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 toEversource 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 ofCL&P are herein collectively referred to as the "financial statements." Our discussion of fiscal year 2022 compared to fiscal year 2021 is included herein. Unless expressly stated otherwise, for discussion and analysis of fiscal year 2020 items and of fiscal year 2021 compared to fiscal year 2020, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in our combined 2021 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 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 that is not recognized under GAAP (non-GAAP) and is 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 earnings and EPS excluding certain transaction and transition costs, and our 2021 earnings and EPS excluding charges atCL&P related to anOctober 2021 settlement agreement that included credits to customers and funding of various customer assistance initiatives and a 2021 storm performance penalty imposed onCL&P by PURA. 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 results without including these items. This information is among the primary indicators we use as a basis for evaluating performance and planning and forecasting of future periods. We believe the impacts of transaction and transition costs, theCL&P October 2021 settlement agreement, and the 2021 storm performance penalty imposed onCL&P by PURA, are not indicative of our ongoing costs and performance. We view these charges as not directly related to the ongoing operations of the business and therefore not an indicator of baseline operating performance. Due to the nature and significance of the effect of these items on Net Income Attributable to Common Shareholders and EPS, 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
Eversource Energy is a public utility holding company primarily engaged, through its wholly-owned regulated utility subsidiaries, in the energy delivery business.Eversource Energy's wholly-owned regulated utility subsidiaries consist ofCL&P ,NSTAR Electric and PSNH (electric utilities),Yankee Gas ,NSTAR Gas and EGMA (natural gas utilities) and Aquarion (water utilities). Eversource is organized into the electric distribution, electric transmission, natural gas distribution, and water distribution reportable segments.
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
•Our results include after-tax transaction and transition costs recorded at Eversource parent of$15.0 million , or$0.04 per share, in 2022, compared with$23.6 million , or$0.07 per share, in 2021. Our 2021 results also include after-tax charges of$86.1 million , or$0.25 per share, resulting from a PURA-approvedCL&P settlement agreement and a PURA assessment as a result ofCL&P's preparation for, and response to, Tropical Storm Isaias inAugust 2020 , which were recorded within the electric distribution segment. Excluding these costs, our non-GAAP earnings were$1.42 billion , or$4.09 per share, in 2022, compared with$1.33 billion , or$3.86 per share, in 2021. •We project that we will earn within a 2023 non-GAAP earning guidance range of between$4.25 per share and$4.43 per share, which excludes the potential impact of the strategic review of our offshore wind investment portfolio. We also project that our long-term EPS growth rate through 2027 from our regulated utility businesses will be in the upper half of a 5 to 7 percent range. 27 --------------------------------------------------------------------------------
Liquidity:
•Cash flows provided by operating activities totaled
•Cash and Cash Equivalents totaled$374.6 million as ofDecember 31, 2022 , compared with$66.8 million as ofDecember 31, 2021 . Our available borrowing capacity under our commercial paper programs totaled$1.21 billion as ofDecember 31, 2022 .
•In 2022, we issued
•In 2022, we issued 2,165,671 common shares, which resulted in proceeds of
•In 2022, we paid dividends totaling$2.55 per common share, compared with dividends of$2.41 per common share in 2021. Our quarterly common share dividend payment was$0.6375 per share in 2022, as compared to$0.6025 per share in 2021. OnFebruary 1, 2023 , ourBoard of Trustees approved a common share dividend payment of$0.675 per share, payable onMarch 31, 2023 to shareholders of record as ofMarch 2, 2023 . •We project to make capital expenditures of$21.52 billion from 2023 through 2027, of which we expect$8.86 billion to be in our electric distribution segment,$5.25 billion to be in our natural gas distribution segment,$5.29 billion to be in our electric transmission segment, and$1.02 billion to be in our water distribution segment. We also project to invest$1.10 billion in information technology and facilities upgrades and enhancements. Additionally, we currently expect to make investments in our offshore wind business between$1.9 billion and$2.1 billion in 2023 and expect to make investments for our three projects in total between$1.6 billion and$1.9 billion from 2024 through 2026. These estimates assume that the three projects are completed and are in-service by the end of 2025, as planned. These projected investments could be impacted by the strategic review of our offshore wind investment.
Strategic and Regulatory Transactions and Developments:
•OnMay 4, 2022 , we announced that we had initiated a strategic review of our offshore wind investment portfolio. As part of that review, we are exploring strategic alternatives that could result in a potential sale of all, or part, of our 50 percent interest in our offshore wind partnership with Ørsted. We continue to work with interested parties through this ongoing process and expect to complete this review in the second quarter of 2023. •OnNovember 30, 2022 , the DPU issued its decision in theNSTAR Electric distribution rate case and approved a base distribution rate increase of$64 million effectiveJanuary 1, 2023 . The DPU approved a renewal of the performance-based ratemaking (PBR) plan originally authorized in its previous rate case for a five-year term, with a corresponding stay out provision. The PBR plan term has the possibility of a five-year extension. The PBR mechanism allows for an annual adjustment to base distribution rates for inflation and exogenous events. The DPU also allowed for adjustments to the PBR mechanism for the recovery of future capital additions based on a historical five-year average of total capital additions, beginning with theJanuary 1, 2024 PBR adjustment. The decision allows an authorized regulatory ROE of 9.80 percent on a capital structure including 53.2 percent equity.
Earnings Overview
Consolidated: Below is a summary of our earnings by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income Attributable to Common Shareholders and diluted EPS.
For the Years Ended
2022 2021 2020 (Millions of Dollars, Except Per Share Amounts) Amount Per Share Amount Per Share Amount Per Share Net Income Attributable to Common Shareholders (GAAP)$ 1,404.9 $ 4.05
Regulated Companies (Non-GAAP)$ 1,460.4 $ 4.21
(40.5) (0.12) (12.2) (0.03) 14.0 0.04 Non-GAAP Earnings$ 1,419.9 $ 4.09
- - (86.1) (0.25) - - Transaction and Transition Costs (after-tax) (2) (15.0) (0.04) (23.6) (0.07) (32.1) (0.09) Net Income Attributable to Common Shareholders (GAAP)$ 1,404.9 $ 4.05 $ 1,220.5 $ 3.54 $ 1,205.2 $ 3.55 (1) The 2021 after-tax costs are associated with theOctober 1, 2021 CL&P settlement agreement approved by PURA onOctober 27, 2021 , which included a pre-tax$65 million charge to earnings for customer credits provided to customers over a two-month billing period fromDecember 1, 2021 toJanuary 31, 2022 and a$10 million pre-tax charge to earnings to establish a fund that provided bill payment assistance to certain existing non-hardship and hardship customers carrying arrearages. The 2021 after-tax costs also include a charge recorded atCL&P as a result of PURA'sApril 28, 2021 andJuly 14, 2021 decisions, which included a pre-tax$28.4 million penalty for storm performance results provided as credits to customer bills over a one-year period that beganSeptember 1, 2021 and a pre-tax$0.2 million fine to theState of Connecticut's general fund. As a result of theOctober 1, 2021 settlement agreement,CL&P agreed to withdraw its pending appeals related to 28 -------------------------------------------------------------------------------- the storm performance penalty imposed in PURA'sApril 28, 2021 andJuly 14, 2021 decisions. Management views these collective charges as not directly related to the ongoing operations of the business and therefore not an indicator of baseline operating performance. (2) The after-tax costs are for the transition of systems as a result of our purchase of the assets ofColumbia Gas of Massachusetts (CMA) onOctober 9, 2020 and integrating the CMA assets onto Eversource's systems. The after-tax costs also include costs associated with our water business acquisitions and the strategic review of our offshore wind investment portfolio. We expect transaction costs in 2023 as a result of the wind strategic review. Regulated Companies: Our regulated companies comprise the electric distribution, electric transmission, natural gas distribution and water distribution segments. A summary of our segment earnings and EPS is as follows: For the Years Ended December 31, 2022 2021 2020 (Millions of Dollars, Except Per Share Amounts) Amount Per Share Amount Per Share Amount
Per Share
Net Income - Regulated Companies (GAAP)
3.60
Electric Distribution, excluding CL&P Settlement Impacts (Non-GAAP)$ 592.8 $ 1.71 $ 556.2 $ 1.61 $ 544.0 $ 1.60 Electric Transmission 596.6 1.72 544.6 1.58 502.5 1.48 Natural Gas Distribution, excluding Transaction-Related Costs (Non-GAAP) 234.2 0.67 204.8 0.59 135.6 0.40 Water Distribution 36.8 0.11 36.8 0.11 41.2 0.12
Net Income - Regulated Companies (Non-GAAP)
3.60
CL&P Settlement Impacts (after-tax) - - (86.1) (0.25) -
-
Transaction and Transition Costs (after-tax) - - - - (1.5)
-
Net Income - Regulated Companies (GAAP)
3.60 Our electric distribution segment earnings increased$122.7 million in 2022, as compared to 2021, due primarily to the absence in 2022 ofCL&P's October 1, 2021 settlement agreement that resulted in a$75 million pre-tax charge to earnings and a$28.6 million pre-tax charge to earnings atCL&P for a 2021 storm performance penalty imposed by PURA as a result ofCL&P's preparation for, and response to, Tropical Storm Isaias. The after-tax impact of theCL&P settlement agreement andCL&P storm performance penalty imposed by PURA was$86.1 million , or$0.25 per share. Excluding those 2021 charges, electric distribution segment earnings increased$36.6 million due primarily to a base distribution rate increase atNSTAR Electric effectiveJanuary 1, 2022 , higher earnings fromCL&P's capital tracking mechanism due to increased electric system improvements, lower pension plan expense inConnecticut andNew Hampshire , and an increase in interest income primarily on regulatory deferrals. Those earnings increases were partially offset by higher operations and maintenance expense driven primarily by higher shared corporate costs resulting from the implementation of new information technology systems, higher storm costs, a$10 million pre-tax charge to earnings as a result ofCL&P's commitment to contribute to an energy assistance program as part of its 2022 rate relief plan, and higher insurance reserves. Earnings were also unfavorably impacted by higher depreciation expense, higher property and other tax expense, and higher interest expense. Our electric transmission segment earnings increased$52.0 million in 2022, as compared to 2021, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure, partially offset by a higher effective income tax rate and higher interest expense on short-term debt. Our natural gas distribution segment earnings increased$29.4 million in 2022, as compared to 2021, due primarily to base distribution rate increases effectiveNovember 1, 2021 andNovember 1, 2022 at each ofEGMA andNSTAR Gas , higher earnings from capital tracking mechanisms due to continued investments in natural gas infrastructure, and lower pension plan expense atYankee Gas . Those earnings increases were partially offset by higher operations and maintenance expense, higher property tax expense, higher interest expense, and higher depreciation expense.
Our water distribution segment earnings were flat in 2022, as compared to 2021.
Eversource Parent and Other Companies: Eversource parent and other companies' losses increased$19.7 million in 2022, as compared to 2021, due primarily to higher interest expense and a higher effective tax rate, partially offset by higher unrealized gains associated with our equity method investment in a renewable energy fund and an after-tax decrease of$8.6 million in transition costs associated with EGMA integration and transaction costs in 2022, as compared to 2021. 29 --------------------------------------------------------------------------------
Liquidity
Sources and Uses of Cash: Eversource's regulated business is capital intensive and requires considerable capital resources. Eversource's regulated companies' capital resources are provided by cash flows generated from operations, short-term borrowings, long-term debt issuances, capital contributions from Eversource parent, and existing cash, and are used to fund their liquidity and capital requirements. Eversource's regulated companies typically maintain minimal cash balances and use short-term borrowings to meet their working capital needs and other cash requirements. Short-term borrowings are also used as a bridge to long-term debt financings. The levels of short-term borrowing may vary significantly over the course of the year due to the impact of fluctuations in cash flows from operations, dividends paid, capital contributions received and the timing of long-term debt financings. 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. Eversource's regulated companies spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment and recovery period. In addition, Eversource uses its capital resources to fund investments in its offshore wind business, which are recognized as long-term assets. These factors have resulted in current liabilities exceeding current assets by$2.58 billion ,$168.6 million , and$330.0 million at Eversource,CL&P , and PSNH, respectively, as ofDecember 31, 2022 . 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. As ofDecember 31, 2022 ,$2.01 billion of Eversource's long-term debt, including$1.20 billion at Eversource parent,$400.0 million atCL&P ,$80.0 million atNSTAR Electric , and$325.0 million at PSNH, matures within the next 12 months.CL&P repaid this long-term debt at maturity inJanuary 2023 . 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.
