties sought rehearing. On December 23, 2019, the NETOs filed supplementary materials in the NETOs' four pending cases to respond to this new methodology because of the uncertainty of the applicability to the NETOs' cases.

On May 21, 2020, the FERC issued its order in Opinion No. 569-A on the rehearing of the MISO transmission owners' cases, in which FERC again changed its methodology for determining the MISO transmission owners' base ROEs. Various parties appealed the MISO transmission owners' opinion. On November 19, 2020, the FERC issued Opinion No. 569-B denying rehearing of Opinion No. 569-A and reaffirmed the methodology previously adopted in Opinion No. 569-A. The new methodology differs significantly from the methodology proposed by FERC in its October 16, 2018 order to determine the NETOs' base ROEs in its four pending cases.

Given the significant uncertainty regarding the applicability of the FERC opinions in the MISO transmission owners' two complaint cases to the NETOs' pending four complaint cases, Eversource concluded that there is no reasonable basis for a change to the reserve or recognized ROEs for any of the complaint periods at this time. As well, Eversource cannot reasonably estimate a range of any gain or loss for any of the four complaint proceedings at this time.

Eversource, CL&P, NSTAR Electric and PSNH currently record revenues at the 10.57 percent base ROE and incentive cap at 11.74 percent established in the October 16, 2014 FERC order.

A change of 10 basis points to the base ROE used to establish the reserves would impact Eversource’s after-tax earnings by an average of approximately $3 million for each of the four 15-month complaint periods. From the date of a final FERC order, a change of 10 basis points to the base ROE would impact Eversource’s 2021 after-tax earnings by approximately $5 million, or $0.01 per share, per year, and will increase slightly over time as we continue to invest in our transmission infrastructure.

FERC Notice of Inquiry on ROE: On March 21, 2019, FERC issued a Notice of Inquiry (NOI) seeking comments from all stakeholders on FERC's policies for evaluating ROEs for electric public utilities, and interstate natural gas and oil pipelines. On June 26, 2019, the NETOs jointly filed comments supporting the methodology established in the FERC’s October 16, 2018 order with minor enhancements going forward. The NETOs jointly filed reply comments in the FERC ROE NOI on July 26, 2019. On May 12, 2020, the NETOs filed supplemental comments in the NOI ROE docket. At this time, Eversource cannot predict how this proceeding will affect its transmission ROEs.

FERC Notice of Inquiry and Proposed Rulemaking on Transmission Incentives: On March 21, 2019, FERC issued an NOI seeking comments on FERC's policies for implementing electric transmission incentives. On June 26, 2019, Eversource filed comments requesting that FERC retain policies that have been effective in encouraging new transmission investment and remain flexible enough to attract investment in new and emerging transmission technologies. Eversource filed reply comments on August 26, 2019. On March 20, 2020, FERC issued a Notice of Proposed Rulemaking (NOPR) on transmission incentives. The NOPR intends to revise FERC’s electric transmission incentive policies to reflect competing uses of transmission due to generation resource mix, technological innovation and shifts in load patterns. FERC proposes to grant transmission incentives based on measurable project economics and reliability benefits to consumers rather than its current project risks and challenges framework. On July 1, 2020, Eversource filed comments generally supporting the NOPR. At this time, Eversource cannot predict how these proceedings will affect its transmission incentives.

FERC Transmission Transparency Settlement: On December 28, 2015, FERC initiated a proceeding to review the NETOs' regional and local transmission formula rates due to a lack of transparency, finding that the formula rates appeared to lack sufficient details to determine how costs are derived and recovered in rates. Parties engaged in further settlement negotiations and reached an agreement in principle on October 22, 2019. On June 15, 2020, the NETOs filed an uncontested Settlement Agreement with FERC, which was signed by all six New England state regulatory commissions, New England States Committee on Electricity, New England Municipals and all the NETOs. On December 28, 2020, the FERC issued an order approving the Settlement Agreement, which establishes annual formula rate transparency procedures effective June 15, 2021, implements a new regional and local rate structure effective January 1, 2022, and contains a rate moratorium through December 31, 2024.

Regulatory Developments and Rate Matters

Electric, Natural Gas and Water Utility Base Distribution Rates: Each Eversource utility subsidiary is subject to the regulatory jurisdiction of the state in which it operates: CL&P, Yankee Gas and Aquarion operate in Connecticut and are subject to PURA regulation; NSTAR Electric, NSTAR Gas, EGMA and Aquarion operate in Massachusetts and are subject to DPU regulation; and PSNH and Aquarion operate in New Hampshire and are subject to NHPUC regulation. The regulated companies' distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates for the recovery of specific incurred costs.

In Connecticut, electric and natural gas utilities are required to file a distribution rate case, or for PURA to initiate a rate review, within four years of the last rate case. CL&P's and Yankee Gas' distribution rates were each established in 2018 PURA-approved rate case settlement agreements. Aquarion is not required to initiate a rate review with the PURA on a set schedule. Aquarion rates were established in a 2013 PURA-approved rate case.

In Massachusetts, electric distribution companies are required to file at least one distribution rate case every five years, and natural gas local distribution companies to file at least one distribution rate case every 10 years, and those companies are limited to one settlement agreement in any 10-year period. NSTAR Electric's distribution rates were established in a 2017 DPU-approved rate case. NSTAR Gas' distribution rates were established in an October 2020 DPU-approved rate case. EGMA's distribution rates were established in an October 2020 DPU-approved rate settlement agreement. Aquarion is not required to initiate a rate review with the DPU. Aquarion rates were established in a 2018 DPU-approved rate case.

In New Hampshire, PSNH's distribution rates were established in a December 2020 NHPUC-approved rate case settlement agreement. Aquarion rates were established in a 2013 NHPUC-approved rate case, further revised in 2016. On December 18, 2020, Aquarion filed an application with the NHPUC for a permanent increase in base rates, effective February 1, 2021.

See "Regulatory Developments and Rate Matters - Massachusetts" and "- New Hampshire," as well as "Business Development and Capital Expenditures – Acquisition of Assets of Columbia Gas of Massachusetts" in this Management's Discussion and Analysis of Financial Condition and Results of Operations, for more information on the NSTAR Gas, PSNH and EGMA 2020 rate approvals.

Electric, Natural Gas and Water Utility Retail Rates: The Eversource electric distribution companies obtain and resell power to retail customers who choose not to buy energy from a competitive energy supplier. The natural gas distribution companies procure natural gas for firm and seasonal customers. These energy supply procurement costs are recovered from customers in energy supply rates that are approved by the respective state regulatory commission. The rates are reset periodically and are fully reconciled to their costs. Each electric and natural gas distribution company fully recovers its energy supply costs through approved regulatory rate mechanisms on a timely basis and, therefore, such costs have no impact on earnings.

The electric and natural gas distribution companies also recover certain other costs on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and, therefore, recovery of these costs has no impact on earnings. Costs recovered through cost tracking mechanisms include, among others, energy efficiency program costs, electric retail transmission charges, electric restructuring and stranded costs (including securitized RRB charges), and additionally for our Massachusetts companies, pension and PBOP benefits and net metering for distributed generation. The reconciliation filings compare the total actual costs allowed to revenue requirements related to these services and the difference between the costs incurred (or the rate recovery allowed) and the actual costs allowed is deferred and included, to be either recovered or refunded, in future customer rates. These cost tracking mechanisms also include certain incentives earned, return on rate base and on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings.

COVID-19 Regulatory Dockets: In Connecticut, PURA opened a docket to address COVID-19 developments, including issuing orders on March 18, 2020, April 29, 2020 and May 15, 2020 that authorized electric, natural gas and water utilities to establish a regulatory asset for COVID-19 uncollectible customer receivable expenses and costs associated with the related orders. PURA’s April 29, 2020 order, as supplemented on May 15, 2020, also allowed the inclusion of working capital costs in the regulatory asset, and authorized electric, natural gas and water utilities to establish a payment plan program designed to assist any customer who requests financial assistance during the COVID-19 pandemic. On July 10, 2020, PURA denied a request from a coalition of large industrial customers to reduce or suspend certain electric and natural gas charges during the COVID-19 pandemic.

In Massachusetts, on July 31, 2020, the DPU approved and adopted a coalition of electric, natural gas and water utilities’ comprehensive Customer Assistance Plan involving extended payment plans and waiver of late fees, extended plans under available arrearage management plans (AMPs), and continuation of the Shut-Off Moratorium. On September 3, 2020, the DPU approved the 2020 small commercial arrearage forgiveness program (AFP) proposed by the electric and natural gas distribution companies. In its interim order dated December 31, 2020, the DPU established certain cost tracking and data reporting requirements for the distribution companies and will allow each company to record, defer, and track incremental cost areas, subject to the DPU’s final determination of the ratemaking treatment in D.P.U. 20-58 and D.P.U. 20-91. In D.P.U. 20-91, the DPU will adjudicate the contested cost-recovery provisions identified in the Ratemaking Proposal and consider proposals to expand alternative customer bill payment options. The distribution companies’ Ratemaking Proposal for COVID-19 financial-related impacts includes recovery requests for each of the following five cost categories: (1) cash working capital; (2) arrearage forgiveness; (3) bad debt; (4) COVID-19 O&M expenses; and (5) waived fees.

