ML19305D644

Annual Financial Rept 1979

ML19305D644
Person / Time
Site:	Millstone
Issue date:	03/14/1980
From:	CONNECTICUT LIGHT & POWER CO. (SUBS. OF NORTHEAST
To:
Shared Package
ML19305D642	List: ML19305D641 ML19305D644 ML19305D647 ML19305D688
References
NUDOCS 8004150322
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{{#Wiki_filter:._ __ _______ SECURITIES AND' EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM'10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) 0F THE SECURITIES EXCHANGE ACT OF 1934 l-For the fiscal year ended December 31, 1979. Commission file number 0-404 THE CONNECTICUT LIGHT AND POWER COMPANY I (Exact name of registrant as specified in its charter) CONNECTICUT 06-0303850 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification Number) Selden Street, Berlin, Connecticut 06037 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (203) 666-6911 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Cumulative Preferred Stock, par value $50.00 per share, issuable in series, of which the following series are now outstanding: $2.00 Series of 1947 $3.24 Series G of 1968 $1.90 Series of 1947 $4.48 Series H of 1970 $2.20 Series of 1949 $4.48 Series I of 1970 $2.04 Series of 1949 - $3.80 Series J of 1971 $2.06 Series E of 1954 $4.56 Series K of 1974 $2.09 Series F of 1955 $5.52 Series L of 1975 (Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No . Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of = the close of the period covered by this report. ~ Class Outstanding at December 31, 1979 Common Stock, $10.00 par value 8,931,014 shares O 8 004150 D

THE CONNECTICUT LIGHT AND POWER COMPANY ITEM 1. BUSINESS THE COMPANY l The Connecticut Light and Power Company (the Company or the Registrant) is part of the Northeast Utilities system ( the System) and a wholly-owned subsidiary of Northeast Utilities (see " Northeast Utilities System"). The Company is a Connecticut l corporation, organized in 1907, and is qualified as a foreign corporation in Massachusetts and New Hampshire. The Company is the largest electric and gas utility in Connecticut and is engaged principally in the production, purchase, transmission, distribution and sale of electricity and the purchase, distribution and sale of gas at retail for residential, commercial, industrial and municipal purposes within the State of Connecticut. As described hereinafter under " Northeast Utilities System-Disposition of Gas Properties", the Company and The Hartford Electric Light Company (HELCO) have undertaken otudies to determine the appropriate course of action to be taken with respect to their gas properties. In this connection a corporate merger of HELCO and the Company is under consideration. PROBLEMS OF THE INDUSTRY The electric utility industry is currently experiencing problems in a number of areas, including the effects of inflation, a continued rapid escalation of the price of fuel, difficulty in meeting coverage requirements for the issuance of senior securities, difficulty in obtaining sufficient return on invested capital and in securing adequate rate increases when required, difficulty in complying with changing environmental regulations, regulatory delays and more stringent requirements with respect to licensing and operation of nuclear generating plants, federal requirements relating to the conversion of generating plants from oil to coal-burning, controversies over the use of nuclear power following the accident at Three Mile Island in Pennsylvania, large financial commitments and lonaer construction periods for new generating units, the effects of higher electricity prices on the use of electric energy, and the uncertain effect of existing and proposed federal energy legislation. The Company and the System have been experiencing these problems in varying degrees and have made reductions in and deferrals of previously planned construction programs primarily as a result of difficulties in obtaining adequate rate relief and the reduced rate of increase in the use of electric energy. (See " Construction and Financing Program", " Rates", " Northeast Utilities System - Fuel for Generating Stations" and " Regulatory cnd Environmental Requirements and Proceedings".) - J

CONSTRUCTION AND FINANCING PROGRAM Construction program expenditures (including Allowance for Funds Used During Construction ( AFUDC)) but excluding nuclear fuel) in the period 1980 through 1984 are estimated to be as follows: 1980 1981 1982 1983 1984 (Thousands of Dollars) Electric Plant