Cash and Cash Equivalents totaled
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 ,EGMA andAquarion Water Company of Connecticut are parties to a five-year$2.00 billion revolving credit facility, which terminates onOctober 15, 2027 . This revolving credit facility serves to backstop Eversource parent's$2.00 billion commercial paper program.NSTAR Electric has a$650 million commercial paper program allowingNSTAR 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 onOctober 15, 2027 . This revolving credit facility serves to backstopNSTAR Electric's $650 million commercial paper program. The amount of borrowings outstanding and available under the commercial paper programs were as follows: Borrowings Outstanding Available Borrowing Capacity Weighted-Average Interest Rate as of as of December 31, as of December 31, December 31, (Millions of Dollars) 2022 2021 2022 2021 2022 2021 Eversource Parent Commercial Paper Program$ 1,442.2 $ 1,343.0 $ 557.8 $ 657.0 4.63 % 0.31 % NSTAR Electric Commercial Paper Program - 162.5 650.0 487.5 - % 0.14 %
There were no borrowings outstanding on the revolving credit facilities as of
CL&P and PSNH have uncommitted line of credit agreements totaling$450 million and$300 million , respectively, which will expire onMay 12, 2023 . There are no borrowings outstanding on either theCL&P or PSNH uncommitted line of credit agreements as ofDecember 31, 2022 . Amounts outstanding under the commercial paper programs are included in Notes Payable and classified in current liabilities on theEversource andNSTAR 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 ofDecember 31, 2022 , there were intercompany loans from Eversource parent to PSNH of$173.3 million . As ofDecember 31, 2021 , there were intercompany loans from Eversource parent to PSNH of$110.6 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. 30 -------------------------------------------------------------------------------- Availability under Long-Term Debt Issuance Authorizations: OnDecember 14, 2022 , the NHPUC approved PSNH's request for authorization to issue up to$600 million in long-term debt throughDecember 31, 2023 . OnNovember 30, 2022 , the PURA approvedCL&P's request for authorization to issue up to$1.15 billion in long-term debt throughDecember 31, 2024 . OnJune 14, 2022 , the DPU approvedNSTAR Gas' request for authorization to issue up to$325 million in long-term debt throughDecember 31, 2024 . The remaining Eversource operating companies, includingNSTAR Electric , have utilized the long-term debt authorizations in place with the respective regulatory commissions.
Long-Term Debt Issuances and Repayments: The following table summarizes long-term debt issuances and repayments:
Issuance/ Issue Date or Use of Proceeds for Issuance/ (Millions of Dollars) Interest Rate (Repayment) Repayment Date Maturity Date Repayment Information Repaid 2013 Series A Bonds at maturity and short-term debt, CL&P 2023 Series A First and paid capital expenditures Mortgage Bonds 5.25 %$ 500.0 January 2023 January 2053 and working capitalCL&P 2013 Series A First Mortgage Bonds 2.50 % (400.0) January 2023 January 2023 Paid at maturity Repaid short-term debt, paid capital expenditures and NSTAR Electric 2022 Debentures 4.55 % 450.0 May 2022 June 2052 working capital Refinanced investments in eligible green expenditures, which were previously financed using short-term debt from October 1, 2020 through June NSTAR Electric 2022 Debentures 4.95 % 400.0 September 2022 September 2052 30, 2022 NSTAR Electric 2012 Debentures 2.375 % (400.0) October 2022 October 2022 Paid at maturity Repaid short-term debt, paid PSNH Series W First Mortgage capital expenditures and Bonds 5.15 % 300.0 January 2023 January 2053 working capital Eversource Parent Series V Repaid Series K Senior Notes at Senior Notes 2.90 % 650.0 February 2022 March 2027 maturity and short-term debt Eversource Parent Series W Repaid Series K Senior Notes at Senior Notes 3.375 % 650.0 February 2022 March 2032 maturity and short-term debt Eversource Parent Series X Repaid short-term debt and paid Senior Notes 4.20 % 900.0 June 2022 June 2024 working capital Eversource Parent Series Y Repaid short-term debt and paid Senior Notes 4.60 % 600.0 June 2022 July 2027 working capital Eversource Parent Series K Senior Notes 2.75 % (750.0) March 2022 March 2022 Paid at maturity Yankee Gas Series B First Mortgage Bonds 8.48 % (20.0) March 2022 March 2022 Paid at maturity Repaid short-term debt, paid Yankee Gas Series U First capital expenditures and for Mortgage Bonds 4.31 % 100.0 September 2022 September 2032 general corporate purposes Repaid short-term debt, paid EGMA Series C First Mortgage capital expenditures and for Bonds 4.70 % 100.0 June 2022 June 2052 general corporate purposes Repaid short-term debt, paid NSTAR Gas Series V First capital expenditures and for Mortgage Bonds 4.40 % 125.0 July 2022 August 2032 general corporate purposesAquarion Water Company of New Hampshire General Mortgage Bonds 4.45 % (5.0) July 2022 July 2022 Paid at maturityAquarion Water Company of Connecticut Senior Notes 4.69 % 70.0 August 2022 September 2052 Repaid short-term debt As a result of theCL&P and PSNH long-term debt issuances inJanuary 2023 ,$400 million and$295.3 million , respectively, of current portion of long-term debt were reclassified as Long-Term Debt onCL&P's and PSNH's balance sheets as ofDecember 31, 2022 . 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$17.6 million of interest payments in 2022, and paid$43.2 million of RRB principal payments and$18.9 million of interest payments in 2021. Common Share Issuances and 2022 Equity Distribution Agreement: OnMay 11, 2022 , Eversource entered into an equity distribution agreement pursuant to which it may offer and sell up to$1.2 billion of its common shares from time to time through an "at-the-market" (ATM) equity offering program. Eversource may issue and sell its common shares through its sales agents during the term of this agreement. Shares may be offered in transactions on theNew York Stock Exchange , in the over-the-counter market, through negotiated transactions or otherwise. Sales may be made at either market prices prevailing at the time of sale, at prices related to such prevailing market prices or at negotiated prices. In 2022, Eversource issued 2,165,671 common shares, which resulted in proceeds of$197.1 million , net of issuance costs. Eversource used the net proceeds received for general corporate purposes. Cash Flows: Cash flows from operating activities primarily result from the transmission and distribution of electricity, and the distribution of natural gas and water. Cash flows provided by operating activities totaled$2.40 billion in 2022, compared with$1.96 billion in 2021. Changes in Eversource's cash flows from operations were generally consistent with changes in its results of operations, after adjustment for non-cash items and as adjusted by changes in working capital in the normal course of business. Operating cash flows were favorably impacted by the timing of cash payments made on our accounts payable, an increase in regulatory over-recoveries driven by the timing of collections for the non-bypassable FMCC atCL&P and other regulatory tracking mechanisms, a decrease of$99.2 million in pension and PBOP contributions made in 2022, as compared to 2021, and a$43.7 million decrease in income tax payments made in 2022, as compared to 2021. The impact of regulatory collections are included in both Regulatory Over/Under Recoveries and Amortization on the statements of cash flows. These favorable impacts were partially 31 -------------------------------------------------------------------------------- offset by the timing of cash collections on our accounts receivable,$78.4 million of payments in 2022 related to withheld property taxes at ourMassachusetts companies, primarily atNSTAR Electric ,$72.0 million of customer credits distributed toCL&P's customers in 2022 as a result of theOctober 2021 settlement agreement and the 2021 storm performance penalty forCL&P's response to Tropical Storm Isaias, a$61.6 million increase in cost of removal expenditures, and an increase of$34.0 million in cash payments for storm costs atNSTAR Electric . In 2022, we paid cash dividends of$860.0 million and issued non-cash dividends of$23.1 million in the form of treasury shares, totaling dividends of$883.1 million , or$2.55 per common share. In 2021, we paid cash dividends of$805.4 million and issued non-cash dividends of$22.9 million in the form of treasury shares, totaling dividends of$828.3 million , or$2.41 per common share. Our quarterly common share dividend payment was$0.6375 per share in 2022, as compared to$0.6025 per share in 2021. OnFebruary 1, 2023 , our Board of Trustees approved a common share dividend payment of$0.675 per share, payable onMarch 31, 2023 to shareholders of record as ofMarch 2, 2023 .
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 2022,
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 income/expense. In 2022, investments for Eversource,CL&P ,NSTAR Electric , and PSNH were$3.44 billion ,$876.7 million ,$954.3 million and$485.6 million , respectively. Capital expenditures were primarily for continuing projects to maintain and improve infrastructure and operations, including enhancing reliability to the transmission and distribution systems. Contractual Obligations: For information regarding our cash requirements from contractual obligations and payment schedules, see Note 9, "Long-Term Debt," Note 10, "Rate Reduction Bonds and Variable Interest Entities," Note 11A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pension," Note 13, "Commitments and Contingencies," and Note 14, "Leases," to the financial statements. Estimated interest payments on existing long-term fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement as ofDecember 31, 2022 and are as follows: (Millions of Dollars) 2023 2024 2025 2026 2027 Thereafter Total Eversource$ 722.6 $ 654.7 $ 589.6 $ 559.7 $ 517.3 $ 5,864.4 $ 8,908.3 CL&P 154.7 149.7 138.6 135.6 127.6 1,657.2 2,363.4 Our commitments to make payments in addition to these contractual obligations include other liabilities reflected on our balance sheets, future funding of our offshore wind equity method investment, and guarantees of certain obligations primarily associated with our offshore wind investment. The future funding and guarantee obligations associated with our offshore wind investment could be impacted by the strategic review of our offshore wind investment. For information regarding our projected capital expenditures over the next five years, see "Business Development and Capital Expenditures -Projected Capital Expenditures" and for projected investments in our offshore wind business, see Business Development and Capital Expenditures - Offshore Wind Business" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations.
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- Positive Baa1 Negative BBB+ Stable CL&P A Positive A3 Stable A- Stable NSTAR Electric A Positive A1 Negative 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 andNSTAR Electric , and senior secured debt ofCL&P and PSNH is as follows: S&P Moody's Fitch Current Outlook Current Outlook Current Outlook Eversource Parent BBB+ Positive Baa1 Negative BBB+ Stable CL&P A+ Positive A1 Stable A+ Stable NSTAR Electric A Positive A1 Negative A+ Stable PSNH A+ Stable A1 Stable A+ Stable 32
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Impact of COVID-19
The financial impacts of COVID-19 as it relates to our businesses primarily relate to collectability of customer receivables and the outcome of future proceedings before our state regulatory commissions to recover our incremental uncollectible customer receivable costs associated with COVID-19.
As ofDecember 31, 2022 , our allowance for uncollectible customer receivable balance of$486.3 million , of which$284.4 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. As ofDecember 31, 2022 and 2021, the total amount incurred as a result of COVID-19 included in the allowance for uncollectible accounts was$50.9 million and$55.3 million at Eversource,$16.0 million and$23.9 million atCL&P , and$4.1 million and$9.0 million atNSTAR Electric , respectively. At ourConnecticut andMassachusetts utilities, the 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 management believes it is probable that these costs will ultimately be recovered from customers in future rates. No COVID-19 related uncollectible amounts were deferred at PSNH as a result of aJuly 2021 NHPUC order. Based on the status of our COVID-19 regulatory dockets, policies and practices in the jurisdictions in which we operate, we believe the state regulatory commissions inConnecticut andMassachusetts will allow us to recover our incremental uncollectible customer receivable costs associated with COVID-19.
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 income/expense (all of which are non-cash factors), totaled$3.79 billion in 2022,$3.54 billion in 2021, and$3.06 billion in 2020. These amounts included$266.5 million in 2022,$238.0 million in 2021, and$239.1 million in 2020 related to information technology and facilities upgrades and enhancements, primarily atEversource Service and The Rocky River Realty Company . Electric Transmission Business: Our consolidated electric transmission business capital expenditures increased by$91.7 million in 2022, as compared to 2021. A summary of electric transmission capital expenditures by company is as follows: For the Years Ended December 31, (Millions of Dollars) 2022 2021 2020 CL&P$ 416.8 $ 400.0 $ 402.9 NSTAR Electric 438.4 480.3 366.8 PSNH 351.8 235.0 193.9 Total Electric Transmission Segment$ 1,207.0 $ 1,115.3
Our transmission projects are designed to improve the reliability of the electric grid, meet customer demand for power and increases in electrification of municipal infrastructure, strengthen the electric grid's resilience against extreme weather and other safety and security threats, and enable integration of increasing amounts of clean power generation from renewable sources, such as solar, battery storage, and offshore wind. InConnecticut ,Massachusetts andNew Hampshire , our transmission projects include transmission line upgrades, the installation of new transmission interconnection facilities, substations and lines, and transmission substation enhancements. Our transmission projects inMassachusetts include electric transmission upgrades in the greaterBoston metropolitan area. Two of these upgrades, the Mystic-Woburn and theWakefield -Woburn reliability projects, are under construction and are expected to be placed in service by the fourth quarter of 2023. Construction on the last remaining upgrade, theSudbury-Hudson Reliability Project , commenced in the fourth quarter of 2022. We spent$71.9 million during 2022 and we expect to make additional capital expenditures of approximately$115 million on these remaining transmission upgrades. There are also several transmission projects underway in southeasternMassachusetts , includingCape Cod , required to reinforce theSoutheastern Massachusetts transmission system and bring the system into compliance with applicable national and regional reliability standards. We spent$23.2 million during 2022 and we expect to make additional capital expenditures of approximately$110 million on these transmission upgrades. 33 --------------------------------------------------------------------------------
Distribution Business: A summary of distribution capital expenditures is as follows:
For the Years Ended
NSTAR Total (Millions of Dollars) CL&P Electric PSNH Electric Natural Gas Water Total 2022 Basic Business$ 267.8 $ 202.4 $ 68.6 $ 538.8 $ 175.2 $ 16.8 $ 730.8 Aging Infrastructure 199.9 245.1 70.8 515.8 562.3 137.6 1,215.7 Load Growth and Other 90.7 177.0 31.3 299.0 66.4 0.9 366.3 Total Distribution$ 558.4 $ 624.5 $ 170.7 $ 1,353.6 $ 803.9 $ 155.3 $ 2,312.8 2021 Basic Business$ 256.2 $ 179.9 $ 56.0 $ 492.1 $ 206.1 $ 16.5 $ 714.7 Aging Infrastructure 178.0 219.1 67.7 464.8 509.6 127.1 1,101.5 Load Growth and Other 80.2 169.9 37.1 287.2 83.3 0.6 371.1 Total Distribution$ 514.4 $ 568.9 $ 160.8 $ 1,244.1 $ 799.0 $ 144.2 $ 2,187.3 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 77.8 112.2 21.3 211.3 65.6 0.8 277.7 Total Distribution$ 491.1 $ 544.4 $ 153.9 $ 1,189.4 $ 545.1 $ 127.2 $ 1,861.7 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. 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 2023 through 2027, including information technology and facilities upgrades and enhancements on behalf of the regulated companies, is as follows: Years 2023 - 2027 (Millions of Dollars) 2023 2024 2025 2026 2027 Total CL&P Transmission$ 406 $ 312 $ 324 $ 263 $ 136 $ 1,441 NSTAR Electric Transmission 461 527 436 575 748 2,747 PSNH Transmission 329 270 252 174 72 1,097 Total Electric Transmission$ 1,196 $ 1,109 $ 1,012 $ 1,012 $ 956 $ 5,285 Electric Distribution$ 1,847 $ 1,750 $ 1,768 $ 1,870 $ 1,628 $ 8,863 Natural Gas Distribution 1,035 1,038 1,146 1,115 918 5,252Total Electric and Natural Gas Distribution$ 2,882 $ 2,788 $ 2,914
$ 170 $ 194 $ 203 $ 218 $ 235 $ 1,020 Information Technology and All Other$ 215 $ 213 $ 244 $ 219 $ 208 $ 1,099 Total$ 4,463 $ 4,304 $ 4,373 $ 4,434 $ 3,945 $ 21,519
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.