In New Hampshire, on October 5, 2020, the NHPUC approved an agreement governing collections and disconnection activities, deposit activities, flexible payment plans, and special arrangements for income-qualified customers for all New Hampshire utilities including Eversource’s electric and water utilities. The terms of that agreement continue through at least April 2021. Also, on August 18, 2020, the NHPUC Staff recommended that utilities in New Hampshire be permitted to create a regulatory asset for waived fees and incremental bad debt related to the COVID-19 pandemic. On November 13, 2020, the NHPUC Staff revised its recommendation arguing that waived fees should not be included in any regulatory asset related to the COVID-19 pandemic. The New Hampshire utilities disputed that recommendation on December 4, 2020, and on December 16, 2020, the NHPUC Staff renewed its November 13, 2020 recommendation. The NHPUC has yet to act on that recommendation.

For information on COVID-19-related regulatory deferrals recorded and COVID-19 charges incurred, see "Impact of COVID-19" included in this Management’s Discussion and Analysis.

Storm Event:

On August 4, 2020, Tropical Storm Isaias caused catastrophic damage to our electric distribution system, which resulted in significant amounts and durations of customer outages, primarily in Connecticut. In terms of customer outages, this storm was one of the worst in CL&P’s history. PURA has opened an investigation into CL&P's response to Tropical Storm Isaias. PURA will also investigate the prudence of costs incurred by CL&P to restore service as part of its response. CL&P is fully participating in PURA’s investigations and believes that these storm restoration costs were prudently incurred and meet the criteria for cost recovery. As a result, management does not expect the storm costs to have a material impact on the results of operations of Eversource or CL&P.

Based on current estimates, the storm resulted in deferred storm restoration costs on our balance sheets of approximately $228 million at CL&P and $245 million at Eversource as of December 31, 2020. The estimated cost of restoration will change as additional cost information becomes available, final storm costs are deferred or capitalized, and post-storm restoration work is completed. The majority of incremental storm costs relate to third-party vendors that are external field crews needed to restore power and address municipal priorities. CL&P’s current estimate of total storm costs includes its projection of the cost of such vendors, but that estimate will change as CL&P receives and examines all storm related invoices.

Connecticut:

CL&P Storm Investigation: On August 7, 2020, PURA issued a notice that it had opened a docket to investigate the preparation for and response to Tropical Storm Isaias by Connecticut utilities, including CL&P. Hearings were completed in January 2021 and a final decision is currently expected on April 28, 2021. If the April 28, 2021 final decision concludes that CL&P failed to comply with applicable storm performance standards, then a separate proceeding will be initiated on May 7, 2021 to examine if and what amount of any civil penalty could potentially be imposed on CL&P, with a final decision currently anticipated on July 14, 2021.

CL&P Rate Suspension: On July 31, 2020, PURA temporarily suspended its June 26, 2020 approval of certain delivery rate components effective July 1, 2020, and ordered CL&P to restore rates to those in effect as of June 30, 2020 in order to allow PURA time to reexamine the rates to ensure that CL&P is not over-collecting revenues in the short-term. Rates were adjusted effective August 1, 2020. PURA indicated that this was due to the convergence of a number of recent events, including the COVID-19 crisis and its corresponding effect on customer energy usage, as well as the warmer than normal weather in July. On December 2, 2020, PURA issued a final decision in which it adjusted the timing of the annual rate adjustments for the Revenue Decoupling Mechanism Charge, the Transmission Adjustment Clause charge, the Non-Bypassable Federally Mandated Congestion Charge, and the Electric System Improvements Tracker so that these rates take effect on May 1st of each year, as opposed to the current process of adjusting rates each January 1 and July 1. The final decision also modified the calculation of carrying charges and shifted the timing of recovery to rely on more actual versus forecasted information, among other changes.

The temporary suspension of rates has resulted in a current period under-recovery of costs, which results in an increase to our regulatory assets, with no impact on the statement of income other than carrying charges, and a delay in the collection of our costs.

Massachusetts:

NSTAR Electric Distribution Rates: As part of an inflation-based mechanism, NSTAR Electric submitted its third annual Performance Based

Rate Adjustment filing on September 15, 2020 and the DPU approved a $29.9 million increase to base distribution rates on December 30, 2020 for effect on January 1, 2021.

NSTAR Gas Rate Case: On October 30, 2020, the DPU approved a base distribution rate increase of $23.0 million effective November 1, 2020, compared to the original request of $38.0 million. NSTAR Gas' 2019 plant additions are allowed recovery beginning on November 1, 2021. Thus, the reduced revenue requirement reflects the removal of this recovery, among other adjustments. The DPU also approved NSTAR Gas' proposal to continue its ongoing Gas System Enhancement Program (GSEP), the inclusion of GSEP investments since 2015 into base rates, and the implementation of a 10-year performance-based ratemaking plan, which includes an inflation-based adjustment mechanism to annual base distribution rates. The decision allows an authorized regulatory ROE of 9.9 percent on a capital structure including 54.77 percent equity. The decision also approves a geothermal pilot program. The impact of the rate case decision resulted in a pre-tax charge to earnings in 2020 of $2.7 million at NSTAR Gas, primarily due to certain plant-related disallowances.

Sale of Water System: On July 31, 2020, we sold our water system and treatment plant that supplies water to the towns of Hingham, Hull and North Cohasset to the town of Hingham, Massachusetts. Net property, plant and equipment of $63.9 million and goodwill of $23.6 million were included in determining the gain on sale. Proceeds from the sale were $110.5 million, with a pre-tax gain of $16.0 million (after-tax gain of $3.5 million) recognized within Operations and Maintenance Expense on the statement of income for the year ended December 31, 2020. The assets and liabilities associated with the sale of the business were previously reflected in the Water Distribution segment and reporting unit.

New Hampshire:

PSNH Distribution Rates: On June 27, 2019, the NHPUC approved a settlement agreement that was reached by PSNH, the NHPUC Staff, the Office of the Consumer Advocate, and another settling party, to implement a temporary annual base distribution rate increase of $28.3 million. Although new rates were implemented on August 1, 2019 to customers, the provisions of the temporary base distribution rate increase were effective July 1, 2019. The settlement agreement also permitted PSNH to recover approximately $68.5 million in unrecovered storm costs over a five-year period beginning August 1, 2019, with debt carrying charges, which is included in the temporary rate increase.

On May 28, 2019, PSNH filed an application with the NHPUC for a permanent increase in base distribution rates of approximately $70 million, effective July 1, 2020, which included the temporary rate increase request. Temporary rates remained in effect with a reconciliation of permanent rates retroactive to July 1, 2019 once permanent rates were set.

On December 15, 2020, the NHPUC approved an October 9, 2020 settlement agreement on permanent rates between PSNH and all parties to the proceeding. The NHPUC approved a permanent rate increase of $45.0 million effective January 1, 2021, inclusive of the temporary rate increase referenced above. PSNH was also permitted three step increases, effective January 1, 2021, August 1, 2021, and August 1, 2022, to reflect plant additions in calendar years 2019, 2020 and 2021, respectively. On December 23, 2020, the NHPUC approved the first step adjustment for 2019 plant in service to recover a revenue requirement of $10.6 million, subject to reconciliation after completion of an audit, effective January 1, 2021. The settlement agreement also established an authorized regulatory ROE of 9.3 percent with a 54.4 percent common equity ratio in PSNH’s capital structure and provided for a new tracker to recover regulatory assessments, vegetation management costs, property tax costs, and lost distribution revenue attributable to net metering. In addition, base distribution rates were adjusted to reflect the refund of EDIT from the Tax Cuts and Jobs Act of 2017.

The settlement agreement allowed for the effect of the permanent rate increase to be extended back to the temporary rate period. In lieu of a customer rate increase for this recoupment of revenue, the NHPUC directed a portion of the total EDIT regulatory liability to offset bill impacts to customers. The impact of the settlement agreement resulted in an after-tax benefit to earnings in 2020 of $11.0 million at Eversource ($7.2 million at PSNH), due primarily to the reconciliation of permanent rates back to the temporary rate period resulting in a reduction of the EDIT regulatory liability, which reduced Income Tax Expense on the statement of income, and the allowed recovery of previously expensed costs. The earnings impact was partially offset by the negative impact from the over-refunding of the change in the 2018 federal corporate income tax rate as a result of the Tax Cuts and Jobs Act of 2017 that was reflected in temporary rates, which reduced Operating Revenues on the statement of income.