• Prodtrtion

$94,811 S100,887 $118,551 S110,677 $103,102 Stbstations ary! Transmission Lines 15,165 7,975 8,698 9,314 11,614 Distribution Operations 19,981 21,779 23,702 25,570 27,236 General 5,201 2.758 4,480 2,571 2,941 Gas Plant 18,435 18,155 14,387 14,146 14,038 'Ibtal $153,593 $151,554 $169,818 $162,278 $158,931 The Company continues to own an approximately 4.5% ownership interest in Seabrook Unit Nos. 1 and 2. The sales made by the Company in 1979 and prior years of a portion of its original 12% ownership interest in these units realized proceeds of approximately $46,900,000. The Company has contracts with two purchasers covering an approximate 1.5% ownership interest. The Company cannot predict when or if the necessary regulatory approvals for such sales will be obtained and the sales consummated. Although efforts are being made to dispose of the balance c f the Company's interest in the Seabrook units, other participants are also attempting to sell portions of their ownership shares in these units, and there is no assurance that the Company will be successful. In view of the uncertainties involved in the disposition of the Company's remaining interest in Seabrook, the costs to be incurred by the Company (excluding nuclear fuel) have been included in the construction program expenditures set forth in the table-above. If the Company disposes of its remaining interest in Seabrook, the construction program set forth in the table would be reduced approximately $18,388,000, $18,876,000, $15,690,000, $8,497,000 and $4,491,000, respectively for the years 1980 through 1984. On March 20, 1980, j the Public Service Company of New Hampshire (PSNH), the principal owner of Seabrook, announced a substantial reduction in the level of Seabrook construction expenditures to approximately 50-60% of the level reflected in the above estimated construction expenditures. It is not presently known how long this reduced level of construction will continue, and the Company cannot at this time assess the impact of this. l L

development on the Company's estimated construction expenditures for Seabrook. See " Regulatory and Environmental Requirements and Proceedings - NRC Nuclear Plant Licensing" with respect to Seabrook licensing matters and the difficulties faced by PSNH. The expenditures shown above do not include the cost of complying with anticipated federal requirements mandating the conversion of certain Company generating units from oil-burning to coal-burning, or any amounts which may be required to assist the various Yankee nuclear generating companies in financing their capital requirements. See " Northeast Utilities System - Fuel for Generating Stations and Joint Projects." The construction program for the years 1980 and 1981 includes approximately S402,000 and $1,780,000 respectively for environmental control facilities. Millstone Unit No. 3 in Waterford, Connecticut and Seabrook Unit Nos. 1 and 2 in Seabrook, New Hampshire are the only major generating facilities under construction in which the Company has an interest. Although the Connecticut Division of Public Utility Control (DPUC) granted additional rate relief to the Company and HELCO in 1979, the additional revenues were not sufficient to permit construction of Millstone Unit No. 3 to be accelerated to provide for a 1984 completion date and that unit continues to be scheduled for completion in 1986. The following table sets forth anticipated construction expenditures for the Company's share of these units. Millstone Seabrook #1 Seabrook #2 ibtal Net MW Capability.............. 1,150 1,150 1,150 Year of Planned Operation............ 1986 1983 1985 Estimated Company Expenditures (4housands of Dollars)*+ Before 1980 ( Actual)................. S231,954 S 38,757 1980............................ 57,745 18,388 1981............................ 67,914 18,876 1982............................ 87,327 15,690 1983............................ 87,202 8,497 1984............................ 84,928 4,491 After 1984.......................... 96,048 249 Estimated Construction Cost per kw... 1,800 1,024 Company Ownership.................... 34.5% 4.4932% Figures do not include cost of nuclear fuel and represent only the Company's portion of the currently estimated total cost. The total cost of Millstone Unit No. 3 is currently estimated at $2,070,000,000. The estimates, which are subject to change, are based on the most recent cost projections. It has been the experience of the System companies and other utilities that the costs of facilities such as these units frequently increase t