Acquisition of
34 -------------------------------------------------------------------------------- Offshore Wind Business: Our offshore wind business includes a 50 percent ownership interest in North East Offshore, which holds PPAs and contracts for the Revolution Wind, South Fork Wind and Sunrise Wind projects, as well as an undeveloped offshore lease area. Our offshore wind projects are being developed and constructed through a joint and equal partnership with Ørsted. The offshore leases include a 257 square-mile ocean lease off the coasts ofMassachusetts andRhode Island and a separate, adjacent 300-square-mile ocean lease located approximately 25 miles south of the coast ofMassachusetts . In aggregate, these ocean lease sites jointly-owned by Eversource and Ørsted could eventually develop at least 4,000 MW of clean, renewable offshore wind energy. As ofDecember 31, 2022 and 2021, Eversource's total equity investment balance in its offshore wind business was$1.95 billion and$1.21 billion , respectively. This equity investment includes capital expenditures for the three projects, as well as capitalized costs related to future development, acquisition costs of offshore lease areas, and capitalized interest. Strategic Review of Offshore Wind Investments: OnMay 4, 2022 , we announced that we had initiated a strategic review of our offshore wind investment portfolio. As part of that review, we are exploring strategic alternatives that could result in a potential sale of all, or part, of our 50 percent interest in our offshore wind partnership with Ørsted. In late July, we started preliminary and targeted outreach to interested parties. We continue to work with interested parties through this ongoing process and expect to complete this review in the second quarter of 2023. If the recommended path forward following the strategic review is a sale of all, or part, of our interest in the partnership, we expect potential proceeds from such transaction would likely be used to support our regulated investments in strengthening, modernizing and decarbonizing our regulated energy and water delivery systems. We currently believe that the fair market value of our offshore wind investment is greater than the carrying value; however, there could be changes in market conditions that would impact our ability to sell this investment or realize a value in excess of our carrying value. As the strategic review proceeds, we remain committed to continue providing oversight of the siting and construction of onshore elements of our South Fork Wind, Revolution Wind and Sunrise Wind offshore wind projects. Contracts, Permitting and Construction of Offshore Wind Projects: 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 Fixed price contract; no price Revolution Wind Rhode Island 400 20$98.43 escalation Approved Fixed price contracts; no Revolution Wind Connecticut 304 20$98.43 -$99.50 price escalation Approved 2 percent average price South Fork Wind New York (LIPA) 90 20$160.33 escalation Approved 2 percent average price South Fork Wind New York (LIPA) 40 20$86.25 escalation Approved Fixed price contract; no price Sunrise Wind New York (NYSERDA) 924 25$110.37 (1) escalation Approved (1) Index Offshore Wind Renewable Energy Certificate (OREC) strike price. Revolution Wind and Sunrise Wind projects are subject to receipt of federal, state and local approvals necessary to construct and operate the projects. The federal permitting process is led by BOEM, and state approvals are required fromNew York ,Rhode Island andMassachusetts . Significant delays in the siting and permitting process resulting from the timeline for obtaining approval from BOEM and the state and local agencies could adversely impact the timing of these projects' in-service dates. Federal Siting and Permitting Process: The federal siting and permitting process for each of our offshore wind projects commence with the filing of a Construction and Operations Plan (COP) application with BOEM. The first major milestone in the BOEM review process is an issuance of a Notice of Intent (NOI) to complete an Environmental Impact Statement (EIS). BOEM then provides a final review schedule for the project's COP approval. BOEM conducts environmental and technical reviews of the COP. The EIS assesses the environmental, social, and economic impacts of constructing the project and recommends measures to minimize impacts. The Final EIS will inform BOEM in deciding whether to approve the project or to approve with modifications and BOEM will then issue its Record of Decision. BOEM issues its final approval of the COP following the Record of Decision. Revolution Wind and Sunrise Wind filed their COP applications with BOEM inMarch 2020 andSeptember 2020 , respectively. BOEM released its Draft EIS onSeptember 2, 2022 for the Revolution Wind project and onDecember 16, 2022 for the Sunrise Wind project. The Draft EIS analyzes the potential environmental impacts of the project and the alternatives to the project to be evaluated as part of the process. Each of the identified alternative configurations in the Draft EISs had a similar level of environmental impacts, and if an alternative configuration was selected, the Revolution Wind project and the Sunrise Wind project would each still meet their respective contractual output requirements. For Revolution Wind, a final EIS is expected in the second quarter of 2023, the Record of Decision in the third quarter of 2023, and final approval is expected in the fourth quarter of 2023. For Sunrise Wind, a final EIS and Record of Decision are expected in the third quarter of 2023, and final approval is expected in the fourth quarter of 2023.
South Fork Wind, Revolution Wind and Sunrise Wind are each designated as a
"
35 -------------------------------------------------------------------------------- State and Local Siting and Permitting Process: State permitting applications inRhode Island for Revolution Wind and inNew York for Sunrise Wind were filed inDecember 2020 . OnJuly 8, 2022 , the Rhode Island Energy Facilities Siting Board issued a Final Decision and Order approving the Revolution Wind project and granting a license to construct and operate. OnSeptember 23, 2022 , Sunrise Wind filed a Joint Proposal to theNew York State Public Service Commission . Among other things, the Joint Proposal includes proposed mitigation for certain environmental, community and construction impacts associated with constructing the project. The Joint Proposal was signed by the New York Departments of Public Service, Environmental Conservation, Transportation and State as well as theOffice of Agriculture and Markets and theLong Island Commercial Fisheries Association . OnNovember 17, 2022 , theNew York Public Service Commission approved an order adopting the Joint Proposal and granting a Certificate of Environmental Compatibility and Public Need. OnNovember 18, 2022 , Sunrise Wind filed its Environmental Management and Construction Plan (EM&CP) with theNew York Public Service Commission , which details the plans on how the project will be constructed in accordance with the conditions of the approved Joint Proposal. Comments from several of the reviewing agencies and parties have been received and Sunrise Wind is in the process of reviewing and addressing those comments in the plan. OnNovember 9, 2022 , the Towns ofBrookhaven andSuffolk County executed the easements and other real estate rights necessary to construct the Sunrise Wind project. OnNovember 28, 2022 , theTown of North Kingstown and theQuonset Development Corporation approved Revolution Wind's real estate PILOT terms and the personal property PILOT agreement necessary to construct the Revolution Wind project. Construction Process: South Fork Wind received all required approvals to start construction and the project entered the construction phase in early 2022. Onshore activities for the project's underground onshore transmission line and construction of the onshore interconnection facility located inEast Hampton, New York are underway. Offshore activities began in the fourth quarter of 2022 with construction of the sea-to-shore conduit system. Other marine construction activities, including the project's monopile foundations, 11-megawatt wind turbines, cable installation, and offshore substation, are expected to occur in 2023. Construction-related purchase agreements with third-party contractors and materials contracts have largely been secured. South Fork Wind faces several challenges and appeals ofNew York State and federal agency approvals, however it believes it is probable it will be able to overcome these challenges. For Revolution Wind and Sunrise Wind, construction is expected to begin in the second half of 2023 once all necessary federal, state and local approvals are received. Projected In-Service Dates: We expect the South Fork Wind project to be in-service by the end of 2023. For Revolution Wind and Sunrise Wind, based on the BOEM permit schedule included in each respective NOI outlining when BOEM will complete its review of the COP, we currently expect in-service dates in 2025 for both projects. Projected Investments: For Revolution Wind and Sunrise Wind, 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. Construction of South Fork Wind is underway. Construction-related purchase agreements with third-party contractors and materials contracts have largely been secured. Subject to advancing our final project designs and federal, state and local permitting processes and construction schedules, we currently expect to make investments in our offshore wind business between$1.9 billion and$2.1 billion in 2023 and expect to make investments for our three projects in total between$1.6 billion and$1.9 billion from 2024 through 2026. These estimates assume that the three projects are completed and are in-service by the end of 2025, as planned. These projected investments could be impacted by the strategic review of our offshore wind investment.
FERC Regulatory Matters
FERC ROE Complaints: Four separate complaints were filed at theFERC by combinations ofNew 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 onOctober 1, 2011 ,December 27, 2012 , andJuly 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 finalFERC order and for the separate 15-month complaint periods. In the fourth complaint, filedApril 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 periodOctober 1, 2011 (beginning of the first complaint period) throughOctober 15, 2014 consisted of a base ROE of 11.14 percent and incentives up to 13.1 percent. OnOctober 16, 2014 ,FERC issued Opinion No. 531-A and 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 beginningOctober 16, 2014 . ThisFERC order was vacated onApril 14, 2017 by theU.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 bothDecember 31, 2022 and 2021. 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 forCL&P ,$14.6 million forNSTAR Electric and$3.1 million for PSNH as of bothDecember 31, 2022 and 2021. OnOctober 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 onJanuary 11, 2019 and reply briefs were filed onMarch 8, 2019 . The NETOs' brief was supportive of the overall ROE methodology determined in theOctober 16, 2018 order provided theFERC does not change the proposed methodology or alter its implementation in a manner that has a material impact on the results. 36 -------------------------------------------------------------------------------- TheFERC order included illustrative calculations for the first complaint usingFERC's proposed frameworks with financial data from that complaint. Those illustrative calculations indicated that for the first complaint period, for the NETOs, whichFERC 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 finalFERC 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 finalFERC order. OnNovember 21, 2019 ,FERC issued Opinion No. 569 affecting the two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in whichFERC adopted a new methodology for determining base ROEs. Various parties sought rehearing. OnDecember 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. OnMay 21, 2020 , theFERC issued its order in Opinion No. 569-A on the rehearing of the MISO transmission owners' cases, in whichFERC again changed its methodology for determining the MISO transmission owners' base ROEs. OnNovember 19, 2020 , theFERC 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 byFERC in itsOctober 16, 2018 order to determine the NETOs' base ROEs in its four pending cases. FERC Opinion Nos. 569-A and 569-B were appealed to the Court. OnAugust 9, 2022 , the Court issued its decision vacating MISO ROE FERC Opinion Nos. 569, 569-A and 569-B and remanded toFERC to reopen the proceedings. The Court found thatFERC's development of the new return methodology was arbitrary and capricious due toFERC's failure to offer a reasonable explanation for its decision to reintroduce the risk-premium financial model in its new methodology for calculating a just and reasonable return. At this time, Eversource cannot predict how and whenFERC will address the Court's findings on the remand of the MISO FERC opinions or any potential associated impact on the NETOs' four pending ROE complaint cases. Given the significant uncertainty regarding the applicability of theFERC 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 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 theOctober 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. Prospectively from the date of a finalFERC order implementing a new base ROE, based off of estimated 2022 rate base, a change of 10 basis points to the base ROE would impact Eversource's future annual after-tax earnings by approximately$5 million per year, and will increase slightly over time as we continue to invest in our transmission infrastructure. FERC Notice of Inquiry on ROE: OnMarch 21, 2019 ,FERC issued a Notice of Inquiry (NOI) seeking comments from all stakeholders onFERC's policies for evaluating ROEs for electric public utilities, and interstate natural gas and oil pipelines. OnJune 26, 2019 , the NETOs jointly filed comments supporting the methodology established in theFERC's October 16, 2018 order with minor enhancements going forward. The NETOs jointly filed reply comments in theFERC ROE NOI onJuly 26, 2019 . OnMay 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: OnMarch 21, 2019 ,FERC issued an NOI seeking comments onFERC's policies for implementing electric transmission incentives. OnJune 26, 2019 , Eversource filed comments requesting thatFERC 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 onAugust 26, 2019 . OnMarch 20, 2020 ,FERC issued a Notice of Proposed Rulemaking (NOPR) on transmission incentives. The NOPR intends to reviseFERC'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. OnJuly 1, 2020 , Eversource filed comments generally supporting the NOPR. OnApril 15, 2021 ,FERC issued a Supplemental NOPR that proposes to eliminate the existing 50 basis point return on equity for utilities that have been participating in a regional transmission organization (RTO ROE incentive) for more than three years. OnJune 25, 2021 , the NETOs jointly filed comments strongly opposingFERC's proposal. OnJuly 26, 2021 , the NETOs filed Supplemental NOPR reply comments responding to various parties advocating for the elimination of the RTO Adder. IfFERC issues a final order eliminating the RTO ROE incentive as proposed in the Supplemental NOPR, the estimated annual impact (using 2022 estimated rate base) on Eversource's after-tax earnings is approximately$18 million . The Supplemental NOPR contemplates an effective date 30 days from the final order.