PSNH Generation Asset Divestiture-Related Costs: On May 15, 2020, the NHPUC Audit Staff issued a final report on the audit of PSNH’s generation asset divestiture-related costs and resulting securitized and stranded costs. The findings in the audit report as well as other aspects of the divestiture process were further investigated by NHPUC Staff through the discovery phase, which was completed in July 2020. On September 30, 2020, PSNH filed a settlement agreement on the generation asset divestiture-related costs with the NHPUC Audit Staff. The settlement agreement resolved all issues with respect to PSNH’s divestiture of its generating assets and the recovery of $12.0 million of divestiture-related costs incurred above the $635.7 million amount previously securitized. On December 17, 2020, the NHPUC approved the additional $12.0 million proposed in the settlement agreement to be recovered over a one-year period through the SCRC rate beginning February 1, 2021.

Legislative and Policy Matters

Federal: On March 27, 2020, President Trump signed the $2.2 trillion bipartisan Coronavirus Aid, Relief, and Economic Security (CARES) Act. Among other provisions, the CARES Act provides for loans and other benefits to small and large businesses, expanded unemployment insurance, direct payments to those with wages middle-income and below, new appropriations funding for health care and other priorities, and tax changes like deferrals of employer payroll tax liabilities coupled with an employee retention tax credit and rollbacks of Tax Cuts and Jobs Act of 2017 limitations on net operating losses and certain business interest limitation. For the year ended December 31, 2020, we have recorded a tax liability of approximately $39 million related to the deferral of employer payroll tax liability provision. Fifty percent of the deferral of employer payroll tax liability must be paid by December 31, 2021 and the remaining amount by December 31, 2022. Other than the cash flow benefit described, the CARES Act did not have a material impact.

On December 27, 2020, President Trump signed into law H.R. 133, the “Consolidated Appropriations Act, 2021.” The House of Representatives and Senate previously passed the bill with overwhelming support. The legislation includes tax extenders as part of Division EE, the “Taxpayer Certainty and Disaster Tax Relief Act of 2020.” The provisions within the law include the extension of the Investment Tax Credit (ITC) for solar at 26 percent for facilities the construction of which begins through the end of 2022, at 22 percent for facilities the construction of which begins in 2023, and postponement of the date after which solar facilities placed in service receive only a 10 percent ITC to December 31, 2025, the extension of the ITC at 30 percent (with no phase-down) to offshore wind if construction begins by December 31, 2025 (qualifying offshore wind includes facilities located in the inland navigable waters or in the coastal waters of the U.S.), and the extension and expansion of the CARES Act employee retention tax credit for the period from January 1, 2021 through June 30, 2021, including increasing the credit rate from 50 percent to 70 percent of qualified wages, and increasing the per-employee creditable wages limit from $10,000 per year to $10,000 for each quarter. The tax credit provision impacts to Eversource are still being evaluated but are a significant positive development for the Company and provides the opportunity to generate additional tax credits in its renewable energy projects when the projects become operational.

Massachusetts: On January 28, 2021, the Massachusetts Legislature approved legislation which permits electric or natural gas distribution companies to assist Massachusetts municipalities in responding to the risks of climate change by owning solar facilities equal to up to 10 percent of the total installed solar generating capacity in Massachusetts as of July 31, 2020. Such facilities may be paired with energy storage where feasible to do so. This legislation is anticipated to allow each of Eversource’s Massachusetts operating companies to own up to approximately 280 MWs of solar generating facilities in addition to the 70 MWs previously constructed at NSTAR Electric.

Connecticut: On October 8, 2020, Connecticut enacted Public Act 20-5 (House Bill Number 7006), September Special Session (the Act). The Act, among other things, (1) requires PURA to open a proceeding by June 1, 2021 to begin to evaluate and eventually implement performance based regulation for electric distribution companies, and permits PURA to open a proceeding to consider such regulation for natural gas and water companies; (2) extends deadlines for PURA to issue final decisions in rate cases, change of control transactions and financing proceedings to be more consistent with timeframes in many other U.S. jurisdictions; (3) increases the maximum potential penalty for noncompliance with storm performance standards from 2.5 percent to 4 percent of annual electric distribution company revenue; and (4) directed PURA to open a proceeding by January 1, 2021 to evaluate and decide when bill credits should be paid to electric customers who lose service in future storms, including when waivers of these criteria will be granted to utilities. PURA opened a docket on December 29, 2020 to evaluate when bill credits would be paid for new storms after July 1, 2021. This law has no impact on storm response, costs or impacts prior to July 1, 2021.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies. Our critical accounting policies are discussed below. See the combined notes to our financial statements for further information concerning the accounting policies, estimates and assumptions used in the preparation of our financial statements.

Regulatory Accounting: Our regulated companies are subject to rate regulation that is based on cost recovery and meets the criteria for application of accounting guidance for rate-regulated operations, which considers the effect of regulation on the timing of the recognition of certain revenues and expenses. The regulated companies' financial statements reflect the effects of the rate-making process. The rates charged to the customers of our regulated companies are designed to collect each company's costs to provide service, plus a return on investment.

The application of accounting guidance for rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors, including, but not limited to, regulatory precedent. Regulatory liabilities represent either revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.

We use judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our financial statements. We believe it is probable that each of the regulated companies will recover its respective investments in long-lived assets and the regulatory assets that have been recorded. If we determine that we can no longer apply the accounting guidance applicable to rate-regulated enterprises, or that we cannot conclude it is probable that costs will be recovered from customers in future rates, the applicable costs would be charged to net income in the period in which the determination is made.

Pension, SERP and PBOP: We sponsor Pension, SERP and PBOP Plans to provide retirement benefits to our employees. For each of these plans, several significant assumptions are used to determine the projected benefit obligation, funded status and net periodic benefit cost. These assumptions include the expected long-term rate of return on plan assets, discount rate, compensation/progression rate and mortality and retirement assumptions. We evaluate these assumptions at least annually and adjust them as necessary. Changes in these assumptions could have a material impact on our financial position, results of operations or cash flows.

Expected Long-Term Rate of Return on Plan Assets: In developing the expected long-term rate of return, we consider historical and expected returns, as well as input from our consultants. Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding expected rates of return for each asset class. We routinely review the actual asset allocations and periodically rebalance the investments to the targeted asset allocations. For the year ended December 31, 2020, our expected long-term rate-of-return assumption used to determine our pension and PBOP expense was 8.25 percent for the Eversource Service plans and 7 percent for the Aquarion plans. For the forecasted 2021 pension and PBOP expense, an expected long-term rate of return of 8.25 percent for the Eversource Service plans and 7 percent for the Aquarion plans will be used reflecting our target asset allocations.

Discount Rate: Payment obligations related to the Pension, SERP and PBOP Plans are discounted at interest rates applicable to the expected timing of each plan's cash flows. The discount rate that was utilized in determining the pension, SERP and PBOP obligations was based on a yield-curve approach. This approach utilizes a population of bonds with an average rating of AA based on bond ratings by Moody's, S&P and Fitch, and uses bonds with above median yields within that population. As of December 31, 2020, the discount rates used to determine the funded status were within a range of 2.4 percent to 2.7 percent for the Pension and SERP Plans, and within a range of 2.5 percent to 2.6 percent for the PBOP Plans. As of December 31, 2019, the discount rates used were within a range of 3.0 percent to 3.4 percent for the Pension and SERP Plans, and within a range of 3.2 percent to 3.3 percent for the PBOP Plans. The decrease in the discount rates used to calculate the funded status resulted in an increase to the Pension and PBOP Plans' liability of $603.0 million and $68.3 million, respectively, as of December 31, 2020.

The Company uses the spot rate methodology for the service and interest cost components of Pension, SERP and PBOP expense because it provides a relatively precise measurement by matching projected cash flows to the corresponding spot rates on the yield curve. The discount rates used to estimate the 2020 expense were within a range of 2.6 percent to 3.5 percent for the Pension and SERP Plans, and within a range of 2.7 percent to 3.6 percent for the PBOP Plans.

Mortality Assumptions: Assumptions as to mortality of the participants in our Pension, SERP and PBOP Plans are a key estimate in measuring the expected payments a participant may receive over their lifetime and the corresponding plan liability we need to record. In 2020, a revised scale for the mortality table was released, and we utilized it in our measurements.

Compensation/Progression Rate: This assumption reflects the expected long-term salary growth rate, including consideration of the levels of increases built into collective bargaining agreements, and impacts the estimated benefits that Pension and SERP Plan participants receive in the future. As of December 31, 2020 and 2019, the compensation/progression rates used to determine the funded status were within a range of 3.5 percent to 4 percent.

Health Care Cost: The Eversource Service PBOP Plan is not subject to health care cost trends. As of December 31, 2020, for the Aquarion PBOP Plan, the health care trend rate for pre-65 retirees is 6.3 percent, with an ultimate rate of 5 percent in 2023, and for post-65 retirees, the health care trend rate and ultimate rate is 3.5 percent.