substantially over earlier projections due to inflation, increased licensing requirements, new environmental regulations, schedule deferrals and other causes. See " Regulatory and Environmental Requirements and Proceedings - NRC Nuclear Plant Licensing" with respect to various problems relating to the Seabrook units. + Pigures do not reflect recent announcement that construction of the Seabrook units will be reduced indefinitely to approximately 50-60% of present levels. The uncertainties of future financing and the licensing process required for new nuclear units have led to the suspension of efforts to obtain early regulatory site approval for Montague Unit Nos. 1 and 2, two 1,150 MW nuclear generating units proposed to be installed in Montague, Massachusetts in which the Company has a 39.8% interest. In view of the suspension, the construction program amounts shown above include for the Montague units only $800,000 per year for the continuation of selected environmental studies and for AFUDC. The Company has expended approximately S14,500,000 to date on the Montague project. The sales in 1979 and in prior years of nuclear generating unit interests, the proposed sale of the Company's remaining interest in the Seabrook units, the deferral to 1986 of Millstone Unit No. 3 and the suspension of the Montague project are not expected to have an adverse effect on reliability of customer service in the near term. The Company's ability to maintain the proposed construction expenditure level is primarily dependent upon its ability to obtain timely and adequate rate relief. If adequate future rate relief cannot be obtained, the Company will be forced to consider further reductions in proposed projects and further sales of interests in generating units. The Company estimates that its expenditures for nuclear fuel (including nuclear fuel for the Seabrook units and after giving effect to the settlement of the Westinghouse litigation referred to under " Northeast Utilities System - Fuel for Generating Stations") will be $5,619,000 in 1980, S10,503,000 in 1981, S8,236,000 in 1982, $5,684,000 in 1983 and S8,315,000 in 1984. Fuel-for Millstone Unit Nos. I and 2 is owned and financed by Northeast Nuclear Energy Company (NNECO). It is expected that any increase required in the investment in nuclear fuel for Millstone Unit Nos. 1 and 2 will be financed by NNECO through capital contributions or advances from Northeast Utilities and the issuance of secured notes and bank borrowings. In addition, NNECO has entered into an arrangement under which a bank is financing up to $50,000,000 of certain nuclear fuel for Millstone Unit Nos. 1 and 2 under a trust arrangement while the fuel is in fabrication. NNECO will be obligated to purchase the fuel and reimburse the trust for payments made~by the trust and for financing costs within a limited period af ter delivery of all such fuel to the reactor site. A substantial portion of the funds required for fuel for those units is expected to be provided through the recovery through rates as an operating expense of the amortization of the fuel being burned in the unit reactors. In addition to the aforesaid construction program, the Company's financing requirements during the period 1980-1984 also include S160,155,635 to meet long-term debt and preferred stock sinking fund and debt maturity requirements. Of this amount, S123,531,127 will be due in 1982. It has been the practice of the Company to finance current construction expenditures and other financing requirements in excess of available internally generated funds from the proceeds of short-term borrowings to be funded through the sale of additional first mortgage bonds and preferred stock, through leasing of equipment and from capital contributions and advances by Northeast Utilities. Northeast Utilities anticipates making a capital contribution to the Company of approximately $40,000,000 during 1980. There is no assurance that Northeast Utilities can continue to sell its common shares in amounts necessary to provide the necessary capital contributions to the Company. The amount of short-term borrowings which may be incurred by the Company is subject to requisite approval of the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 and is also restricted by the Company's preferred stock provisions. The presently authorized SEC limit on such short-term borrowings expires June 30, 1980. The SEC limit and the preferred stock limitation on short-term debt for the Company together with the amount of short-term borrowings outstanding at December 31, 1979, are act forth below. Limit under Preferred Stock Short-Current Provisions Term Total Short-SEC at December Commercial Bank Term Debt Authorization

_31, 1979 Paper Loans Outstanding

$135,000,000 S281,694,000 S65,245,000 S23,000,000 $88,245,000 See Note 4 to financial statements with respect to credit lines available to the Company. l The indentures securing the outstanding mortgage bonds l i of the Company requires for the issuance of additional bonds, Gxcept for certain refunding purposes, minimum earnings Coverage ~ of twice the pro forma annual interest charges on bonds outstanding and those to be issued, and its preferred stock provisions require for the issuance of additional preferred stock minimum earnings coverage of one and one-half times the pro forma annual interest charges on indebtedness and annual dividend requirements on preferred stock to be outstanding after the issuance of the additional stock. On the basis of the formulas contained in the indenture and preferred stock provisions, and including in earnings AFUDC applicable both to borrowed funds and to other (equity) funds to the maximum extent permitted by the respective coverage provisions, the Company's coverages for the years ended December 31, 1977, 1978 and 1979 were, based on the amounts outstanding as of the end of such periods, as follows: Preferred Bond Stock Year Ended Coverage Coverage December 31, 1977.............. 2.11 1.57 December 31, 1978.............. 2.25 1.60 December 31, 1979.............. 2.19 1.45 The Company believes that its sale of additional securities will continue to depend on the adequacy of future earnings, on general conditions in securities markets and on favorable market appraisal of the Company's securities and Northeast Utilities common shares. BUSINESS Electric Operations The Company furnishes retail electric service in Connecticut. The Company furnishes wholesale electric service to a total of 5 municipal electric systems and 4 investor-owned electric systems. About 86% of the Company's operating revenues for 1979 came from electric service. Electric revenues for that period were derived 43% from residential customers, 25% from commercial customers, 21% from industrial customers, 8% from wholesale customers and the balance from others. Through December 31, 1979, the all-time maximum demand on the Company's system was 2,150,600 kilowatts, which occurred on December 19, 1979 at which time the generating capacity of the Company's generating plants (including the Company's entitlements in regional nuclear generating companies) was 3,228,200 kilowatts. At the time of the peak, the Company was selling 77,950 kilowatts of capacity from its plants to other utilities and was purchasing 8000 kilowatts from other utilities for economy purposes. Such purchases are designed to take advantage of lower fuel costs on the system of the selling I