At this time, Eversource cannot predict the ultimate outcome of these proceedings, including possible appellate review, and the resulting impact on its transmission incentives.
Regulatory Developments and Rate Matters
Electric, Natural Gas and Water Utility Retail Tariff 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 inConnecticut and are subject to PURA regulation;NSTAR Electric ,NSTAR Gas , EGMA and Aquarion operate inMassachusetts and are subject to DPU regulation; and PSNH and Aquarion operate inNew 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. 37 -------------------------------------------------------------------------------- Base Distribution Rates: InConnecticut , electric and natural gas utilities are required to file a distribution rate case within four years of the last rate case.CL&P's andYankee Gas' base distribution rates were each established in 2018 PURA-approved rate case settlement agreements. OnOctober 27, 2021 , PURA approved a settlement agreement atCL&P that included a current base distribution rate freeze until no earlier thanJanuary 1, 2024 . The approval of the settlement agreement satisfies theConnecticut statute of rate review requirements that requires electric utilities to file a distribution rate case within four years of the last rate case. Aquarion is not required to initiate a rate review with PURA on a set schedule. OnAugust 29, 2022 , Aquarion filed an application with PURA to amend its existing rate schedules and a final decision is expectedMarch 15, 2023 . InMassachusetts , electric distribution companies are required to file distribution rate schedules every five years, and natural gas local distribution companies to file distribution rate schedules every 10 years, and those companies are limited to one settlement agreement in any 10-year period.NSTAR Electric's base distribution rates were established in aNovember 2022 DPU-approved rate case.NSTAR Gas' base distribution rates were established in anOctober 2020 DPU-approved rate case. EGMA's base distribution rates were established in anOctober 2020 DPU-approved rate settlement agreement. Aquarion is not required to initiate a rate review with the DPU. Aquarion's base distribution rates were established in a 2018 DPU-approved rate case. InNew Hampshire , PSNH's base distribution rates were established in aDecember 2020 NHPUC-approved rate case settlement agreement. Aquarion's base distribution rates were established in aJuly 2022 NHPUC-approved rate case settlement agreement, with a single step adjustment approved onJanuary 19, 2023 . Rates are effectiveMarch 1, 2023 . Rate Reconciling Mechanisms: 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 in retail rates 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, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for theMassachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs. 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 capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings.
CL&P Advanced Metering Infrastructure Filing: OnJuly 31, 2020 ,CL&P submitted to PURA its proposed$512 million Advanced Metering Infrastructure investment and implementation plan. OnAugust 17, 2021 , PURA issued a Notice of Request for Amended EDC Advanced Metering Infrastructure Proposal.CL&P submitted an Amended Proposal in response to this request onNovember 8, 2021 with an updated schedule for the years 2022 through 2028, which included additional information as required by PURA. As required, the plan includes a full deployment of advanced metering functionality and a composite business case in support of the Advanced Metering Infrastructure plan. The procedural schedule includes briefs that were filed onApril 29, 2022 , written comments that were filedJuly 20, 2022 , and a technical session onSeptember 14, 2022 . CL&P Rate Relief Plan: OnNovember 28, 2022 ,Governor Lamont , DEEP,Office of Consumer Counsel , andCL&P jointly developed a rate relief plan for electric customers for the winter peak season ofJanuary 1, 2023 throughApril 30, 2023 . OnDecember 16, 2022 , PURA approved the rate relief plan. As part of the rate relief plan,CL&P reduced the Non-Bypassable Federally Mandated Congestion Charge (NBFMCC) rate effectiveJanuary 1, 2023 to provide customers with an average$10 monthly bill credit from January throughApril 2023 . This rate reduction accelerates the return to customers of net revenues generated by long-term state-approved energy contracts with the Millstone andSeabrook nuclear power plants of approximately$90 million . The rate relief plan also included instituting a temporary, flat monthly discount for qualifying low-income hardship customers effectiveJanuary 1, 2023 . This flat-rate credit will continue until a new low-income discount rate that was approved by PURA in anOctober 19, 2022 decision is implemented in 2024. These aspects of the rate relief plan do not impactCL&P's earnings but do impact its future cash flows. Also as part of the rate relief plan,CL&P committed to contribute$10 million to an energy assistance program for qualifying hardship customers, which is expected to be distributed as a bill credit to those customers by the end of the first quarter of 2023.CL&P recorded a current liability of$10 million on the balance sheet and a charge to expense on the statement of income for the year endedDecember 31, 2022 associated with the customer assistance program. CL&P Performance Based Rate Making: OnMay 26, 2021 , in accordance with anOctober 2020 Connecticut law, PURA opened a proceeding to begin to evaluate and eventually implement performance based regulation for electric distribution companies. PURA will conduct the proceeding in two phases, with a draft decision on the first phase expected inMarch 2023 and then a procedural schedule established for the second phase. OnJanuary 25, 2023 , PURA staff issued a proposal outlining a suggested portfolio of performance based regulation elements for further exploration and implementation in the second phase of the proceeding. At this time, we cannot predict the ultimate outcome of this proceeding and the resulting impact toCL&P . 38 --------------------------------------------------------------------------------Aquarion Water Company of Connecticut Distribution Rate Case: OnAugust 29, 2022 ,Aquarion Water Company of Connecticut (AWC-CT) filed an application with PURA to amend its existing rate schedules to address an operating revenue deficiency. AWC-CT's rate application requested approval of rate increases of$27.5 million , an additional$13.6 million , and an additional$8.8 million , effectiveMarch 15, 2023 , 2024, and 2025, respectively. A final decision from PURA is expectedMarch 15, 2023 .
NSTAR Electric Distribution Rates: As part of an inflation-based mechanism,
NSTAR Electric Distribution Rate Case: OnNovember 30, 2022 , the DPU issued its decision in theNSTAR Electric distribution rate case and approved a base distribution rate increase of$64 million effectiveJanuary 1, 2023 . The DPU approved a renewal of the performance-based ratemaking (PBR) plan originally authorized in its previous rate case for a five-year term, with a corresponding stay out provision. The PBR plan term has the possibility of a five-year extension. The PBR mechanism allows for an annual adjustment to base distribution rates for inflation and exogenous events. The DPU also allowed for adjustments to the PBR mechanism for the recovery of future capital additions based on a historical five-year average of total capital additions, beginning with theJanuary 1, 2024 PBR adjustment. The decision allows an authorized regulatory ROE of 9.80 percent on a capital structure including 53.2 percent equity. Among other items, the DPU approved an increase to the annual storm fund contribution collected through base distribution rates from$10 million to$31 million , and allowed for the recovery of storm threshold costs of$1.3 million per storm event subsequent to the eighth storm in a calendar year (six recovered in base rates plus two additional storms). The DPU approved cost recovery of a portion ofNSTAR Electric's outstanding storm costs beginning onJanuary 1, 2023 andJanuary 1, 2024 , subject to reconciliation from future prudency reviews. In a subsequent compliance filing, the DPU allowed recovery to commence for outstanding storm costs occurring between 2018 and 2022 and interest in a total of$162.1 million over a five-year period startingJanuary 1, 2023 . In addition,NSTAR Electric will begin to recover 2021 exogenous storms and interest in a total of$220.9 million over a five-year period beginningJanuary 1, 2024 . The DPU also approved the recovery of historical exogenous property taxes of$30.8 million incurred from 2020 through 2022 over a two-year period and$8.3 million incurred from 2012 through 2015 over a five-year period effectiveJanuary 1, 2023 .NSTAR Electric's AMI Implementation Plan and a new Advanced Metering Infrastructure tariff (AMIF) reconciling mechanism effectiveJanuary 1, 2023 were also approved andNSTAR Electric will recover all meter-related capital now through the AMIF as opposed to base distribution rates. NSTAR Electric Grid Modernization Plan: OnOctober 7, 2022 , the DPU issued an order approving continuing investments from the initial 2018 to 2021 Grid Modernization Plan that were included in the 2022 to 2025 Grid Modernization Plan. The DPU established a preauthorized total budget cap of$162.6 million over the four-year plan period for these continuing investments. OnNovember 30, 2022 , the DPU issued an order that preauthorized a four-year$43.0 million budget for new grid-facing investments. All of the ongoing and new investments will have targeted cost recovery throughNSTAR Electric's annual grid modernization factor filings. NSTAR Electric Advanced Metering Infrastructure Plan: OnNovember 30, 2022 , the DPU approvedNSTAR Electric's proposed Advanced Metering Infrastructure customer-facing investment and implementation plan (including program operating costs), including a full deployment of advanced metering functionality, for the years 2022 through 2028. The DPU established preauthorized total budget caps of$534.8 million for core AMI investments and corresponding operating costs and$133.1 million for supporting AMI investments and corresponding operating costs over the seven-year plan period. The DPU approved a new AMIF tariff reconciling mechanism effectiveJanuary 1, 2023 to recover eligible costs associated with both AMI customer-facing investments and implementation costs. Investments above these budget caps can be recovered in a future base distribution rate proceeding. NSTAR Electric Transmission Support Agreement: OnJune 17, 2022 ,FERC approved a transmission support agreement betweenNSTAR Electric andPark City Wind LLC (PCW). The agreement commitsNSTAR Electric to construct certain transmission facilities required to interconnect PCW's future 800 MW offshore wind generation facility toNSTAR Electric's transmission system. Of the total estimated$196 million project,NSTAR Electric will finance an estimated$152 million and earn a return on those specific investments over a ten-year period once the facility is in operation based on the authorized return that is in effect at the applicable time for regional transmission service under the ISO-NE Open Access Transmission Tariff. The interconnection transmission facilities are currently expected to be in-service in 2026. 39 -------------------------------------------------------------------------------- NSTAR Electric CIP Filing: OnDecember 30, 2022 , the DPU approved a provisional system planning tariff for the recovery of costs associated with a capital investment project (CIP) proposal submitted byNSTAR Electric for one of six geographic study areas in its service territory in accordance with DPU's directives. The DPU established a new, provisional framework for planning and funding upgrades to the electric power system to foster development and interconnection of distributed energy facilities. Under the DPU program,NSTAR Electric has filed infrastructure upgrade proposals to be built within a four-year construction timeframe that allocate the costs of interconnection upgrades between the interconnecting distributed generation facility and distribution customers. Payments made by the distributed generation facility will be applied against the total capital investment made byNSTAR Electric andNSTAR Electric will earn a return on the net investment. The amount allocated to distribution customers will be recovered through a reconciling mechanism, the Provisional System Planning Tariff. The DPU approved the first of these provisional system planning projects, theMarion -Fairhaven group study area, which will enable 141 MW of distributed energy to be interconnected at a total estimated cost of$119.7 million . Of the total$119.7 million ,$65.8 million will be allocated to distribution customers, once the enabled distributed energy facilities capacity is fully subscribed by distributed energy facilities interconnecting customers. Additionally,NSTAR Electric will proceed with construction of$54 million of transmission upgrades necessary to improve local reliability and integrate distribution energy resources in theMarion -Fairhaven area and recover the amount through local transmission rates. NSTAR Electric Electric Vehicles Program: OnDecember 30, 2022 ,NSTAR Electric received DPU approval for a new Phase 2 electric vehicle (EV) charging infrastructure program (including operating costs) totaling$188 million over a four-year period, which includes make-ready costs and other EV expenditures to support the deployment of charging ports and provides incentives for charging infrastructure installed at commercial and residential sites inMassachusetts .NSTAR Electric will recover the cost of this program through an Electric Vehicle Program tariff. NSTAR Gas Distribution Rates: As part of an inflation-based mechanism,NSTAR Gas submitted its second annual Performance Based Rate Adjustment filing onSeptember 15, 2022 and onOctober 31, 2022 , the DPU approved a$21.7 million increase to base distribution rates for effect onNovember 1, 2022 . The increase is inclusive of a$4.5 million permanent increase