Actuarial Determination of Expense: Pension, SERP and PBOP expense is determined by our actuaries and consists of service cost and prior service cost, interest cost based on the discounting of the obligations, and amortization of actuarial gains and losses, offset by the expected return on plan assets. Actuarial gains and losses represent the amortization of differences between assumptions and actual information or updated assumptions. Pre-tax net periodic benefit expense for the Pension and SERP Plans was $56.9 million, $63.7 million and $39.6 million for the years ended December 31, 2020, 2019 and 2018, respectively. For the PBOP Plans, there was net periodic PBOP income of $51.6 million, $41.5 million and $45.0 million for the years ended December 31, 2020, 2019 and 2018, respectively.

The expected return on plan assets is determined by applying the assumed long-term rate of return to the Pension and PBOP Plan asset balances. This calculated expected return is compared to the actual return or loss on plan assets at the end of each year to determine the investment gains or losses to be immediately reflected in unamortized actuarial gains and losses.

Forecasted Expenses and Expected Contributions: We estimate that expense in 2021 for the Pension and SERP Plans will be approximately $28 million and income in 2021 for the PBOP Plans will be approximately $58 million. Pension, SERP and PBOP expense for subsequent years will depend on future investment performance, changes in future discount rates and other assumptions, and various other factors related to the populations participating in the plans.

Our policy is to fund the Pension Plans annually in an amount at least equal to the amount that will satisfy all federal funding requirements. We contributed $109.6 million to the Pension Plans in 2020. We currently estimate contributing $130.0 million to the Pension Plans in 2021.

It is our policy to fund the PBOP Plans annually through tax deductible contributions to external trusts. We contributed $1.9 million to the PBOP Plans in 2020. We currently estimate contributing $2.8 million to the PBOP Plans in 2021.

Sensitivity Analysis: The following represents the hypothetical increase to the Pension Plans' (excluding the SERP Plans) reported annual cost and a decrease to the PBOP Plans' reported annual income as a result of a change in the following assumptions by 50 basis points:


(Millions of Dollars)	Increase in Pension Plan Cost				Decrease in PBOP Plan Income
Assumption Change	As of December 31,				As of December 31,
Eversource	2020		2019		2020		2019
Lower expected long-term rate of return	$	25.0	$	22.9	$	4.5	$	4.1
Lower discount rate	25.4		21.7		1.7		1.7
Higher compensation rate	8.8		8.7		N/A		N/A

Goodwill: We recorded goodwill on our balance sheet associated with previous mergers and acquisitions, which totaled $4.45 billion as of December 31, 2020. We have identified our reporting units for purposes of allocating and testing goodwill as Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution. Electric Distribution and Electric Transmission reporting units include carrying values for the respective components of CL&P, NSTAR Electric and PSNH. The Natural Gas Distribution reporting unit includes the carrying values of NSTAR Gas, Yankee Gas and EGMA. We recorded $42 million of goodwill arising from the acquisition of CMA on October 9, 2020. The Water Distribution reporting unit includes the Aquarion water utility businesses. As of December 31, 2020, goodwill was allocated to the reporting units as follows: $2.54 billion to Electric Distribution, $577 million to Electric Transmission, $441 million to Natural Gas Distribution and $884 million to Water Distribution.

We are required to test goodwill balances for impairment at least annually by considering the fair values of the reporting units, which requires us to use estimates and judgments. We have selected October 1st of each year as the annual goodwill impairment test date. Goodwill impairment is deemed to exist if the carrying amount of a reporting unit exceeds its estimated fair value. If goodwill were deemed to be impaired, it would be written down in the current period to the extent of the impairment.

We performed an impairment test of goodwill as of October 1, 2020 for the Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution reporting units. This evaluation required the consideration of several factors that impact the fair value of the reporting units, including conditions and assumptions that affect the future cash flows of the reporting units. Key considerations include discount rates, utility sector market performance and merger transaction multiples, and internal estimates of future cash flows and net income.

The 2020 goodwill impairment assessment resulted in a conclusion that goodwill is not impaired and no reporting unit is at risk of a goodwill impairment. The fair value of the reporting units was substantially in excess of carrying value.

Long-Lived Assets: Impairment evaluations of long-lived assets, including property, plant and equipment and other assets, involve a significant degree of estimation and judgment, including identifying circumstances that indicate an impairment may exist. Impairment analysis is required when events or changes in circumstances indicate that the carrying value of a long-lived asset may not be recoverable. Indicators of potential impairment include a deteriorating business climate, unfavorable regulatory action, decline in value that is other than temporary in nature, plans to dispose of a long-lived asset significantly before the end of its useful life, and accumulation of costs that are in excess of amounts allowed for recovery. The review of long-lived assets for impairment utilizes significant assumptions about operating strategies and external developments, including assessment of current and projected market conditions that can impact future cash flows.

Impairment of Northern Pass Transmission: Northern Pass was Eversource's planned 1,090 MW HVDC transmission line that would have interconnected from the Québec-New Hampshire border to Franklin, New Hampshire and an associated alternating current radial transmission line between Franklin and Deerfield, New Hampshire. As a result of a final decision received on July 19, 2019 from the New Hampshire Supreme Court, whereby the court denied Northern Pass’ appeal and affirmed the NHSEC’s denial of Northern Pass’ siting application on NPT, Eversource concluded that construction of NPT was no longer probable and that there was no constructive path forward for the project. In 2019, Eversource terminated the project and permanently abandoned any further development.

Based on the conclusion that the construction of Northern Pass was no longer probable, Eversource recorded an impairment charge in 2019 for all of the project costs associated with Northern Pass, which were primarily engineering design, siting, permitting and legal costs, along with appropriate allowances for funds used during construction, and recognized a receivable for certain cost reimbursement agreements. Additionally, Eversource recorded an impairment charge associated with the land acquired to construct Northern Pass in order to recognize the land at its estimated fair value based on assessed values and transaction costs. In total, this resulted in a pre-tax impairment charge of $239.6 million within Operating Income on the statement of income for the year ended December 31, 2019, and was reflected in the Electric Transmission segment. The after-tax impact of the impairment charge was $204.4 million, or $0.64 per share, after giving effect to the estimated fair value of the related land, reimbursement agreements, and the impact of expected income tax benefits associated with the impairment charge. As a result of the decision to terminate the NPT project and permanently abandon any further development, Eversource does not expect any future cash expenditures associated with this project.

Equity Method Investments: Investments in affiliates where we have the ability to exercise significant influence, but not control, over an investee are initially recognized as an equity method investment at cost. Any differences between the cost of an investment and the amount of underlying equity in net assets of an investee are considered basis differences and are determined based upon the estimated fair values of the investee's identifiable assets and liabilities. For our offshore wind equity method investment, basis differences are related to intangible assets for PPAs that will be amortized over the term of the PPAs, and equity method goodwill that are not amortized. Capitalized interest associated with our offshore wind equity method investment is included in the investment balance.

Equity method investments are assessed for impairment when conditions exist that indicate that the fair value of the investment is less than book value. If the decline in value is considered to be other-than-temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment. Impairment evaluations involve a significant degree of judgment and estimation, including identifying circumstances that indicate an impairment may exist and developing an estimate of undiscounted future cash flows.

In 2020, Eversource recorded an other-than-temporary impairment of $2.8 million within Other Income, Net on the statement of income, related to a write-off of an investment within a renewable energy fund.

In 2018, Eversource recorded an other-than-temporary impairment of $32.9 million within Other Income, Net on our statement of income, related to Access Northeast, an equity method investment. Eversource identified a September 2018 non-Eversource natural gas series of explosions in eastern Massachusetts, compounded by an adverse legislative environment, as negative evidence that indicated potential impairment of our investment in Access Northeast. In 2018, management determined that the future cash flows of the Access Northeast project were uncertain and could no longer be reasonably estimated and that the book value of our equity method investment was not recoverable. On April 1, 2019, pursuant to a provision in the partnership agreement jointly entered into by Eversource, Enbridge, Inc. and National Grid plc, through Algonquin Gas Transmission, LLC, the Access Northeast project was terminated.

Income Taxes: Income tax expense is estimated for each of the jurisdictions in which we operate and is recorded each quarter using an estimated annualized effective tax rate. This process to record income tax expense involves estimating current and deferred income tax expense or benefit and the impact of temporary differences resulting from differing treatment of items for financial reporting and income tax return reporting purposes. Such differences are the result of timing of the deduction for expenses, as well as any impact of permanent differences, non-tax deductible expenses, or other items that directly impact income tax expense as a result of regulatory activity (flow-through items). The temporary differences and flow-through items result in deferred tax assets and liabilities that are included in the balance sheets.

We also account for uncertainty in income taxes, which applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on our balance sheets. The determination of whether a tax position meets the recognition threshold under applicable accounting guidance is based on facts and circumstances available to us.

Pursuant to the Tax Cuts and Jobs Act of 2017, Eversource had remeasured its existing deferred federal income tax balances to reflect the decrease in the U.S. federal corporate income tax rate from 35 percent to 21 percent. The remeasurement resulted in provisional regulated excess accumulated deferred income tax (excess ADIT or EDIT) liabilities that will benefit our customers in future periods. As of December 31, 2020, these EDIT liabilities were estimated to be approximately $2.78 billion and were included in regulatory liabilities on the balance sheet. Eversource's regulated companies are in the process of, or will be, refunding the EDIT liabilities to customers based on orders issued by applicable state regulatory commissions. The refund of these regulatory liabilities to customers will generally be made over the same period as the remaining useful lives of the underlying assets that gave rise to the ADIT liabilities.