utility. Gas Operations The Company furnishes retail gas service in eight separate service areas, not interconnected. See " Northeast Utilities - Disposition of Gas Properties". About 14% of the Company's operating revenues for 1979 came from gas service. Gas revenues for that period were derived 45% from residential customers, 18% from commercial customers, 35% from industrial customers and the balance from others. The Company and HELCO have since January 1, 1979 effected their gas supply operations on a one-system basis. The effect of this arrangement is to make the gas supply costs of the Company and HELCO uniform. Tre bulk of the gas supplied by the Company is natural gas purchaser: ader long-term contracts with Algonquin Gas Transmission Company (approximately 58%) and Tennessee Gas Pipeline Company (approximately 42%) at rates subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). Although since 1970 natural gas suppliers, with the approval of FERC, have reduced the quantities of natural gas available to the Company, the amounts supplied by Algonquin Gas Transmission Company and Tennessee Gas Pipeline Company were not significantly curtailed during the 1979-1980 heating season, and no significant curtailment is anticipated during the 1980-1981 heating season. However, the limits on availability of natural gas are continuing to require the Company to use higher cost liquefied natural gas (LNG), substitute natural gas (SNG) and, to a lesser extent in recent years, propane to supplement its natural gas supply. In addition, the natural gas suppliers of the Company have periodically obtained rate increases for their natural gas deliveries and have additional requests for rate increases pending before PERC. These and other factors are causing continuing increases in operating costs for gas service. Since 1970, the Company has had a purchased gas adjustment clause in its retail gas rates permitting increased billings to customers reflecting higher costs of all forms of gas utilized by the Company. Arrangements have been made by the Company to obtain additional quantities of LNG, SNG and propane and to provide additional storage for LNG. However, the suppliers of LNG and SNG are largely dependent on foreign sources and the extent of future availability is uncertain at this time. The Company has also contracted for underground storage service which will be available in 1981 and will enhance the Company's utilization of available natural gas. Barring presently unforeseen conditions, the Company expects that its gas supplies will be ad:quate to meet the anticipated demand through the 19^4-1985 heating season. ;