related to exogenous property taxes and a$5.4 million increase related to anOctober 6, 2021 mitigation plan filing that delayed recovery of a portion of a base distribution rate increase originally scheduled to take effectNovember 1, 2021 . The DPU also approved the recovery of historical exogenous property taxes incurred fromNovember 1, 2020 throughOctober 31, 2022 of$8.2 million over a two-year period through a separate reconciling mechanism effectiveNovember 1, 2022 . EGMA Distribution Rates: As established in anOctober 7, 2020 EGMA Rate Settlement Agreement approved by the DPU, onSeptember 16, 2022 EGMA filed for its second base distribution rate increase and onOctober 31, 2022 , the DPU approved a$6.7 million increase to base distribution rates and a$3.3 million increase to the Tax Act Credit Factor for effect onNovember 1, 2022 . The DPU also approved the recovery of historical exogenous property taxes incurred fromNovember 1, 2020 throughOctober 31, 2022 of$8.6 million over a two-year period through a separate reconciling mechanism effectiveNovember 1, 2022 . EGMA will request recovery of incremental property taxes incurred afterOctober 31, 2022 in future exogenous filings.New Hampshire : PSNH Distribution Rates: In connection with anOctober 9, 2020 settlement agreement, PSNH was permitted three step increases to reflect qualifying plant additions in calendar years 2019, 2020 and 2021. The first two step adjustments had effective dates ofJanuary 1, 2021 andAugust 1, 2021 , respectively. OnOctober 20, 2022 , the NHPUC approved the third step adjustment for 2021 plant in service to recover a revenue requirement of$8.9 million , with rates effectiveNovember 1, 2022 . The total approved revenue requirement increase is being collected over the remainder of the rate year (November 1, 2022 -July 31, 2023 ). PSNH Pole Acquisition Approval: OnNovember 18, 2022 , the NHPUC issued a decision that approved a proposed purchase agreement betweenPSNH and Consolidated Communications, in which PSNH would acquire approximately 343,000 jointly-owned utility poles and approximately 3,800 solely-owned poles and pole assets. The NHPUC also authorized PSNH to recover certain expenses associated with the operation and maintenance of the transferred poles, pole inspections, and vegetation management expenses through a new cost recovery mechanism, the Pole Plant Adjustment Mechanism (PPAM), subject to consummation of the purchase agreement. OnDecember 16, 2022 , a motion for rehearing of NHPUC's approval was filed by an intervenor, which was denied by the NHPUC onFebruary 8, 2023 . PSNH cannot predict the timing of consummation of the proposed purchase agreement. PSNH Energy Efficiency Plan: OnNovember 12, 2021 , the NHPUC issued an order rejecting the proposed 2021 through 2023 energy efficiency plan and significantly reduced funding and operational functions of the program. The order eliminated the recovery of performance incentives and made other key changes to the energy efficiency plan beginning in 2022. PSNH sought a rehearing of the order and was denied, which resulted in PSNH filing a formal appeal to theNew Hampshire Supreme Court . OnFebruary 10, 2022 , the NHPUC issued an order that restored the 2022 energy efficiency rate to be consistent with the 2021 rate, which PSNH implemented effectiveMarch 1, 2022 . OnFebruary 24, 2022 , state legislation was signed into law that undid the most impactful effects of theNovember 12, 2021 NHPUC order. The legislation directed that the joint utility energy efficiency plan and programming framework in effect onJanuary 1, 2021 be utilized going forward, including utility performance incentive payments, lost base revenue calculations, and Evaluation, Measurement, and Verification process. Additionally, the legislation established a process for future plan proposals, including the 2024 through 2026 triennial plan, and includes a mechanism for future rate increases based on the consumer price index. As a result of the new legislation passed specific to this order, PSNH withdrew its appeal to theNew Hampshire Supreme Court . PSNH made the required filing for the remainder of the 2022 through 2023 triennial plan onMarch 1, 2022 , which was approved as filed by the NHPUC onApril 29, 2022 . 40 --------------------------------------------------------------------------------
Legislative and Policy Matters
Massachusetts : OnAugust 11, 2022 ,Governor Baker signed into law climate-related legislation which, among other things, affirms the state's commitment to contract for 5,600 MW of offshore wind byJune 30, 2027 , modifies the bidding process to encourage more competition among offshore wind developers, and provides incentives to increase the manufacturing and assembly of offshore wind components inMassachusetts . The law also provides incentives to encourage the sale and leasing of electric vehicles, promotes energy storage and electrification technologies, directs electric companies to develop grid modernization plans to upgrade distribution and transmission facilities, and initiates a pilot program that would allow up to ten communities in the state to restrict fossil fuel use in new buildings. Additionally, for long-term contracts that are approved by the DPU between developers of offshore wind generation and the contracting electric distribution company, the law provides for an annual remuneration for the distribution company equal to 2.25 percent of the annual payments under the contract to compensate the distribution company for accepting the financial obligation of the long-term contract. Federal: OnAugust 16, 2022 , the Inflation Reduction Act of 2022 (IRA) was signed into law. This is a broad package of legislation that includes incentives and support for clean energy resource development. Most notable for Eversource, the investment tax credit (ITC) on offshore wind projects increases from 30 percent to 40 percent if certain requirements for labor and domestic content are met. The act also re-establishes the production tax credit for solar and wind energy projects, gives increased credit for projects in certain communities, and sets credits for qualifying clean energy generation and energy storage projects. The tax provisions of the IRA provide additional incentives for offshore wind projects and could reduce retail electricity costs for our customers related to those clean energy investments. The IRA includes other tax provisions focused on implementing a 15 percent minimum tax on adjusted financial statement income and a one percent excise tax on corporate share repurchases. TheDepartment of Treasury and the Internal Revenue Service issued limited guidance in the fourth quarter; however, they are expected to issue additional needed guidance with respect to the application of the newly enacted IRA provisions in the future. We will continue to monitor and evaluate impacts on our consolidated financial statements. We currently do not expect the alternative minimum tax change to have a material impact on our earnings, financial condition or cash flows.
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 ourBoard 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 make judgments regarding the future outcome of regulatory proceedings that involve potential future refund to customers and record liabilities for these loss contingencies when probable and reasonably estimable based upon available information. Regulatory liabilities are recorded at the best estimate, or at a low end of the range of possible loss. The amount recorded may differ from when the uncertainty is resolved. Such differences could have a significant impact on our financial statements. We continually assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or refund. This assessment includes consideration of recent orders issued by regulatory commissions, the passage of new legislation, historical regulatory treatment for similar costs in each of our jurisdictions, discussions with legal counsel, the status of any appeals of regulatory decisions, and changes in applicable regulatory and political environments. We believe that we will continue to be able to defer and recover prudently incurred costs, including additional storm costs, based on the legal and regulatory framework. 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. The ultimate outcome of regulatory rate proceedings could have a significant effect on our ability to recover costs or earn an adequate return. Established rates are also often subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed. Storm restoration and pre-staging costs are subject to prudency reviews from our regulators. We have approximately$1.4 billion of deferred storm costs that either have yet to be filed with the applicable regulatory commission, are pending regulatory approval, or are subject to prudency review as ofDecember 31, 2022 . Tropical Storm Isaias resulted in deferred storm restoration costs of approximately$235 million atCL&P as ofDecember 31, 2022 . While it is possible that some amount of the Tropical Storm Isaias costs may be disallowed by PURA in a future proceeding, any such 41 --------------------------------------------------------------------------------
amount cannot be estimated at this time. We believe that our storm restoration costs were prudently incurred, meet the criteria for cost recovery and are probable of recovery.
We believe it is probable that each of our 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. Plan assets and the benefit obligation are presented on a net basis and we recognize the overfunded or underfunded status of the plans as an asset or liability on the balance sheet. These amounts are remeasured annually using aDecember 31st measurement date. For each of these plans, several significant assumptions are used to determine the projected benefit obligation, funded status and net periodic benefit expense/income. 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 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 Assumption: 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 endedDecember 31, 2022 , 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 2023 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 Assumptions: 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 ofDecember 31, 2022 , the discount rates used to determine the funded status were within a range of 5.1 percent to 5.2 percent for the Pension and SERP Plans, and 5.2 percent for the PBOP Plans. As ofDecember 31, 2021 , the discount rates used were within a range of 2.8 percent to 3.0 percent for the Pension and SERP Plans, and within a range of 2.91 percent to 2.92 percent for the PBOP Plans. The increase in the discount rates used to calculate the funded status resulted in a decrease to the Pension and SERP Plans' projected benefit obligation and the PBOP Plans' projected benefit obligation of$1.48 billion and$180.1 million , respectively, as ofDecember 31, 2022 . 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 2022 expense were within a range of 2.2 percent to 3.2 percent for the Pension and SERP Plans, and within a range of 2.3 percent to 3.3 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. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. In 2022, our mortality assumption utilized theSociety of Actuaries base mortality tables (Pri-2012), adjusted to reflect Eversource's own mortality experience, and projected generationally using the MP-2021 improvement scale. Compensation/Progression Rate Assumptions: 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 will receive in the future. As ofDecember 31, 2022 and 2021, the compensation/progression rates used to determine the funded status were within a range of 3.5 percent to 4.0 percent. Health Care Cost Assumptions: The Eversource Service PBOP Plan is not subject to health care cost trends. As ofDecember 31, 2022 , for the Aquarion PBOP Plan, the health care trend rate used to determine the funded status for pre-65 retirees is 7 percent, with an ultimate rate of 5 percent in 2031, and for post-65 retirees, the health care trend rate and ultimate rate is 3.5 percent. Actuarial Gains and Losses: Actuarial gains and losses represent the differences between actuarial assumptions and actual information or updated assumptions. Unamortized actuarial gains or losses arising at theDecember 31st measurement date are primarily from differences in actual investment performance compared to our expected return and changes in the discount rate assumption. The Eversource Service Pension and PBOP Plans use the corridor approach to determine the amount of gain or loss to amortize into net periodic benefit expense/income. The corridor approach defers all actuarial gains and losses arising at remeasurement and the net unrecognized actuarial gain or loss balance is amortized as a component of expense if, as of the beginning of the year, that net gain or loss exceeds 10 percent of the greater of the market value of the plan's assets or the projected benefit obligation. The amount of net unrecognized actuarial gain or loss in excess of the 10 percent corridor is amortized to expense over the estimated average future employee service period. For the Eversource Service Pension Plan, the net actuarial gain or loss is amortized as a component of expense over the estimated average future employee service period of seven years. For the Eversource Service PBOP Plan, the net unrecognized actuarial gain or loss was within the 10 percent corridor and therefore there was no amortization to expense during 2022. 42 -------------------------------------------------------------------------------- An increase in the discount rate used to determine our pension funded status would decrease our projected benefit obligation atDecember 31st , resulting in a lower unamortized actuarial loss to be recognized in future years' pension expense, subject to exceeding the 10 percent corridor. An increase in the discount rate atDecember 31st would also result in an increase in the interest cost component and a decrease in the service cost component of the subsequent year's benefit plan expense. The calculated expected return on plan assets 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.