Accounting for Environmental Reserves: Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated. Increases to estimates of environmental liabilities could have an adverse impact on earnings. We estimate these liabilities based on findings through various phases of the assessment, considering the most likely action plan from a variety of available remediation options (ranging from no action required to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third party engineering and remediation contractors, and our prior experience in remediating contaminated sites. If a most likely action plan cannot yet be determined, we estimate the liability based on the low end of a range of possible action plans. A significant portion of our environmental sites and reserve amounts relate to former MGP sites that were operated several decades ago and manufactured natural gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment, for which we may have potential liability. Estimates are based on the expected remediation plan. Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site, the extent of our responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates.

Fair Value Measurements: We follow fair value measurement guidance that defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). We have applied this guidance to our Company's derivative contracts that are not elected or designated as "normal purchases or normal sales" (normal), to marketable securities held in trusts, and to our investments in our Pension and PBOP Plans. Fair value measurements are also incorporated into the accounting for goodwill, long-lived assets, equity method investments, and AROs, and in the valuation of the acquisition of CMA in 2020. The fair value measurement guidance was also applied in estimating the fair value of preferred stock, long-term debt and RRBs.

Changes in fair value of our derivative contracts are recorded as Regulatory Assets or Liabilities, as we recover the costs of these contracts in rates charged to customers. These valuations are sensitive to the prices of energy and energy-related products in future years for which markets have not yet developed and assumptions are made.

We use quoted market prices when available to determine the fair value of financial instruments. When quoted prices in active markets for the same or similar instruments are not available, we value derivative contracts using models that incorporate both observable and unobservable inputs. Significant unobservable inputs utilized in the models include energy and energy-related product prices for future years for long-dated derivative contracts and market volatilities. Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk-adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.

Other Matters

Accounting Standards: For information regarding new accounting standards, see Note 1C, "Summary of Significant Accounting Policies - Accounting Standards," to the financial statements.

Contractual Obligations and Commercial Commitments: Information regarding our contractual obligations and commercial commitments as of December 31, 2020, is summarized annually through 2025 and thereafter as follows:


Eversource
(Millions of Dollars)	2021		2022		2023		2024		2025		Thereafter		Total
Long-term debt maturities (a)	$	1,022.2	$	1,175.2	$	1,658.2	$	1,049.9	$	1,400.0	$	9,807.9	$	16,113.4
Rate reduction bond maturities	43.2		43.2		43.2		43.2		43.2		324.1		540.1
Estimated interest payments on existing debt (b)	542.8		510.6		478.4		437.3		391.0		4,541.4		6,901.5
Operating leases (c)	11.4		9.0		6.4		4.5		3.4		36.2		70.9
Finance leases(c)	7.2		5.7		4.9		4.8		4.7		60.7		88.0
Funding of pension obligations (d) (e)	130.0		—		—		—		—		—		130.0
Funding of PBOP obligations (d) (e)	2.8		—		—		—		—		—		2.8
Estimated future annual long-term contractual costs (f)	1,328.8		1,218.6		1,096.1		1,052.3		1,023.0		5,451.8		11,170.6
Total (g)	$	3,088.4	$	2,962.3	$	3,287.2	$	2,592.0	$	2,865.3	$	20,222.1	$	35,017.3


CL&P
(Millions of Dollars)	2021		2022		2023		2024		2025		Thereafter		Total
Long-term debt maturities (a)	$	—	$	—	$	400.0	$	139.8	$	400.0	$	2,975.5	$	3,915.3
Estimated interest payments on existing debt (b)	156.2		156.2		151.2		146.2		135.2		1,884.0		2,629.0
Operating leases (c)	0.2		0.1		—		—		—		—		0.3
Finance leases (c)	1.5		—		—		—		—		—		1.5
Funding of pension obligations (d) (e)	78.9		—		—		—		—		—		78.9
Estimated future annual long-term contractual costs (f)	588.3		661.5		684.6		674.9		647.7		2,755.8		6,012.8
Total (g)	$	825.1	$	817.8	$	1,235.8	$	960.9	$	1,182.9	$	7,615.3	$	12,637.8

(a) Long-term debt maturities exclude the CYAPC pre-1983 spent nuclear fuel obligation, net unamortized premiums, discounts and debt issuance costs, and other fair value adjustments.

(b) Estimated interest payments on fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement.

(d) Amounts are not included on our balance sheets.

(e) These amounts represent expected pension and PBOP contributions for 2021. Future contributions will vary depending on many factors, including the performance of existing plan assets, valuation of the plans' liabilities and long-term discount rates.

(f) Other than certain derivative contracts held by the regulated companies, these obligations are not included on our balance sheets.

(g) Does not include other long-term liabilities recorded on our balance sheet, such as environmental reserves, employee medical insurance, workers compensation and long-term disability insurance reserves, ARO liability reserves and other reserves, as we cannot make reasonable estimates of the timing of payments. Also, does not include amounts not included on our balance sheets for future funding of Eversource's equity method investments, as we cannot make reasonable estimates of the periods or the investment contributions.

For further information regarding our contractual obligations and commercial commitments, see Note 7, "Asset Retirement Obligations," Note 8, "Short-Term Debt," Note 9, "Long-Term Debt," Note 10, "Rate Reduction Bonds and Variable Interest Entities," Note 11A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pension," Note 13, "Commitments and Contingencies," and Note 14, "Leases," to the financial statements.

RESULTS OF OPERATIONS – EVERSOURCE ENERGY AND SUBSIDIARIES

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for Eversource for the years ended December 31, 2020 and 2019 included in this Annual Report on Form 10-K:


	For the Years Ended December 31,
(Millions of Dollars)	2020		2019		Increase/(Decrease)
Operating Revenues	$	8,904.4	$	8,526.5	$	377.9
Operating Expenses:
Purchased Power, Fuel and Transmission	2,987.8		3,040.2		(52.4)
Operations and Maintenance	1,480.3		1,363.1		117.2
Depreciation	981.4		885.3		96.1
Amortization	177.7		195.4		(17.7)
Energy Efficiency Programs	535.8		501.4		34.4
Taxes Other Than Income Taxes	752.7		711.0		41.7
Impairment of Northern Pass Transmission	—		239.6		(239.6)
Total Operating Expenses	6,915.7		6,936.0		(20.3)
Operating Income	1,988.7		1,590.5		398.2
Interest Expense	538.4		533.2		5.2
Other Income, Net	108.6		132.8		(24.2)
Income Before Income Tax Expense	1,558.9		1,190.1		368.8
Income Tax Expense	346.2		273.5		72.7
Net Income	1,212.7		916.6		296.1
Net Income Attributable to Noncontrolling Interests	7.5		7.5		—
Net Income Attributable to Common Shareholders	$	1,205.2	$	909.1	$	296.1

Operating Revenues

Sales Volumes: A summary of our retail electric GWh sales volumes, our firm natural gas MMcf sales volumes, and our water MG sales volumes, and percentage changes, is as follows:


	Electric					Firm Natural Gas					Water
	Sales Volumes (GWh)		Percentage Decrease			Sales Volumes (MMcf)			Percentage Increase		Sales Volumes (MG)		Percentage (Decrease)/Increase
	2020	2019			2020		2019		2020		2019
Traditional	7,675	7,685	(0.1)	%		—		—	—	%	2,011	2,161	(6.9)	%
Decoupled and Special Contracts (1)(2)	42,531	43,934	(3.2)	%		112,756		107,806	4.6	%	23,122	21,370	8.2	%
Total Sales Volumes	50,206	51,619	(2.7)	%		112,756		107,806	4.6	%	25,133	23,531	6.8	%

(1) Special contracts are unique to Yankee Gas natural gas distribution customers who take service under such an arrangement and generally specify the amount of distribution revenue to be paid to Yankee Gas regardless of the customers' usage.

(2) The 2020 firm natural gas sales volumes include the addition of EGMA beginning October 9, 2020.

Weather, fluctuations in energy supply costs, conservation measures (including utility-sponsored energy efficiency programs), and economic conditions affect customer energy usage and water consumption. Industrial sales volumes are less sensitive to temperature variations than residential and commercial sales volumes. In our service territories, weather impacts both electric and water sales volumes during the summer and both electric and natural gas sales volumes during the winter; however, natural gas sales volumes are more sensitive to temperature variations than electric sales volumes. Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur.

Fluctuations in retail electric sales volumes at PSNH impact earnings ("Traditional" in the table above). For CL&P, NSTAR Electric, NSTAR Gas, EGMA, Yankee Gas, and our Connecticut water distribution business, fluctuations in retail sales volumes do not materially impact earnings due to their respective regulatory commission-approved distribution revenue decoupling mechanisms ("Decoupled" in the table above). These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized.