Pipeline natural gas, LNG and SNG provided 88%, 3.3% and 8.2%, respectively, of the Company's requirements during 1979, with propanc supplying the remainder. Assuming a continuation of the weather pattern of recent years, the Company's gas requirements for 1980 are expected to be met approximately 88.7% by pipeline natural gas, 3.8% by LNG, 7.4% by SNG and the balance with propane. Segments of Business The information required is located in the Statements of Segments of Business on page 19 of Registrant's I.7nual Report to Shareholders for the year 1979 attached and made a part hereof as Exhibit A which information is hereby incorporated herein. Employees As of December 31, 1979, the Company had a total of 3,834 regular employees. See " Northeast Utilities System." The Company has agreements with various local unions which cover a total of 2,029 employees. The earliest of these agreements expires June 1, 1980. NORTHEAST UTILITIES SYSTEM Operations The Company, HELCO, Western Massachusetts Electric Company (WMECO), and Holyoke Water Power Company (HWP) are the principal operating subsidiaries comprising the System. Other subsidiaries of Northeast Utilities providing substantial support to the System companies include Northeast Utilities Service Company (the Service Company), a System service company supplying centralized accounting, administrative, data processing, engineering, financial, legal, operations, planning, purchasing and other services to the System companies, NNECO, agent for System companies in construction and operation of nuclear ~ generating facilities and the financing of nuc1 ear fuel for such facilities, and The Rocky River Realty Company and the Quinnehtuk Company, each a real estate company. The Company and HELCO have consolidated thdir operations by means of a transfer of all HELCO personnel (other than production personnel) to the Company. The Company is responsible for meeting the local service needs of customers of both companies and bills HELCO for work performed for HELCO on a recovery of cost basis. The Company and HELCO are continuing their investigation of the feasibility of a corporate merger, in which the Company would be the surviving corporation. S l System operating companies own and operate a fully-integrated electric utility business. Generating and transmission facilities are planned and operated as part of a regional New England bulk power system. See " Northeast Utilities System - Joint Projects". System transmission lines form part of a New England transmission system linking System generating plants with one another and with the facilities of other utilities in the northeastern United States and in Canada. Since June 1, 1970, the System companies have pooled their electric production costs and the costs of their principal transmission facilities. The effect of this arrangement is to make the unit bulk power costs of the System companies uniform. Through December 31, 1979 the all-time maximum demand on the System was 3,955,200 kilowatts, which occurred on December 19, 1979 at which time the generating capacity of the System's generating plants (including the System companies' entitlements in regional nuclear generating companies) was 6,374,900 kilowatts. At the time of the peak, the System was selling 461,600 kilowatts of capacity from its plants to other utilities and was purchasing 8,000 kilowatts from other utilities for economy purposes. Such purchases are designed to take advantage of lower fuel costs on the system of the selling utility. System capacity which is in excess of System needs including reserve requirements, is offered for sale to other utilities. The System expects to have capacity available from its existing units for such sales until at least 1989. System kilowatthour sales for 1979 were 2.6% above the level for 1978. During 1979, System energy requirements were met 53% with nuclear units, 43% with fossil fired units, and 4% with hydroelectric units. During 1978, System energy requirements were met 58% with nuclear units, 39% with fossil fired units, and 3% with hydroelectric units. The System currently estimates that the annual rate of growth in sales will approximate 2.5% during the next ten years. Joint Projects System operating companies and most other New England utilities with electric generating facilities are parties to the New England Power Pool (NEPOOL) Agreement. Under the Agreement the generating facilities of all participants are l operated as a single system through the New England Power Exchange, a regional dispatch control agency. Provision is I also made for the generating capacity responsibilities of l participants and their transmission rights and responsibilities. Op3 ration of System generating facilities under pool dispatch l results in substantial purchases and sales of electric energy l by the System at prices determined in accordance with the NEPOOL Agreement. System companies have entered into agreements with other New Englamt utilities covering the participation of such utilities as joint owners in the future nuclear units referred to under " Construction and Financing Program." The arrangements with respect to each of these units provide for a pro rata sharing of construction and operating costs and the electrical output of the unit by the owners, as well as pro rata sharing of the costs of transmission associated with the unit. The units have been planned in accordance with NEPOOL criteria which are designed to bring about the planning and construction by NEPOOL members of sufficient additional generating capacity to insure that an insufficiency of capacity to meet expected customer loads will not exist more frequently than one day in ten years. The Company, HELCO and WMECO are part owners with other New England electric utilities of the stock of four regional nuclear generating companies. These companies are Connecticut Yankee Atomic Power Company, Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power Corporation, and Yankee Atomic Electric Company, in which the Company has a 25%, 8%, 6% and 15% interest, respectively. The Company, HELCO and WMECO are obligated, within specified limits, to provide their percentages of such additional equity capital as may be necessary for the Yankee companies. It is presently estimated that Connecticut Yankee Atomic Power Company's construction program (excluding nuclear fuel) for the years 1980, 1981 and 1982 will be approximately $32,700,000, S25,800,000 and S24,100,000, respectively, which expenditures are primarily for plant modifications and improvements. The System believes that additional capital may be also required by one or more of the o ther Yankee companies in the next several years to finance construction expenditures and nuclear fuel or for other purposes. Although it is not possible to determine at this time how the various Yankee companies may finance such construction requirements, it is possible that the System companies may be required to provide additional equity capital and/or other types of financial support for one or more of the Yankee companies. Fuel for Generating Stations The System required approximately 12,600,000 barrels of oil in 1979 for the operation of its generating units. The System's storage capacity is approximately 3,000,000 barrels and the inventory is generally a 45-day supply. Although at the present time System companies are able to obtain their full oil requirements, there can be no assurance that an adequate oil supply will be available indefinitely. More than 60% of the oil for System generating units is purchased under a contract with Amerada Hess Corporation which expires in August 1981 but may be renewed from year to year by mutual 1 i agreement. The contract is for a specific quantity of oil but the price may increase or decrease since it is based on a specified discount from the posted price. Most of the balance 3 is purchased.under contracts for one year or less. The cost por barrel has increased substantially from approximately $14.00 par barrel _ in December 1977, to approximately S30.00 per barrel in early 1980 and is expected to rise even higher in the coming year. The System's current construction program does not include any funds for the conversion of existing oil-fired l generating units to coal. One such unit, HWP's Mt. Tom Station, J is presently subject to a prohibition order issued under the Ene:gy Supply and Environmental Coordination Act of 1974 which would prevent the continued burning of oil and require a compliance schedule for conversion to coal. Similar orders issued under that Act with respect to five other system units have been rescinded, but those units, together with other system 4 I units, may become subject to new prohibition orders that could be issued under the Powerplant and Industrial Fuel Use Act of 1978. In addition new federal legislation has been proposed that would require the conversion of a total of 10 of che System's units (including the foregoing 6 units) with an aggregate capacity of 1,271 MW. The estimated cost of conversion of all ten System units ranges from approximately $265,000,000 to approximately $665,000,000, depending on whether flue gas desulphurization equipment is required for each of the units. The Company owns five of these ten units with an aggregate j capacity of 638 MW and the estimated cost of conversion of all such Company units ranges from approximately $137,000,000 to j approximately $306,000,000. None of these costs are included in the construction program expenditures under " Construction and Financing Program". Although proposed federal legislation d may provide funds to finance a portion of such conversion costs, the System companies are presently unable to finance any significant conversion expenditures and intend to contest any such requirements for coal conversion unless adequate arrangements are made to enable the companies to finance these costs. The System companies are presently contesting existing ef forts by DOE to require such conversions. I Uranium concentrates, uranium processing and nuclear core fabrication services for the initial fuel loading and reload fuel for nuclear units are sometimes purchased as a package f rom the reactor supplier. In other instances the uranium concentrates are purchased separately from processing and fabrication services. To the extent indicated below, there are outstanding contracts for uranium concentrates and conversion, enrichment and fabrication for the System's existing and planned units, and the other units in which System companies-are participating, which cover the units'-requirements through - - - -. -. - = -..,