An underperformance of our pension plan investment returns relative to the
expected returns would increase our pension liability at
Net Periodic Benefit Expense/Income: Pension, SERP and PBOP expense/income is determined by our actuaries and consists of service cost and prior service cost/credit, interest cost based on the discounting of the obligations, amortization of actuarial gains and losses, and the expected return on plan assets. For the Pension and SERP Plans, pre-tax net periodic benefit income was$181.6 million for the year endedDecember 31, 2022 , and there was pre-tax net periodic benefit expense of$23.6 million and$56.9 million for the years endedDecember 31, 2021 and 2020, respectively. For the PBOP Plans, pre-tax net periodic benefit income was$79.8 million ,$60.5 million and$51.6 million for the years endedDecember 31, 2022 , 2021 and 2020, respectively. The change in pension, SERP and PBOP expense/income arising from the annual remeasurement does not fully impact earnings. OurMassachusetts utilities recover qualified pension and PBOP expenses related to their distribution operations through a rate reconciling mechanism that fully tracks the change in net pension and PBOP expenses each year, therefore the change in their pension and PBOP expense does not impact earnings. Our electric transmission companies' rates provide for an annual true-up of estimated to actual costs, which include pension and PBOP expenses, therefore the change in their pension and PBOP expense does not impact earnings. Additionally, the portion of our pension and PBOP expense that relates to company labor devoted to capital projects is capitalized on the balance sheet instead of being charged to expense. Forecasted Expense/Income and Expected Contributions: We estimate that net periodic benefit income in 2023 for the Pension and SERP Plans will be approximately$114 million and for the PBOP Plans will be approximately$57 million . The change in pension income from 2022 to 2023 is driven primarily by an increase in the interest cost component due to a higher discount rate and lower expected return on assets due to a lower asset balance, partially offset by lower amortization of actuarial losses due to unrecognized actuarial gains arising in 2022. The change in PBOP income from 2022 to 2023 is driven primarily by an increase in the interest cost component due to a higher discount rate and lower expected return on assets due to a lower asset balance. For the PBOP Plans, there is no amortization of actuarial losses in 2023. Pension, SERP and PBOP expense/income 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$80.0 million to the Pension Plans in 2022. Based on the current status of the Pension Plans and federal pension funding requirements, there is no minimum funding requirement for our Eversource Service Pension Plan in 2023 and we do not expect to make pension contributions in 2023. It is our policy to fund the PBOP Plans annually through tax deductible contributions to external trusts. We do not expect to make any contributions to the Eversource Service PBOP Plan in 2023. We contributed$3.1 million to the Aquarion PBOP Plan in 2022. We currently estimate contributing$5.0 million and$2.9 million to the Aquarion Pension and PBOP Plans, respectively in 2023. Sensitivity Analysis: The following table illustrates the hypothetical effect on reported annual net periodic benefit income as a result of a change in the following assumptions by 50 basis points: Pension Plans (excluding SERP Plans) PBOP Plans Decrease in Plan Increase in Plan Income Expense Decrease in Plan Income (Millions of Dollars) For the Years Ended December 31, For the Years Ended December 31, Eversource 2022 2021 2022 2021 Lower expected long-term rate $ 32.5 $ 26.5 $ 5.6$ 4.8 of return Lower discount rate 32.6 27.0 1.7 2.6 Higher compensation rate 7.6 9.9 N/A N/AGoodwill : We recorded goodwill on our balance sheet associated with previous mergers and acquisitions, all of which totaled$4.52 billion as ofDecember 31, 2022 . 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 ofCL&P ,NSTAR Electric and PSNH. The Natural Gas Distribution reporting unit includes the carrying values ofNSTAR Gas ,Yankee Gas and EGMA. The Water Distribution reporting unit includes the Aquarion water utility businesses. As ofDecember 31, 2022 , goodwill was allocated to the reporting units as follows:$2.54 billion to Electric Distribution,$577 million to Electric Transmission,$451 million to Natural Gas Distribution and$951 million to Water Distribution.Goodwill recorded and allocated to the Water Distribution reporting unit included$44.8 million in 2022 arising from the acquisition ofThe Torrington Water Company onOctober 3, 2022 and$22.2 million arising from the acquisition of NESC onDecember 1, 2021 , which included measurement period increases in 2022 totaling$0.5 million . 43 -------------------------------------------------------------------------------- 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. Additionally, we monitor all relevant events and circumstances during the year to determine if an interim impairment test is required. We have selectedOctober 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. In assessing goodwill for impairment, an entity is permitted to first assess qualitatively whether it is more likely than not that goodwill impairment exists as of the annual impairment test date. A quantitative impairment test is required only if it is concluded that it is more likely than not that a reporting unit's fair value is less than its carrying amount. We performed an impairment assessment of goodwill as ofOctober 1, 2022 for the Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution reporting units. Our qualitative assessment included an evaluation of multiple factors that impact the fair value of the reporting units, including general, macroeconomic and market conditions, and entity-specific assumptions that affect the future cash flows of the reporting units. Key considerations include discount rates, utility sector market performance and merger transaction multiples, the Company's share price and credit ratings, analyst reports, financial performance, cost and risk factors, internal estimates and projections of future cash flows and net income, long-term strategy, the timing and outcome of rate cases, and recent regulatory and legislative proceedings. The 2022 goodwill impairment assessment resulted in a conclusion that goodwill is not impaired and no reporting unit is at risk of a goodwill impairment. We believe that the fair value of the reporting units was substantially in excess of carrying value. Adverse regulatory actions, changes in the regulatory and political environment, or changes in significant assumptions could potentially result in future goodwill impairment indicators. 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. An 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. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. No impairments occurred during the year 2022. 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 is 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 at the equity method investment level, selecting discount rates used to determine fair values, and developing an estimate of discounted future cash flows expected from investment operations or the sale of the investment. No impairments occurred during 2022. Eversource continually monitors and evaluates its equity method investments to determine if there are indicators of an other-than-temporary impairment. 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, 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. The interpretation of tax laws and associated regulations involves uncertainty since tax authorities may interpret the laws differently. Ultimate resolution or clarification of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material. Significant management judgment is required in determining the provision for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. We evaluate the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and our intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. We also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the 44 -------------------------------------------------------------------------------- inability to realize the deferred tax assets. Valuation allowances are provided to reduce deferred tax assets to the amount that will more likely than not be realized in future periods. This requires management to make judgments and estimates regarding the amount and timing of the reversal of taxable temporary differences, expected future taxable income, and the impact of tax planning strategies. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, not realizing expected tax planning strategy amounts, as well as results of audits and examinations of filed tax returns by taxing authorities. 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," 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, AROs, and in the valuation of business combinations and asset acquisitions. 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-related products in future years and assumptions 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-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. 45 -------------------------------------------------------------------------------- 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
For the Years Ended December 31, (Millions of Dollars) 2022 2021 Increase Operating Revenues$ 12,289.3 $ 9,863.1 $ 2,426.2 Operating Expenses:Purchased Power ,Purchased Natural Gas and Transmission 5,014.1 3,372.3 1,641.8 Operations and Maintenance 1,865.3 1,739.7 125.6 Depreciation 1,194.2 1,103.0 91.2 Amortization 448.9 232.0 216.9 Energy Efficiency Programs 658.0 592.8 65.2 Taxes Other Than Income Taxes 910.6 830.0 80.6 Total Operating Expenses 10,091.1 7,869.8 2,221.3 Operating Income 2,198.2 1,993.3 204.9 Interest Expense 678.3 582.4 95.9 Other Income, Net 346.1 161.3 184.8 Income Before Income Tax Expense 1,866.0 1,572.2 293.8 Income Tax Expense 453.6 344.2 109.4 Net Income 1,412.4 1,228.0 184.4 Net Income Attributable to Noncontrolling Interests 7.5 7.5 - Net Income Attributable to Common Shareholders$ 1,404.9 $ 1,220.5 $ 184.4 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: ElectricFirm Natural Gas Water Sales Volumes (GWh) Percentage Sales Volumes (MMcf) Percentage Sales Volumes (MG) Percentage 2022 2021 (Decrease)/Increase 2022 2021 Increase 2022 2021 Increase Traditional 7,764 7,782 (0.2) % - - - % 1,857 1,256 47.9 % Decoupled and Special Contracts (1) 43,493 43,228 0.6 % 152,291 150,145 1.4 % 23,154 22,099 4.8 % Total Sales Volumes 51,257 51,010 0.5 % 152,291 150,145 1.4 % 25,011 23,355 7.1 %
(1) Special contracts are unique to
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). ForCL&P ,NSTAR Electric ,NSTAR Gas , EGMA,Yankee Gas , and ourConnecticut 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. 46 -------------------------------------------------------------------------------- Operating Revenues: Operating Revenues by segment increased in 2022, as compared to 2021, as follows: (Millions of Dollars) Increase/(Decrease) Electric Distribution $ 1,981.7 Natural Gas Distribution 426.0 Electric Transmission 174.1 Water Distribution 11.2 Other 81.5 Eliminations (248.3) Total Operating Revenues $ 2,426.2 Electric and Natural Gas (excluding EGMA) Distribution Revenues: Base Distribution Revenues: •Base electric distribution revenues increased$43.4 million in 2022, as compared to 2021, due primarily to the impact of base distribution rate increases atNSTAR Electric effectiveJanuary 1, 2022 resulting from its annual Performance Based Rate Adjustment filing and at PSNH effectiveAugust 1, 2021 andNovember 1, 2022 . •Base natural gas distribution revenues (excluding EGMA) increased$21.4 million in 2022, as compared to 2021, due primarily to base distribution rate increases atNSTAR Gas effectiveNovember 1, 2021 andNovember 1, 2022 . Electric distribution revenues atCL&P also increased$93.4 million in 2022, as compared to 2021, due to the absence of a 2021 reserve established to provide bill credits to customers as a result ofCL&P's settlement agreement onOctober 1, 2021 and a storm performance penalty assessed by PURA. In the 2021 settlement agreement,CL&P agreed to provide a total of$65 million of customer credits, which were distributed based on customer sales over a two-month period fromDecember 1, 2021 toJanuary 31, 2022 . Additionally,CL&P recorded a$28.4 million reserve in 2021 for a civil penalty for non-compliance with storm performance standards that was provided as credits to customers on electric bills beginning onSeptember 1, 2021 over a one-year period. 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. Revenues from certain of these cost tracking mechanisms also include certain incentives earned, return 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), certain capital tracking mechanisms for infrastructure improvements, and additionally for theMassachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs. Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market, sales of natural gas to third party marketers, and the sale of RECs to various counterparties. Customers have the choice to purchase electricity from each Eversource electric utility or from a competitive third party supplier. For customers who have contracted separately with these competitive suppliers, revenue is not recorded for the sale of the electricity commodity, as the utility is acting as an agent on behalf of the third party supplier. For customers that choose to purchase electric generation fromCL&P ,NSTAR Electric or PSNH, each purchases power on behalf of, and is permitted to recover the related energy supply cost without mark-up from, its customers, and records offsetting amounts in revenues and purchased power and amortization expense related to this energy supply procurement.CL&P ,NSTAR Electric and PSNH each remain as the distribution service provider for all customers and charge a regulated rate for distribution delivery service recorded in revenues.
Tracked distribution revenues increased/(decreased) in 2022, as compared to 2021, due primarily to the following:
(Millions of Dollars) Electric Distribution Natural Gas Distribution Retail Tariff Tracked Revenues: Energy supply procurement $ 1,032.9 $ 144.1 Retail transmission 246.8 - CL&P FMCC (87.8) - Energy efficiency 52.9 (1.4) Stranded costs (72.5) - Other distribution tracking mechanisms 49.8 31.7 Wholesale Market Sales Revenue 615.1 33.3 The increase in energy supply procurement within electric distribution and natural gas distribution in 2022, as compared to 2021, was driven by higher average prices and higher average supply-related sales volumes. Fluctuations in retail transmission revenues are driven by the recovery of the costs of our wholesale transmission business, such as those billed by ISO-NE and Local and Regional Network Service charges. For further information, see "Purchased Power ,Purchased Natural Gas and Transmission Expense" below. 47 -------------------------------------------------------------------------------- The increase in electric distribution wholesale market sales revenue in 2022, as compared to 2021, was due primarily to higher average electricity market prices received for wholesale sales atCL&P ,NSTAR Electric and PSNH. ISO-NE average market prices received forCL&P's wholesale sales increased approximately 90 percent in 2022, as compared to 2021, driven primarily by higher natural gas prices inNew England . The increase was also due to higher wholesale sales volumes atCL&P resulting from the sale of output generated by the Seabrook PPA beginning in the first quarter of 2022. Volumes sold into the market were primarily from the sale of output generated by the Millstone PPA andSeabrook PPA thatCL&P entered into in 2019, as required by regulation.CL&P sells the energy purchased from Millstone andSeabrook into the wholesale market and uses the proceeds from the energy sales to offset the contract costs. The net sales or net cost amount is refunded to, or recovered from, customers in the non-bypassable component of the CL&P FMCC rate. The increase in electric distribution wholesale market sales revenues was also driven by higher proceeds from the sale of transmission rights over a one-year period underCL&P's ,NSTAR Electric's and PSNH'sHydro-Quebec transmission support agreements. Proceeds from these sales are credited back to customers. The decrease inCL&P's FMCC revenues and PSNH's stranded cost revenues was driven by decreases in the retail rate, which reflect the net benefit of higher wholesale market sales received in the ISO-NE market for long-term state approved energy contracts atCL&P and PSNH, which are then credited back to customers through these retail rates. The decrease in PSNH's stranded cost revenues was also due to lower stranded costs to be recovered due to higher Regional Greenhouse Gas Initiative (RGGI) proceeds received, which are credited back to customers. EGMA Natural Gas Distribution Revenues: EGMA total operating revenues at the natural gas distribution segment increased by$193.8 million in 2022, as compared to 2021. Included in the total operating revenues increase was EGMA's base natural gas distribution revenues increase of$26.3 million in 2022, as compared to 2021, due primarily to base distribution rate increases effectiveNovember 1, 2021 andNovember 1, 2022 . Electric Transmission Revenues: Electric transmission revenues increased$174.1 million in 2022, as compared to 2021, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure. Other Revenues and Eliminations: Other revenues primarily include the revenues of Eversource's service company, most of which are eliminated in consolidation. Eliminations are also primarily related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses ofCL&P ,NSTAR Electric and PSNH that recover the costs of the wholesale transmission business in rates charged to their customers.
These electric and natural gas supply costs and other energy-related costs are recovered from customers in rates through commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs).Purchased Power ,Purchased Natural Gas and Transmission expense increased in 2022, as compared to 2021, due primarily to the following: (Millions of Dollars) Increase Purchased Power Costs$ 1,217.5 Natural Gas Costs 307.7 Transmission Costs 277.1 Eliminations (160.5)
The increase in purchased power expense at the electric distribution business in 2022, as compared to 2021, was driven primarily by higher energy supply procurement costs resulting from higher average prices and higher average supply-related sales volumes, as well as higher long-term contractual energy-related costs that are recovered in the non-bypassable component of the FMCC mechanism atCL&P , and higher net metering costs atNSTAR Electric andCL&P .
The increase in costs at the natural gas distribution segment in 2022, as compared to 2021, was due primarily to higher average prices and higher average supply-related sales volumes.
The increase in transmission costs in 2022, as compared to 2021, was primarily the result of an increase resulting from the retail transmission cost deferral, which reflects the actual cost of transmission service compared to estimated amounts billed to customers. This was partially offset by a decrease in Local Network Service charges, which reflects the cost of transmission service provided by Eversource over our local transmission network, and a decrease in costs billed by ISO-NE that support regional grid investments. 48 -------------------------------------------------------------------------------- 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 2022, as compared to 2021, due primarily to the following: (Millions of Dollars)
Increase/(Decrease)
Base Electric Distribution (Non-Tracked Costs): General costs (including vendor services in corporate areas, insurance, fees and assessments) $ 26.8
Shared corporate costs (including computer software depreciation at Eversource
25.0
Service)
Storm costs 22.0
Commitment to energy assistance program as part of
10.0
Operations-related expenses (including vegetation management, vendor services and
4.4
vehicles)
Employee-related expenses, including labor and benefits (20.5)
Absence in 2022 of
(10.0)
associated with the settlement agreement on
20.3 Total Base Electric Distribution (Non-Tracked Costs) 78.0
Tracked Electric Costs (Electric Distribution and Electric Transmission) -
Increase due primarily to higher transmission expenses of
72.4 Total Electric Distribution and Electric Transmission 150.4 Natural Gas Distribution: Base (Non-Tracked Costs) - Increase due primarily to higher employee-related expenses and higher shared corporate costs 12.6 Tracked Costs 18.6 Total Natural Gas Distribution 31.2 Water Distribution 8.3 Parent and Other Companies and Eliminations: Eversource Parent and Other Companies - other operations and maintenance 30.5 Transaction and Transition Costs (11.8) Eliminations (83.0) Total Operations and Maintenance $ 125.6
Depreciation expense increased in 2022, as compared to 2021, due to higher utility plant in service balances.