Operating Revenues: Operating Revenues by segment increased in 2020, as compared to 2019, as follows:


(Millions of Dollars)	Increase/(Decrease)
Electric Distribution	$	155.8
Natural Gas Distribution	146.5
Electric Transmission	147.1
Water Distribution	0.8
Other	207.4
Eliminations	(279.7)
Total Operating Revenues	$	377.9

Electric and Natural Gas Distribution Revenues:

Base Distribution Revenues:

Base electric distribution revenues increased $97.5 million in 2020, as compared to 2019, due primarily to the impact of CL&P's base distribution rate increases effective May 1, 2020 and May 1, 2019, which include recovery of storm costs and certain other items that do not impact earnings, the NSTAR Electric base distribution rate increase effective January 1, 2020, and the impact of the PSNH temporary base distribution rate increase effective July 1, 2019, which includes recovery of storm costs and certain other items that do not impact earnings.
The increase in total electric distribution revenues was partially offset by the impact of the December 2020 PSNH settlement agreement driven by the negative impact from the over-refunding of the change in the 2018 federal corporate income tax rate as a result of the Tax Cuts and Jobs Act of 2017 that was reflected in temporary rates.
Base natural gas distribution revenues increased $34.3 million in 2020, as compared to 2019, due primarily to base distribution rate increases at Yankee Gas effective January 1, 2020 and at NSTAR Gas effective November 1, 2020.

Tracked Distribution Revenues: Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. However, tracked revenues do include certain incentives earned, return on rate base and on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings. Costs recovered through cost tracking mechanisms include, among others, energy supply and natural gas supply procurement and other energy-related costs, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), and additionally for the Massachusetts utilities, pension and PBOP benefits and net metering for distributed generation. Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market and the sale of RECs to various counterparties.

Tracked distribution revenues increased/(decreased) in 2020, as compared to 2019, due primarily to the following:


(Millions of Dollars)	Electric Distribution		Natural Gas Distribution
Retail Tariff Tracked Revenues:
Energy supply procurement	$	(211.8)	$	(49.3)
CL&P FMCC	120.5		N/A
Other distribution tracking mechanisms	36.3		30.9
Wholesale Market Sales Revenue	111.6		(19.5)

The decrease in energy supply procurement within electric distribution was driven primarily by lower average prices, partially offset by higher average supply-related sales volumes in 2020, as compared to 2019. The increase in the CL&P FMCC regulatory tracking mechanism revenues and the increase in wholesale market sales revenue within electric distribution was due primarily to the new Millstone PPA entered into by CL&P in 2019, as required by regulation. Beginning in the fourth quarter of 2019, CL&P sells the energy purchased from Millstone Nuclear Power Station (Millstone) into the wholesale market and uses the proceeds from the energy sales to offset a portion of the contract costs. The net costs under the contract are recovered from customers in the FMCC rate.

The addition of EGMA increased total operating revenues at the natural gas distribution segment by $154.8 million.

Electric Transmission Revenues: Electric transmission revenues increased $147.1 million in 2020, as compared to 2019, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure and a higher benefit from the annual billing and cost reconciliation filing with FERC.

Other Revenues and Eliminations: Other revenues primarily include the revenues of Eversource's service company, most of which are eliminated in consolidation. Eliminations are also primarily related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business.

Purchased Power, Fuel and Transmission expense includes costs associated with purchasing electricity and natural gas on behalf of our customers. These electric and natural gas supply costs are recovered from customers in rates through commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power, Fuel and Transmission expense decreased in 2020, as compared to 2019, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Purchased Power Costs	$	48.1
Natural Gas Costs	(7.9)
Transmission Costs	(6.3)
Eliminations	(86.3)
Total Purchased Power, Fuel and Transmission	$	(52.4)

The increase in purchased power expense at the electric distribution business in 2020 as compared to 2019, was driven primarily by the impact of energy purchases from the new Millstone PPA and higher average supply-related sales volumes, partially offset by lower average prices. The decrease in natural gas supply costs at our natural gas distribution business was due primarily to lower average prices and lower average sales volumes, partially offset by the addition of EGMA natural gas supply costs as a result of the CMA asset acquisition of $58.8 million.

The decrease in transmission costs in 2020, as compared to 2019, was primarily the result of a decrease in the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. This was partially offset by an increase in Local Network Service charges, which reflect the cost of transmission service provided by Eversource over our local transmission network, and an increase in costs billed by ISO-NE that support regional grid investments.

Operations and Maintenance expense includes tracked costs and costs that are part of base electric, natural gas and water distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense increased in 2020, as compared to 2019, due primarily to the following:


(Millions of Dollars)	Increase/(Decrease)
Base Electric Distribution (Non-Tracked Costs):
Storm restoration costs	$	29.8
Shared corporate costs (including computer software depreciation at Eversource Service)	22.6
COVID-19 Costs	9.5
Employee-related expenses, including labor and benefits	(12.9)
Operations-related expenses, including vegetation management, vehicles, and outside services	(5.7)
Other non-tracked operations and maintenance	(8.3)
Total Base Electric Distribution (Non-Tracked Costs)	35.0
Tracked Costs (Electric Distribution and Electric Transmission) - Increase due to higher transmission expenses of $26.3 million and increase of $24.0 million due to higher pension tracking mechanism deferral	55.8
Total Electric Distribution and Electric Transmission	90.8
Natural Gas Distribution:
Base (Non-Tracked) Costs, excluding EGMA - Increase due primarily to higher shared corporate costs of $10.1 million and $6.3 million for COVID-19 costs, partially offset by lower employee-related expenses of $7.5 million	13.3
Tracked Costs, excluding EGMA	4.2
EGMA Operations and Maintenance - due to CMA asset acquisition	40.1
Total Natural Gas Distribution	57.6
Water Distribution:
Gain on sale of Hingham water system	(16.0)
Other	0.9
Total Water Distribution	(15.1)
Parent and Other Companies and Eliminations:
Eversource Parent and Other Companies - other operations and maintenance	83.9
Acquisition costs related to CMA	42.1
Eliminations	(142.1)
Total Operations and Maintenance	$	117.2

Depreciation expense increased in 2020, as compared to 2019, due to higher utility plant in service balances, and due to the addition of EGMA utility plant balances as a result of the CMA asset acquisition of $10.9 million.

Amortization expense includes the deferrals of energy supply, energy-related costs and other costs that are included in certain regulatory commission-approved cost tracking mechanisms, and the amortization of certain costs as those costs are collected in rates. These deferrals adjust expense to match the corresponding revenues. Energy supply and energy-related costs are recovered from customers in rates and have no impact on earnings. Amortization decreased in 2020, as compared to 2019, due to the deferrals for the under recovery of energy purchases related to the Millstone PPA at CL&P and due to the deferral of other energy supply and energy-related costs.

Energy Efficiency Programs expense increased in 2020, as compared to 2019, due primarily to the deferral adjustment at CL&P, PSNH and NSTAR Gas, which reflects the actual costs of energy efficiency programs compared to the amounts billed to customers and the timing of the recovery of energy efficiency costs. The increase was also due to the addition of EGMA energy efficiency program costs as a result of the CMA asset acquisition of $14.4 million. The increase was partially offset by a decrease in spending on certain large energy efficiency projects in 2020, compared to 2019 at NSTAR Electric, due to timing. The costs for the majority of the state energy policy initiatives and expanded energy efficiency programs are recovered from customers in rates and have no impact on earnings.

Taxes Other Than Income Taxes expense increased in 2020, as compared to 2019, due primarily to an increase in property taxes as a result of higher utility plant balances and higher Connecticut gross earnings taxes at CL&P, and due to the addition of EGMA property taxes as a result of the CMA asset acquisition of $9.7 million. The increase was partially offset by a decrease of $21.4 million related to CL&P's remittance of energy efficiency funds to the State of Connecticut. Energy efficiency funds collected from customers after July 1, 2019 are no longer subject to remittance to the State of Connecticut. The increase was also partially offset by a decrease in property tax at NSTAR Gas relating to the resolution of disputed property taxes for prior years.

Impairment of Northern Pass Transmission reflects an impairment charge of $239.6 million that was recorded in the second quarter of 2019 as a result of the July 19, 2019 New Hampshire Supreme Court decision. The after-tax impact of this impairment charge was $204.4 million.

Interest Expense increased in 2020, as compared to 2019, due primarily to an increase in interest on long-term debt as a result of new debt issuances ($27.3 million) and higher amortization of debt discounts and premiums, net ($4.6 million), partially offset by a decrease in interest on notes payable ($16.9 million), a decrease in interest expense at NSTAR Gas relating to the resolution of disputed property taxes for prior years ($5.7 million), and an increase in capitalized AFUDC related to debt funds and other capitalized interest ($3.6 million).