the following years: Uranium conversion to concentrates flexafluoride Enrichment Fabrication Connecticut Yankee 1986 1985 1995 1986 Maine Yankee (l) 1986 1982 2000 1984 Vermont Yankee (l) 1982 1982 2001 1982 Yankee Atomic (1) 1982 1982 1999 1983 Seabrook Unit tb.1(1) 1985 1987 2009 1986 Seabrook Unit tb. 2()) 1985 1987 2011 1986 Millstone Unit ib.1 1987 1990 2001 1982 Millstone Unit No. 2 1986 1989 2001 1986 Millstone Unit tb. 3 1990 1989 2014 1993 (1) The information in the table for these units has been furnished to the Company by the utility company having responsibility for operation of the unit. The System expects that uranium concentrates and related services for other periods not covered by existing contracts will be available, although such availability depends, among other factors, on suppliers of such materials and services developing additional capacity. There can be no assurance that such concentrates and services will in fact be available when needed. The costs for materials and services for subsequent periods are likely to be substantially higher than under existing contracts. On September 26, 1979 the United States District Court for the Eastern District of Virginia approved an agreement reached by the Service Company, acting on behalf of the Company, ilELCO and WMECO and the other owners of Millstone Unit No. 3, in settlement of the owners' action against Westinghouse seeking damages for the repudiation by Westinghouse of its contract to supply uranium for the first core and three refuelings of the unit. Under the agreement Westinghouse has paid the owners S2,000,000 in cash, will provide equipment and services for the unit during the next ten years at no charge or with a rebate against the purchase price, will provide rebates against the purchase price on certain uranium conversion services and fuel fabrication services for the unit, will provide at formula prices currently approximating or slightly below estimated production costs 1.5 million pounds of uranium for the unit to be delivered during the period 1985 to 1989, and has waived any right for price adjustment for uranium already delivered and to be delivered under a court ordered allocation plan at the original contract price. The Service Company has valued the cash, l uranium, equipment, rebates and services at $60,100,000, in l 1979 dollars. The considerations received in settlement of l l