Amortization expense includes the deferral of energy supply, energy-related costs and other costs that are included in certain regulatory commission-approved cost tracking mechanisms. This deferral adjusts expense to match the corresponding revenues compared to the actual costs incurred. Energy supply and energy-related costs are recovered from customers in rates and have no impact on earnings. Amortization expense also includes the amortization of certain costs as those costs are collected in rates. Amortization increased in 2022, as compared to 2021, due primarily to the deferral adjustment of energy supply, energy-related and other tracked costs atCL&P (included in the non-bypassable component of the FMCC mechanism), andNSTAR Electric , which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. The increase in the FMCC mechanism atCL&P was driven primarily by the net costs and benefits of the long-term state approved contracts that Eversource has executed with Millstone andSeabrook , among others. The increase was partially offset by a decrease in storm amortization expense atCL&P related to the completion of the amortization period of certain storm cost deferred assets. Energy Efficiency Programs expense increased in 2022, as compared to 2021, due primarily to the deferral adjustment, 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 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 2022, as compared to 2021, due primarily to an increase in property taxes as a result of higher utility plant balances and higherConnecticut gross earnings taxes. Interest Expense increased in 2022, as compared to 2021, due primarily to an increase in interest on long-term debt as a result of new debt issuances ($101.3 million ), an increase in interest on short-term notes payable ($10.9 million ), an increase in interest expense on regulatory deferrals ($6.7 million ), and higher amortization of debt discounts and premiums, net ($3.3 million ), partially offset by an increase in capitalized AFUDC related to debt funds and other capitalized interest ($20.0 million ), lower interest resulting from the 2022 payment of withheld property taxes atNSTAR Electric ($5.0 million ), and a decrease in RRB interest expense ($1.4 million ). Other Income, Net increased in 2022, as compared to 2021, due primarily to an increase related to pension, SERP and PBOP non-service income components ($135.4 million ), an increase in interest income primarily from regulatory deferrals ($24.9 million ), an increase in capitalized AFUDC related to equity funds ($10.0 million ), an increase in equity in earnings related to Eversource's equity method investments ($8.7 million ), a gain on the sale of property in 2022 ($2.5 million ) and investment income in 2022 compared to investment losses in 2021 driven by market volatility ($2.1 million ). 49 -------------------------------------------------------------------------------- Income Tax Expense increased in 2022, as compared to 2021, due primarily to higher pre-tax earnings ($61.7 million ), higher state taxes ($5.9 million ), lower share-based payment excess tax benefits ($1.9 million ), an increase in return to provision adjustments ($11.2 million ), a decrease in amortization of EDIT ($20.0 million ), an increase in valuation allowances ($8.5 million ), and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($0.2 million ). RESULTS OF OPERATIONS - THE CONNECTICUT LIGHT AND POWER COMPANY NSTAR ELECTRIC COMPANY AND SUBSIDIARY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES The following provides the amounts and variances in operating revenues and expense line items in the statements of income forCL&P ,NSTAR Electric and PSNH for the years endedDecember 31, 2022 and 2021 included in this Annual Report on Form 10-K: For the Years Ended December 31, CL&P NSTAR Electric PSNH Increase/ Increase/ (Millions of Dollars) 2022 2021 Increase 2022 2021 (Decrease) 2022 2021 (Decrease) Operating Revenues$ 4,817.7 $ 3,637.4
1,393.0 717.3 1,264.8 932.5 332.3 665.5 370.3 295.2 Operations and Maintenance 707.2 644.2 63.0 640.8 563.2 77.6 256.0 237.7 18.3 Depreciation 355.5 338.9 16.6 362.0 337.5 24.5 128.0 120.1 7.9 Amortization of Regulatory Assets, Net 335.6 99.0 236.6 83.9 55.8 28.1 42.9 86.8 (43.9) Energy Efficiency Programs 134.2 129.6 4.6 332.3 288.6 43.7 37.4 38.7 (1.3) Taxes Other Than Income Taxes 384.7 363.8 20.9 246.7 216.7 30.0 95.3 91.5 3.8 Total Operating Expenses 4,027.5 2,968.5 1,059.0 2,930.5 2,394.3 536.2 1,225.1 945.1 280.0 Operating Income 790.2 668.9 121.3 652.6 662.1 (9.5) 249.7 232.1 17.6 Interest Expense 169.4 166.1 3.3 162.9 146.0 16.9 59.5 57.0 2.5 Other Income, Net 83.3 30.2 53.1 142.7 74.8 67.9 32.7 14.6 18.1 Income Before Income Tax Expense 704.1 533.0 171.1 632.4 590.9 41.5 222.9 189.7 33.2 Income Tax Expense 171.2 131.3 39.9 140.0 114.3 25.7 51.3 39.4 11.9 Net Income$ 532.9 $ 401.7 $ 131.2 $ 492.4 $ 476.6 $ 15.8 $ 171.6 $ 150.3 $ 21.3
Operating Revenues Sales Volumes: A summary of our retail electric GWh sales volumes is as follows:
For the Years Ended
Percentage 2022 2021 Increase/(Decrease) Increase/(Decrease) CL&P 20,560 20,501 59 0.3 % NSTAR Electric 22,933 22,727 206 0.9 % PSNH 7,764 7,782 (18) (0.2) % Fluctuations in retail electric sales volumes at PSNH impact earnings. ForCL&P andNSTAR 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$1.18 billion atCL&P ,$526.7 million atNSTAR Electric , and$297.6 million at PSNH in 2022, as compared to 2021. Base Distribution Revenues: •CL&P's distribution revenues increased$0.4 million . •NSTAR Electric's distribution revenues increased$36.9 million due primarily to the impact of its base distribution rate increase effectiveJanuary 1, 2022 resulting from its annual Performance Based Rate Adjustment filing. •PSNH's distribution revenues increased$6.1 million due primarily to the impact of its base distribution rate increases effectiveAugust 1, 2021 andNovember 1, 2022 . Electric distribution revenues atCL&P also increased$93.4 million in 2022, as compared to 2021, due to the absence of a 2021 reserve established to provide bill credits to customers as a result ofCL&P's settlement agreement onOctober 1, 2021 and a storm performance penalty assessed by PURA. In the 2021 settlement agreement,CL&P agreed to provide a total of$65 million of customer credits, which were distributed based on customer sales over a two-month period fromDecember 1, 2021 toJanuary 31, 2022 . Additionally,CL&P recorded a$28.4 million reserve in 2021 for a civil penalty for non-compliance with storm performance standards that was provided as credits to customers on electric bills beginning onSeptember 1, 2021 over a one-year period. 50 -------------------------------------------------------------------------------- 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. Revenues from certain of these cost tracking mechanisms also include certain incentives earned, return 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), certain capital tracking mechanisms for infrastructure improvements, and additionally forNSTAR Electric , pension and PBOP benefits, net metering for distributed generation, and solar-related programs. 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. Customers have the choice to purchase electricity from each Eversource electric utility or from a competitive third party supplier. For customers who have contracted separately with these competitive suppliers, revenue is not recorded for the sale of the electricity commodity, as the utility is acting as an agent on behalf of the third party supplier. For customers that choose to purchase electric generation fromCL&P ,NSTAR Electric or PSNH, each purchases power on behalf of, and is permitted to recover the related energy supply cost without mark-up from, its customers, and records offsetting amounts in revenues and purchased power and amortization expense related to this energy supply procurement.CL&P ,NSTAR Electric and PSNH each remain as the distribution service provider for all customers and charge a regulated rate for distribution delivery service recorded in revenues.
Tracked revenues increased/(decreased) in 2022, as compared to 2021, due primarily to the following:
(Millions of Dollars) CL&P NSTAR Electric
PSNH
Retail Tariff Tracked Revenues: Energy supply procurement$ 559.9 $ 178.4 $ 294.6 Retail transmission 110.6 155.1 (18.9) CL&P FMCC (87.8) - - Energy efficiency 7.2 41.9 3.8 Stranded costs 1.1 (14.6) (59.0) Other distribution tracking mechanisms 28.2 22.9
(1.3)
Wholesale Market Sales Revenue 464.9 105.8
44.4
The increase in energy supply procurement atCL&P was driven by higher average prices and higher average supply-related sales volumes. The increase in energy supply procurement atNSTAR Electric was driven by higher average prices, partially offset by lower average supply-related sales volumes. The increase in energy supply procurement at PSNH was driven by higher average prices. Fluctuations in retail transmission revenues are driven by the recovery of the costs of our wholesale transmission business, such as those billed by ISO-NE and Local and Regional Network Service charges. For further information, see "Purchased Power and Transmission Expense" below. The increase in wholesale market sales revenue in 2022, as compared to 2021, was due primarily to higher average electricity market prices received for wholesale sales atCL&P ,NSTAR Electric and PSNH. ISO-NE average market prices received forCL&P's wholesale sales increased approximately 90 percent in 2022, as compared to 2021, driven primarily by higher natural gas prices inNew England . The increase atCL&P was also due to higher wholesale sales volumes resulting from the sale of output generated by the Seabrook PPA beginning in the first quarter of 2022.CL&P's volumes sold into the market were primarily from the sale of output generated by the Millstone PPA and Seabrook PPA thatCL&P entered into in 2019, as required by regulation.CL&P sells the energy purchased from Millstone andSeabrook into the wholesale market and uses the proceeds from the energy sales to offset the contract costs. The net sales or net cost amount is refunded to, or recovered from, customers in the non-bypassable component of the CL&P FMCC rate. The increase in wholesale market sales revenues atCL&P ,NSTAR Electric and PSNH was also driven by higher proceeds from the sale of transmission rights over a one-year period underHydro-Quebec transmission support agreements. Proceeds from these sales are credited back to customers. The decrease inCL&P's FMCC revenues and PSNH's stranded cost revenues was driven by decreases in the retail rate, which reflect the net benefit of higher wholesale market sales received in the ISO-NE market for long-term state approved energy contracts atCL&P and PSNH, which are then credited back to customers through these retail rates. The decrease in PSNH's stranded cost revenues was also due to lower stranded costs to be recovered due to higher Regional Greenhouse Gas Initiative (RGGI) proceeds received, which are credited back to customers. Transmission Revenues: Transmission revenues increased$61.5 million atCL&P ,$73.5 million atNSTAR Electric and$39.1 million at PSNH in 2022, as compared to 2021, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure. Eliminations: Eliminations are primarily related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses ofCL&P ,NSTAR Electric and PSNH that recover the costs of the wholesale transmission business in rates charged to their customers. The impact of eliminations decreased revenues by$60.8 million atCL&P ,$78.6 million atNSTAR Electric and$12.9 million at PSNH in 2022, as compared to 2021. 51 --------------------------------------------------------------------------------Purchased Power and Transmission expense includes costs associated with purchasing electricity on behalf ofCL&P ,NSTAR Electric and PSNH's customers and the cost of energy purchase contracts, as required by regulation. These energy supply and other energy-related costs are recovered from customers in rates through commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs).Purchased Power and Transmission expense increased in 2022, as compared to 2021, due primarily to the following: (Millions of Dollars) CL&P NSTAR Electric PSNH Purchased Power Costs$ 650.6 $ 255.5 $ 311.4 Transmission Costs 125.1 155.4 (3.4) Eliminations (58.4) (78.6) (12.8)
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 atCL&P was due primarily to higher energy supply procurement costs resulting from higher average prices and higher average supply-related volumes. The increase was also due to higher long-term contractual energy-related costs and higher net metering costs that are recovered in the non-bypassable component of the FMCC mechanism. •The increase atNSTAR Electric was due primarily to higher energy supply procurement costs resulting from higher average prices, partially offset by lower supply-related sales volumes. The increase was also due to higher net metering costs. •The increase at PSNH was due primarily to higher energy supply procurement costs resulting from higher average prices. 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 increase in transmission costs atCL&P was due primarily to an increase resulting from the retail transmission cost deferral, which reflects the actual cost of transmission service compared to estimated amounts billed to customers. This was partially offset by a decrease in Local Network Service charges, which reflect the cost of transmission service provided by Eversource over our local transmission network, and a decrease in costs billed by ISO-NE that support regional grid investments. •The increase in transmission costs atNSTAR Electric was due primarily to an increase resulting from the retail transmission cost deferral, an increase in Local Network Service charges, and an increase in costs billed by ISO-NE. •The decrease in transmission costs at PSNH was due primarily to a decrease in costs billed by ISO-NE and a decrease in Local Network Service charges, partially offset by an increase resulting from 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 2022, as compared to 2021, due primarily to the following: (Millions of Dollars) CL&P NSTAR Electric PSNH Base Electric Distribution (Non-Tracked Costs): General costs (including vendor services in corporate areas,$ 12.3 $ 8.8$ 5.7
insurance, fees and assessments) Shared corporate costs (including computer software depreciation at Eversource Service)
8.7 13.2 3.1 Storm costs 9.0 9.5 3.5
Commitment to energy assistance program as part of
- - relief plan Operations-related expenses (including vegetation management, vendor services and vehicles) 3.1 2.2 (0.9)
Absence in 2022 of
(10.0) - -
Employee-related expenses, including labor and benefits (1.5)
(11.0) 0.5 Other non-tracked operations and maintenance 5.6 15.8 (1.1) Total Base Electric Distribution (Non-Tracked Costs) 37.2 38.5 10.8 Tracked Costs: Transmission expenses 19.4 7.4 8.3 Other tracked operations and maintenance 6.4 31.7 (0.8) Total Tracked Costs 25.8 39.1 7.5 Total Operations and Maintenance$ 63.0
$ 77.6
Depreciation expense increased in 2022, as compared to 2021, for
Amortization of Regulatory Assets, Net expense includes the deferral of energy supply, energy-related costs and other costs that are included in certain regulatory-approved cost tracking mechanisms. This deferral adjusts expense to match the corresponding revenues compared to the actual costs incurred. Energy supply and energy-related costs are recovered from customers in rates and have no impact on earnings. Amortization expense also includes the amortization of certain costs as those costs are collected in rates. Amortization of Regulatory Assets, Net increased/decreased in 2022, as compared to 2021, due primarily to the following: •The increase atCL&P was due primarily to the deferral adjustment of energy supply, energy-related and other tracked costs that are included in the non-bypassable component of the FMCC mechanism, which can fluctuate from period to period based on the timing of 52 -------------------------------------------------------------------------------- costs incurred and related rate changes to recover these costs. The increase in the FMCC mechanism was driven primarily by the net costs and benefits of the long-term state approved contracts thatCL&P executed with Millstone andSeabrook , among others. The increase was partially offset by a decrease in storm amortization expense related to the completion of the amortization period of certain storm cost deferred assets. •The increase atNSTAR Electric was due to the deferral adjustment of energy supply, energy-related costs and other tracked costs. •The decrease at PSNH was due to the deferral adjustment of energy-related and other tracked 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 2022, as compared to 2021, due primarily to the following: •The increases atCL&P andNSTAR Electric were 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 PSNH was due to the deferral adjustment and the timing of the recovery of energy efficiency costs.