Other Income, Net decreased in 2020, as compared to 2019, due primarily to a decrease in equity in earnings related to Eversource's equity method investments ($28.0 million), the absence in 2020 of the recognition of the equity component of the carrying charges related to PSNH storm costs recorded in interest income in the first quarter of 2019 ($5.2 million) and lower AFUDC related to equity funds ($3.0 million), partially offset by an increase related to pension, SERP and PBOP non-service income components ($13.1 million).

Income Tax Expense increased in 2020, as compared to 2019, due primarily to higher pre-tax earnings ($23.5 million), higher state taxes ($12.6 million), by the absence in 2020 of the impairment of NPT ($35.2 million), by a decrease in tax planning benefits ($9.5 million), the sale of Hingham water system ($12.5 million), return to provision adjustments ($3.3 million), and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($4.1 million), partially offset by an increase in share-based payment excess tax benefits ($5.1 million), an increase in amortization of EDIT ($11.3 million), and a decrease in valuation allowance ($11.6 million).

RESULTS OF OPERATIONS –

THE CONNECTICUT LIGHT AND POWER COMPANY

NSTAR ELECTRIC COMPANY AND SUBSIDIARY

PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES

The following provides the amounts and variances in operating revenues and expense line items in the statements of income for CL&P, NSTAR Electric and PSNH for the years ended December 31, 2020 and 2019 included in this Annual Report on Form 10-K:


	For the Years Ended December 31,
	CL&P						NSTAR Electric						PSNH
(Millions of Dollars)	2020		2019		Increase		2020		2019		Increase/(Decrease)		2020		2019		Increase/(Decrease)
Operating Revenues	$	3,547.5	$	3,232.6	$	314.9	$	2,941.1	$	3,044.6	$	(103.5)	$	1,079.1	$	1,065.9	$	13.2
Operating Expenses:
Purchased Power and Transmission	1,369.2		1,188.2		181.0		879.2		1,064.3		(185.1)		364.1		398.4		(34.3)
Operations and Maintenance	572.9		549.2		23.7		534.1		468.4		65.7		219.3		211.0		8.3
Depreciation	320.7		301.2		19.5		319.5		296.5		23.0		100.4		93.7		6.7
Amortization of Regulatory Assets, Net	58.4		51.6		6.8		83.2		103.7		(20.5)		52.8		57.7		(4.9)
Energy Efficiency Programs	141.5		118.2		23.3		264.0		289.2		(25.2)		37.6		26.0		11.6
Taxes Other Than Income Taxes	344.4		342.5		1.9		206.8		195.6		11.2		81.6		62.6		19.0
Total Operating Expenses	2,807.1		2,550.9		256.2		2,286.8		2,417.7		(130.9)		855.8		849.4		6.4
Operating Income	740.4		681.7		58.7		654.3		626.9		27.4		223.3		216.5		6.8
Interest Expense	153.6		151.4		2.2		130.5		114.2		16.3		58.1		60.7		(2.6)
Other Income, Net	20.8		17.6		3.2		52.0		44.6		7.4		13.8		19.2		(5.4)
Income Before Income Tax Expense	607.6		547.9		59.7		575.8		557.3		18.5		179.0		175.0		4.0
Income Tax Expense	149.7		137.0		12.7		130.8		125.3		5.5		31.7		41.0		(9.3)
Net Income	$	457.9	$	410.9	$	47.0	$	445.0	$	432.0	$	13.0	$	147.3	$	134.0	$	13.3

Operating Revenues

Sales Volumes: A summary of our retail electric GWh sales volumes is as follows:


	For the Years Ended December 31,
	2020	2019	Decrease	Percent
CL&P	20,113	20,719	(606)	(2.9)	%
NSTAR Electric	22,418	23,215	(797)	(3.4)	%
PSNH	7,675	7,685	(10)	(0.1)	%

Fluctuations in retail electric sales volumes at PSNH impact earnings. For CL&P and NSTAR Electric, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission-approved distribution revenue decoupling mechanisms.

Operating Revenues: Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased $314.9 million at CL&P and $13.2 million at PSNH, and decreased $103.5 million at NSTAR Electric in 2020, as compared to 2019.

Base Distribution Revenues:

CL&P's distribution revenues increased $40.0 million due primarily to the impact of its base distribution rate increases effective May 1, 2020 and May 1, 2019, which include recovery of storm costs and certain other items that do not impact earnings.
NSTAR Electric's distribution revenues increased $32.6 million due primarily to the impact of its base distribution rate increase effective January 1, 2020.
PSNH's distribution revenues increased $24.9 million due primarily to the impact of its temporary base distribution rate increase effective July 1, 2019, which includes recovery of storm costs and certain other items that do not impact earnings.
The increase in PSNH’s total distribution revenues was partially offset by the impact of the December 2020 settlement agreement driven by the negative impact from the over-refunding of the change in the 2018 federal corporate income tax rate as a result of the Tax Cuts and Jobs Act of 2017 that was reflected in temporary rates.

Tracked Revenues: Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. However, tracked revenues do include certain incentives earned, return on rate base and on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings. Costs recovered through cost tracking mechanisms include, among others, energy supply procurement and other energy-related costs, retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), and additionally for NSTAR Electric, pension and PBOP benefits and net metering for distributed generation. Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market and the sale of RECs to various counterparties.

Tracked revenues increased/(decreased) in 2020, as compared to 2019, due primarily to the following:


(Millions of Dollars)	CL&P		NSTAR Electric		PSNH
Retail Tariff Tracked Revenues:
Energy supply procurement	$	(58.7)	$	(116.7)	$	(36.4)
CL&P FMCC	120.5		—		—
Other distribution tracking mechanisms	38.2		(17.6)		15.7
Wholesale Market Sales Revenue	125.0		(14.7)		1.3

The decrease in energy supply procurement at CL&P and PSNH reflects lower average prices, partially offset by higher average supply-related sales volumes in 2020, as compared to 2019. The decrease in energy supply procurement at NSTAR Electric reflects both lower average prices and lower average supply-related sales volumes for 2020, as compared to 2019.

The increase in the CL&P FMCC regulatory tracking mechanism revenues and the increase in wholesale market sales revenue was due primarily to the new Millstone PPA entered into by CL&P in 2019, as required by regulation. Beginning in the fourth quarter of 2019, CL&P sells the energy purchased from Millstone into the wholesale market and uses the proceeds from the energy sales to offset a portion of the contract costs. The net costs under the contract are recovered from customers in the FMCC rate.

Transmission Revenues: Transmission revenues increased $61.7 million at CL&P, $54.2 million at NSTAR Electric and $31.2 million at PSNH in 2020, as compared to 2019, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure and a higher benefit from the annual billing and cost reconciliation filing with FERC.

Eliminations: Eliminations are primarily related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business. The impact of eliminations decreased revenues by $13.1 million at CL&P, $44.0 million at NSTAR Electric and $20.7 million at PSNH in 2020, as compared to 2019.

Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf of CL&P, NSTAR Electric and PSNH's customers. These energy supply costs are recovered from customers in rates through commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). Purchased Power and Transmission expense increased/(decreased) in 2020, as compared to 2019, due primarily to the following:


(Millions of Dollars)	CL&P		NSTAR Electric		PSNH
Purchased Power Costs	$	233.0	$	(141.9)	$	(43.0)
Transmission Costs	(36.6)		0.8		29.5
Eliminations	(15.4)		(44.0)		(20.8)
Total Purchased Power and Transmission	$	181.0	$	(185.1)	$	(34.3)

Purchased Power Costs: Included in purchased power costs are the costs associated with providing electric generation service supply to all customers who have not migrated to third party suppliers and the cost of energy purchase contracts, as required by regulation.

The increase at CL&P was due primarily to the new Millstone PPA energy purchases and higher average supply-related sales volumes, partially offset by lower average prices.
The decrease at NSTAR Electric was due primarily to lower expense related to the procurement of energy supply resulting from lower average prices and lower average supply-related sales volumes.
The decrease at PSNH was due primarily to lower expense related to the procurement of energy supply resulting from lower average prices, partially offset by higher average supply-related sales volumes.

Transmission Costs: Included in transmission costs are charges that recover the cost of transporting electricity over high-voltage lines from generation facilities to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.

The decrease in transmission costs at CL&P was due primarily to a reduction to the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. This was partially offset by an increase in Local Network Service charges, which reflects the cost of transmission service provided by Eversource over our local transmission network, and an increase in costs billed by ISO-NE that support regional grid investments.
The increase in transmission costs at PSNH was primarily the result of an increase in Local Network Service charges, an increase in costs billed by ISO-NE that support regional grid investments, and an increase in the retail transmission cost deferral.

Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). Operations and Maintenance expense increased in 2020, as compared to 2019, due primarily to the following:


(Millions of Dollars)	CL&P		NSTAR Electric		PSNH
Base Electric Distribution (Non-Tracked Costs):
Storm restoration costs	$	11.4	$	9.0	$	9.4
Shared corporate costs (including computer software depreciation at Eversource Service)	8.3		11.6		2.7
COVID-19 Costs	3.9		3.8		1.8
Employee-related expenses, including labor and benefits	(5.1)		(6.0)		(1.8)
Operations-related expenses, including vegetation management, vehicles, and outside services	(5.2)		0.2		(0.7)
Other non-tracked operations and maintenance	(11.9)		6.7		1.9
Total Base Electric Distribution (Non-Tracked Costs)	1.4		25.3		13.3
Tracked Costs:
Transmission expenses	10.3		15.6		0.4
Other tracked operations and maintenance	12.0		24.8		(5.4)
Total Tracked Costs	22.3		40.4		(5.0)
Total Operations and Maintenance	$	23.7	$	65.7	$	8.3

Depreciation expense increased in 2020, as compared to 2019, for CL&P, NSTAR Electric and PSNH due to higher net plant in service balances.

Amortization of Regulatory Assets, Net expense includes the deferrals of energy supply, energy-related costs and other costs that are included in certain regulatory-approved cost tracking mechanisms, and the amortization of certain costs as those costs are collected in rates. These deferrals adjust expense to match the corresponding revenues. Energy supply and energy-related costs are recovered from customers in rates and have no impact on earnings. Amortization of Regulatory Assets, Net increased at CL&P and decreased at NSTAR Electric and PSNH in 2020, as compared to 2019, due primarily to the deferrals of energy supply and energy-related costs, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs.

Energy Efficiency Programs expense includes costs of various state energy policy initiatives and expanded energy efficiency programs that are recovered from customers in rates, most of which have no impact on earnings. Energy Efficiency Programs expense increased/decreased in 2020, as compared to 2019, due primarily to the following:

The increase at CL&P and PSNH was due to the deferral adjustment, which reflects actual costs of energy efficiency programs compared to the estimated amounts billed to customers, and the timing of the recovery of energy efficiency costs.
The decrease at NSTAR Electric was due to the timing of spending on certain large energy efficiency projects in 2020, as compared to 2019.

Taxes Other Than Income Taxes increased in 2020, as compared to 2019, due primarily to the following:

The increase at CL&P was related to higher property taxes as a result of a higher utility plant balance, higher gross earnings taxes, and the absence in 2020 of a use tax refund received in 2019, partially offset by a decrease of $21.4 million relating to the remittance of energy efficiency funds to the State of Connecticut. Energy efficiency funds collected from customers after July 1, 2019 are no longer subject to remittance to the State of Connecticut.
The increases at NSTAR Electric and PSNH were due to higher property taxes as a result of higher utility plant balances offset against some favorable property tax resolutions with a number of communities.

Interest Expense increased/decreased in 2020, as compared to 2019, due primarily to the following:

The increase at CL&P was due to higher interest on long-term debt ($6.6 million), partially offset by a decrease in interest expense on regulatory deferrals ($2.0 million), a decrease in interest on short-term notes payable ($1.2 million), and lower amortization of debt discounts and premiums, net ($0.9 million).
The increase at NSTAR Electric was due to higher interest on long-term debt ($12.9 million), an increase in interest expense on regulatory deferrals ($7.4 million), and a decrease in capitalized AFUDC related to debt funds ($1.4 million), partially offset by a decrease in interest on short-term notes payable ($3.6 million).
The decrease at PSNH was due to a decrease in interest expense on regulatory deferrals ($2.3 million) and a decrease in RRB interest expense ($1.4 million), partially offset by higher amortization of debt discounts and premiums, net ($0.8 million) and a decrease in capitalized AFUDC related to debt funds ($0.6 million).

Other Income, Net increased/decreased in 2020, as compared to 2019, due primarily to the following:

The increase at CL&P was due to an increase related to pension, SERP and PBOP non-service income components ($3.3 million), an increase in AFUDC related to equity funds ($0.6 million), and higher interest income ($0.5 million), partially offset by a decrease in investment income ($1.2 million).
The increase at NSTAR Electric was due primarily to an increase related to pension, SERP and PBOP non-service income components ($5.8 million) and an increase in AFUDC related to equity funds ($1.7 million).
The decrease at PSNH was due primarily to lower interest income ($8.1 million), which includes the absence in 2020 of the recognition of the equity component of the carrying charges related to storm costs recorded in interest income in 2019 ($5.2 million), partially offset by an increase related to pension, SERP and PBOP non-service income components ($2.1 million) and an increase in AFUDC related to equity funds ($0.8 million).

Income Tax Expense increased/decreased in 2020, as compared to 2019, due primarily to the following:

The increase at CL&P was due primarily to higher pre-tax earnings ($12.6 million), higher state taxes ($2.8 million), and return to provision adjustments ($1.2 million), partially offset by items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($0.5 million), an increase in share-based payment excess tax benefits ($1.8 million), and a decrease in a valuation allowance ($1.6 million).
The increase at NSTAR Electric was due primarily to higher pre-tax earnings ($3.9 million), higher state taxes ($0.7 million), a decrease in amortization of EDIT ($2.5 million), and return to provision adjustments ($0.5 million), partially offset by items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($0.3 million), and an increase in share-based payment excess tax benefits ($1.8 million).
The decrease at PSNH was due primarily to lower state taxes ($2.0 million), an increase in amortization of EDIT ($11.4 million), and an increase in share-based payment excess tax benefits ($0.6 million), partially offset by higher pre-tax earnings ($0.6 million), return to provision adjustments ($1.7 million), and items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($2.4 million).

EARNINGS SUMMARY

CL&P's earnings increased $47.0 million in 2020, as compared to 2019, due primarily to the base distribution rate increases effective May 1, 2020 and May 1, 2019, an increase in transmission earnings driven by a higher transmission rate base, and higher earnings from its capital tracker mechanism due to increased electric system improvements. The earnings increase was partially offset by higher depreciation expense, higher property tax expense, and higher interest expense.

NSTAR Electric's earnings increased $13.0 million in 2020, as compared to 2019, due primarily to the base distribution rate increase effective January 1, 2020, an increase in transmission earnings driven by a higher transmission rate base, and higher energy efficiency incentives earned. The earnings increase was partially offset by higher operations and maintenance expense, higher interest expense, higher depreciation expense, and higher property tax expense.

PSNH's earnings increased $13.3 million in 2020, as compared to 2019, due primarily to the temporary base distribution rate increase effective July 1, 2019, an increase in transmission earnings driven by a higher transmission rate base, and the impact of the PSNH rate settlement agreement approved in December 2020 that was due primarily to the reconciliation of permanent rates back to the temporary rate period. The settlement agreement primarily resulted in a benefit to income tax expense for the reduction of the EDIT regulatory liability, partially offset by a reduction in revenues driven by the negative impact from the over-refunding of the change in the 2018 federal corporate income tax rate as a result of the Tax Cuts and Jobs Act of 2017 that was reflected in temporary rates. The earnings increase was partially offset by higher operations and maintenance expense, higher property tax expense, and the absence of the 2019 recognition of carrying charges on its 2013 through 2016 storm costs approved for recovery.

LIQUIDITY

Cash Flows: CL&P had cash flows provided by operating activities of $397.1 million in 2020, as compared to $726.4 million in 2019. The decrease in operating cash flows was due primarily to cash payments made in 2020 for storm restoration costs of approximately $180 million related to Tropical Storm Isaias and the timing of cash payments made on our accounts payable. In addition, the timing of collections for regulatory tracking mechanisms, which includes the impact of the CL&P temporary rate suspension, the timing of cash collections on our accounts receivable, and the timing of other working capital items contributed to the decrease in operating cash flows. Partially offsetting these unfavorable impacts was lower income tax payments made of $69.7 million in 2020, as compared to 2019.

NSTAR Electric had cash flows provided by operating activities of $525.8 million in 2020, as compared to $698.3 million in 2019. The decrease in operating cash flows was due primarily to the timing of collections for regulatory tracking mechanisms primarily related to transmission costs, the timing of cash collections on our accounts receivable, a $32.8 million increase in income tax payments made in 2020, as compared to 2019, and the timing of other working capital items. Partially offsetting these unfavorable impacts were the timing of cash payments on our accounts payable and a $5.7 million decrease in Pension and PBOP contributions made in 2020, as compared to 2019.

PSNH had cash flows provided by operating activities of $218.7 million in 2020, as compared to $274.4 million in 2019. The decrease in operating cash flows was due primarily to the timing of cash collections on our accounts receivable and an increase in income tax payments made of $30.8 million in 2020, as compared to 2019. Also contributing to the decrease were the timing of collections for regulatory tracking mechanisms and an increase of $4.1 million in Pension contributions made in 2020, as compared to 2019. Partially offsetting these unfavorable impacts was the timing of cash payments on our accounts payable.

Receivables, net of reserves, on the balance sheets have increased $58.3 million at CL&P, $56.3 million at NSTAR Electric, and $20.0 million at PSNH in 2020, as compared to 2019, due primarily to an increase in delinquent receivables from customers attributable to the moratorium on disconnections and the economic slowdown resulting from the COVID-19 pandemic.

For further information on CL&P's, NSTAR Electric's and PSNH's liquidity and capital resources, see "Liquidity" and "Business Development and Capital Expenditures" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

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