the litigation by System companies for their 65% ownership interest will be credited to the cost of uranium for the unit, which will lower the fuel costs of the unit for a period of time after it commences commercial operation. Nuclear Waste Disposal and Decommissioning Costs Costs associated with nuclear plants include amounts for the disposition of nuclear wastes, including spent fuel, and for the ultimate decommissioning of these plants. There is some uncertainty with respect to current cost estimates for plant decommissioning, largely because of recently announced planned changes and extensions of the federal government policy. The System companies currently reflect in their nuclear fuel expense DOE's current estimated cost (1978 dollars) of spent fuel disposal. This provision for spent fuel disposal has been accepted by the DPUC in the rate case decisions of June 29, 1979 and by the Massachusetts Department of Public Utilities (DPU) in its fuel adjustment decision of November 30, 1979 and is reflected in the wholesale fuel adjustment charges approved by FERC. Such provisions, which reflect increases over previous levels, also include amortization, over a ten-year period, of the currently estimated disposal cost (1978 dollars) of accumulated spent nuclear fuel. Although in planning their nuclear generating plants the System companies had expected that spent fuel would be reprocessed in commercial facilities, present government policy favors an indefinite postponement of commercial reprocessing. In view of this, operating nuclear generating plants are required to make long-term arrangements for the storage of spent fuel. Each of the operating nuclear plants listed under " Northeast Utilities System-Fuel for Generating Stations" in which the System has an interest is expected to have adequate storage capacity on site until at least the mid-1980's, and the storage facilities for Connecticut Yankee and the Millstone Units, including the facilities currently under construction at Millstone Unit No. 3, are expected to be adequate until at least the mid-1990's, by which time government storage and waste repository facilities are expected to be available to accept spent fuel. In the event such government storage facilities are not available at that time, the System may be required to incur substantial additional costs in obtaining alternate storage facilities. The Federal administration has recently announced specific proposals for the disposal of nuclear wastes. Ilo w e v e r, the System cannot predict at this time what difficulties will be encountered in the future rm:.rl'.ng such disposal. The NRC, along with other federal agencies, is in the process of developing regulations and guidelines in this area. It is possible that there will be additional costs (above those ; 1

presently accepted by the state regulatory commissions) associated with the disposal of nuclear wastes, including spent fuel, from each of the nuclear plants in which the System companies have an ownership interest. The System companies presently estimate decommissioning costs for their nuclear units on the basis of complete dismantlement at the time of retirement. The presently estimated decommissioning costs on this basis for Millstone Unit Nos. 1 and 2 and Connecticut Yankee are in the range of S60-70 million per unit. If alternative decommissioning arrangements are required, these cost estimates may increase. At present only a portion of such presently estimated total decommissioning costs are reflected in the depreciation expenses of the Company and IIELCO and no portions of such costs are presently reflected in WMECO's depreciation expense. See Note 1 to financial statements. Disposition of Gas Properties In light of the termination of the November 27, 1974 agreement among the Company, ilELCO and Connecticut Natural Gas Corporation (CNG) for the sale of the Company's and !!ELCO's gas properties to CNG, the Company and IIELCO have undertaken studies to determine an appropriate course of action with respect to their gas properties. It continues to be the SEC position that companies subject to the Public Utility llolding Company Act of 1935 may not retain both gas and electric properties. RATES General The Company's retail electric and gas rate schedules are subject to the jurisdiction of the DPUC. The Company's wholesale electric rates are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) and have been filed with that Commission. Retail Rates Connecticut law affords the DPUC 150 days to act upon a proposed rate increase. In default of such action by the DPUC, the proposed rates may be put into effect subject to refund. Interim rate increases, subject to refund, may be approved by the DPUC after a public hearing if they are found to be necessary to prevent substantial and material deterioration of the financial condition, or the adequacy and reliability of service, of a utility. Under Connecticut law, the DPUC is required to conduct a complete review and investigation of, and to hold a public hearing on, the financial and operating results of each electric and gas utility at least once every two years to determine whether an increase or decrease in the L