Taxes Other Than Income Taxes increased in 2022, as compared to 2021, due primarily to the following:
•The increase atCL&P was related to higher property taxes as a result of a higher utility plant balance and higher gross earnings taxes. •The increases atNSTAR Electric and PSNH were due to higher property taxes as a result of higher utility plant balances.
Interest Expense increased in 2022, as compared to 2021, due primarily to the following:
•The increase atCL&P was due primarily to an increase in interest expense on regulatory deferrals ($3.4 million ), higher interest on long-term debt ($0.8 million ), and higher amortization of debt discounts and premiums, net ($0.3 million ), partially offset by an increase in capitalized AFUDC related to debt funds ($1.9 million ). •The increase atNSTAR Electric was due primarily to higher interest on long-term debt ($19.9 million ), an increase in interest expense on regulatory deferrals ($3.0 million ), and higher amortization of debt discounts and premiums, net ($0.5 million ), partially offset by lower interest resulting from the 2022 payment of withheld property taxes ($5.0 million ), and an increase in capitalized AFUDC related to debt funds ($1.7 million ). •The increase at PSNH was due primarily to higher interest expense on regulatory deferrals ($3.2 million ), higher interest on short-term notes payable ($2.1 million ), higher interest on long-term debt ($0.6 million ), partially offset by lower amortization of debt discounts and premiums, net ($1.6 million ), a decrease in RRB interest expense ($1.4 million ), and an increase in capitalized AFUDC related to debt funds ($0.6 million ).
Other Income, Net increased in 2022, as compared to 2021, due primarily to the following:
•The increase atCL&P was due primarily to an increase related to pension, SERP and PBOP non-service income components ($49.2 million ), an increase in capitalized AFUDC related to equity funds ($5.9 million ) and an increase in interest income primarily on regulatory deferrals ($0.6 million ), partially offset by investment losses in 2022 compared to investment income in 2021 driven by market volatility ($2.6 million ). •The increase atNSTAR Electric was due primarily to an increase related to pension, SERP and PBOP non-service income components ($45.3 million ), an increase in interest income primarily on regulatory deferrals ($17.3 million ), an increase in capitalized AFUDC related to equity funds ($4.2 million ) and an increase in investment income ($1.1 million ). •The increase at PSNH was due primarily to an increase related to pension, SERP and PBOP non-service income components ($16.5 million ), an increase in capitalized AFUDC related to equity funds ($0.9 million ) and an increase in interest income primarily on regulatory deferrals ($0.7 million ).
Income Tax Expense increased in 2022, as compared to 2021, due primarily to the following:
•The increase atCL&P was due primarily to higher pre-tax earnings ($36.0 million ), higher state taxes ($2.3 million ), an increase in valuation allowances ($8.0 million ), a decrease in amortization of EDIT ($0.6 million ) and lower share-based payment excess tax benefits ($0.8 million ), partially offset by lower return to provision adjustments ($6.3 million ) and a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($1.5 million ). •The increase atNSTAR Electric was due primarily to a decrease in amortization of EDIT ($14.0 million ), an increase in pre-tax earnings ($8.7 million ), higher state taxes ($2.8 million ), and lower share-based payment excess tax benefits ($0.6 million ), partially offset by a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($0.4 million ). •The increase at PSNH was due primarily to higher pre-tax earnings ($6.9 million ), higher state taxes ($3.2 million ), a decrease in amortization of EDIT ($2.8 million ), and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($1.3 million ), partially offset by a decrease in return to provision adjustments ($2.3 million ). 53 --------------------------------------------------------------------------------
EARNINGS SUMMARY
CL&P's earnings increased$131.2 million in 2022, as compared to 2021, due primarily to the absence in 2022 of theOctober 1, 2021 settlement agreement that resulted in a$75 million pre-tax charge to earnings and a$28.6 million pre-tax charge to earnings for a 2021 storm performance penalty imposed by PURA as a result ofCL&P's preparation for, and response to, Tropical Storm Isaias. The after-tax impact of the settlement agreement and storm performance penalty imposed by PURA was$86.1 million . Earnings were also favorably impacted by higher earnings from its capital tracking mechanism due to increased electric system improvements, an increase in transmission earnings driven by a higher transmission rate base and lower pension plan expense. The earnings increase was partially offset by higher operations and maintenance expense driven primarily by a$10 million pre-tax charge to earnings as a result ofCL&P's commitment to contribute to an energy assistance program as part of its 2022 rate relief plan, higher storm costs, higher shared corporate costs resulting from the implementation of new information technology systems and higher insurance reserves, as well as higher depreciation expense and higher property and other tax expense.NSTAR Electric's earnings increased$15.8 million in 2022, as compared to 2021, due primarily to the base distribution rate increase effectiveJanuary 1, 2022 , an increase in transmission earnings driven by a higher transmission rate base, and an increase in interest income primarily on regulatory deferrals. The earnings increase was partially offset by higher operations and maintenance expense driven primarily by higher shared corporate costs resulting from the implementation of new information technology systems and higher storm costs, as well as higher property tax expense, higher depreciation expense, and higher interest expense. PSNH's earnings increased$21.3 million in 2022, as compared to 2021, due primarily to an increase in transmission earnings driven by a higher transmission rate base, lower pension plan expense, and the base distribution rate increases effectiveAugust 1, 2021 andNovember 1, 2022 . The earnings increase was partially offset by higher operations and maintenance expense driven primarily by higher storm costs and higher shared corporate costs resulting from the implementation of new information technology systems, the absence in 2022 of a favorable impact of a new tracker mechanism at PSNH approved as part of the 2020 rate settlement agreement that was recorded in 2021, and higher depreciation expense.
LIQUIDITY
Cash Flows:CL&P had cash flows provided by operating activities of$869.6 million in 2022, as compared to$612.9 million in 2021. The increase in operating cash flows was due primarily to an increase in regulatory over-recoveries driven by the timing of collections for the non-bypassable FMCC and other regulatory tracking mechanisms, the timing of cash payments made on our accounts payable, the absence in 2022 of pension contributions of$98.9 million made in 2021, an increase in earnings after adjustment for non-cash items primarily due to higher revenues, and a$24.2 million decrease in cost of removal expenditures. The impact of regulatory collections are included in both Regulatory Over/Under Recoveries and Amortization of Regulatory Assets on the statements of cash flows. These favorable impacts were partially offset by the timing of cash collections on our accounts receivable, a$79.2 million increase in income tax payments made in 2022, as compared to 2021,$72.0 million of customer credits distributed in 2022 as a result of theOctober 2021 settlement agreement and the 2021 storm performance penalty forCL&P's response to Tropical Storm Isaias, and the timing of other working capital items.NSTAR Electric had cash flows provided by operating activities of$771.5 million in 2022, as compared to$700.9 million in 2021. The increase in operating cash flows was due primarily to an increase in earnings after adjustment for non-cash items primarily due to higher revenues, a decrease in regulatory under-recoveries driven by the timing of collections for regulatory tracking mechanisms, a$50.4 million decrease in income tax payments made in 2022, as compared to 2021, the timing of cash collections on our accounts receivable, a$15.0 million decrease in pension contributions made in 2022, as compared to 2021, and the timing of other working capital items. The impact of regulatory collections are included in both Regulatory Over/Under Recoveries and Amortization of Regulatory Assets on the statements of cash flows. These favorable impacts were partially offset by$76.3 million of payments in 2022 related to withheld property taxes, a$34.0 million increase in cash payments for storm costs, and the timing of cash payments made on our accounts payable. PSNH had cash flows provided by operating activities of$361.5 million in 2022, as compared to$336.1 million in 2021. The increase in operating cash flows was due primarily to the timing of cash payments made on our accounts payable and an increase in earnings after adjustment for non-cash items primarily due to higher revenues. These favorable impacts were partially offset by the timing of cash collections on our accounts receivable, a decrease in regulatory over-recoveries driven by the timing of collections for regulatory tracking mechanisms, the timing of other working capital items, a$9.1 million increase in cost of removal expenditures, and a$7.2 million increase in income tax payments made in 2022, as compared to 2021. The impact of regulatory collections are included in both Regulatory Over/Under Recoveries and Amortization of Regulatory Assets on the statements of cash flows. For further information onCL&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. 54 --------------------------------------------------------------------------------
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Market Risk Information
Commodity Price Risk Management: Our regulated companies enter into energy contracts to serve our customers, and the economic impacts of those contracts are passed on to our customers. Accordingly, the regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. Eversource's Energy Supply Risk Committee, comprised of senior officers, reviews and approves all large-scale energy related transactions entered into by its regulated companies.
Other Risk Management Activities
We have an Enterprise Risk Management (ERM) program for identifying the principal risks of the Company. Our ERM program involves the application of a well-defined, enterprise-wide methodology designed to allow our Risk Committee, comprised of our senior officers of the Company, to identify, categorize, prioritize, and mitigate the principal risks to the Company. The ERM program is integrated with other assurance functions throughout the Company including Compliance, Auditing, and Insurance to ensure appropriate coverage of risks that could impact the Company. In addition to known risks, ERM identifies emerging risks to the Company, through participation in industry groups, discussions with management and in consultation with outside advisers. Our management then analyzes risks to determine materiality, likelihood and impact, and develops mitigation strategies. Management broadly considers our business model, the utility industry, the global economy, climate change, sustainability and the current environment to identify risks. TheFinance Committee of the Board of Trustees is responsible for oversight of the Company's ERM program and enterprise-wide risks as well as specific risks associated with insurance, credit, financing, investments, pensions and overall system security including cyber security. The findings of the ERM process are periodically discussed with theFinance Committee of ourBoard of Trustees , as well as with other Board Committees or the fullBoard of Trustees , as appropriate, including reporting on how these issues are being measured and managed. However, there can be no assurances that the ERM process will identify or manage every risk or event that could impact our financial position, results of operations or cash flows. Interest Rate Risk Management: We manage our interest rate risk exposure in accordance with our written policies and procedures by maintaining a mix of fixed and variable rate long-term debt. As ofDecember 31, 2022 , approximately 98 percent of our long-term debt was at a fixed interest rate. The remaining long-term debt is at variable interest rates and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in our variable interest rates, annual interest expense would have increased by a pre-tax amount of$3.5 million . Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and transact with suppliers that include IPPs, industrial companies, natural gas and electric utilities, oil and natural gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process. Our regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and monitor contracting risks, including credit risk. As ofDecember 31, 2022 , our regulated companies held collateral (letters of credit or cash) of$32 million from counterparties related to our standard service contracts. As ofDecember 31, 2022 , Eversource had$35.7 million of cash posted with ISO-NE related to energy transactions. For further information on cash collateral deposited and posted with counterparties, see Note 1M, "Summary of Significant Accounting Policies - Supplemental Cash Flow Information," to the financial statements. If the respective unsecured debt ratings of Eversource or its subsidiaries were reduced to below investment grade by either Moody's, S&P or Fitch, certain of Eversource's contracts would require additional collateral in the form of cash or letters of credit to be provided to counterparties and independent system operators. Eversource would have been and remains able to provide that collateral. 55
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