level of the utility's rates is required. On June 29, 1979 the DPUC issued a decision granting the Company an increase in retail gas and electric revenues stated to total S53,722,000, based on adjusted test year sales. The Company had requested an $87,650,000 revenue increase based upon anticipated sales during the first year that the new rates would be in effect. Rate design issues were deferred to subsequent proceedings in which a preliminary decision was issued on March 11, 1980 with implementation of amended rate schedules anticipated about May 1, 1980. The Company is collecting the total revenues authorized by the 1979 DPUC decision under interim rates ef fective for service rendered on and af ter July 19, 1979. In its decision the DPUC established the cost of common equity funds at 14.1%, resulting in a composite rate of return on rate base of 9.68% for the Company. The DPUC also stated that subsequent to the time Millstone Unit No. 3 is placed in service, generating capacity in excess of 40% of peak demand will be taken into consideration by the DPUC in making revenue determinations, and it further stated that a nechanism should be developed which would exempt some plant from the foregoing limitation based upon the Company's demonstrated performance in achieving conservation through improvements in output per unit of installed capacity, measured from an established benchmark. No mechanism was established by the decision, and the Company anticipates that discussions or generic hearings with respect to this issue will be held in the future. As part of its decision the DPUC approved a generation utilization adjustment clause for the Company effective August 1, 1979. Monthly, this clause levelizes the effect on fuel costs caused by variations from a 70 percent nuclear generation capacity factor. At the end of a twelve-month period, ending July 31 o.f each year any deferred balance resulting from the actual nuclear generation capacity factor being below or above 70 percent will be either collected from or refunded to customers over the subsequent twelve-month period. However, the clause will not permit such collection from customers to the extent that such nuclear generation capacity factor is less than 55%. For the period August 1, 1979 to December 31, 1979, the nuclear generation capacity factor was 76.6 percent resulting in a leveling charge to fuel expense of $5,242,000. The DPUC indicated in its decision that the formula adopted for computing the deferred amounts should not be considered as final until tested during the first year that it is in effect; therefore, final determinations of charges or credits may require adjustment of amounts deferred on the Company's books. The Connecticut Division of Consumer Counsel has appealed from the June 29, 1979 rate decision of the Company to the Connecticut Freedom of Information Commission (FOIC) alleging that certain discussions between members of the DPUC panel which 4

rendered the decision were in violation of the Connecticut Freedom of Information Act and requesting a decision to that ef fect and an order voiding any actions taken during such discussions. At the request of the DPUC, the POIC was enjoined by the Superior Court from hearing the appeal until after a ruling by the FOIC upon a motion filed by the DPUC to dismiss the appeal for lack of jurisdiction and thereafter until a further order by the Court. On February 13, 1980, the FOIC determined that it does have jurisdiction to hear the Division of Consumer Counsel appeal. The Court is presently considering whether its injunction against hearing the appeal should be continued, and interlocutory appeals from the FOIC's February ~ 13, 1979 jurisdiction decision have been filed by the DPUC.and by the Company. In management's opinion, the FOIC's ultimate decision on the Division of Consumer Counsel's appeal will not include an enforceable requirement that all or any portion of the rate relief granted by the DPUC in 1979 be refunded to customers. The Company expects to apply to the DPUC by the middle of 1980 for an increase in its retail electric and gas rates. Fuel Adjustment Clauses The Company has fuel adjustment clauses applicable to its retail and wholesale electric rates, and the Company has a purchased gas adjustment clause applicable to its retail gas rates. In Connecticut, public hearings are required to be held by the DPUC each month on the charges proposed for the following month under the retail fuel adjustment clause and the purchased gas adjustment clause of the Company. Under Connecticut law, monthly fuel and gas adjustment charges are also subject to retroactive review and appropriate adjustment by DPUC each quarter. No evidence has been introduced at any of the proceedings which in management's opinion would result in any substantial refunds to customers. In February 1980, the Company requested authorization from-the DPUC to defer on its books, for recovery in future rate proceedings, certain fuel-related expenses which are not currently reflected in its fuel adjustment clause. No action has been taken on this request. L

Wholesale Rates On July 31, 1978, the Company filed with the FERC new wholesale rates (R-4) estimated to increase the Company's charges to wholesale customers by $2,346,000 on a test year basis. FERC accepted the filing and suspended its effectiveness to February 1, 1979. The new rates are currently being billed subject to refund pending the final decision of FEHC., The Company and the municipal customers served under the R-4 rate have reached a settlement which, if approved by PERC, would result in refunds of approximately S543,000 on a test year basis, plus interest, the amounts of which refunds were accrued by the Company as of December 31, 1979. It is the Company's opinion that it is unlikely that the amounts of refunds it will ultimately be required to make which are in excess of the amounts which have been accrued by the Company would have a material ef fect on its results of operations. As the result of a court remand, FERC must rule upon the normalization of tax timing differences by wholesale suppliers; if the Commission should rule that normalization is not permitted, the agreed upon not annual revenue increase of S1,803,000, on a test year basis, would be reduced by approximately $2,000,000 resulting in an approximately $200,000 net reduction in wholesale revenues. The Company does not anticipate such a ruling, and it has not made any provision for such a reduction. Three of the Company's municipal customers have not agreed to the rate design proposed by the Company; hearings on that issue have been completed before an administrative law judge; the decision on that issue should have no material effect upon the Company's revenues. A price squeeze allegation made by the municipal customers will be addressed after revenue and rate design issues have been determined. On December 2, 1975 the Company filed with the PERC new wholesale rates (R-3) estimated to increase its charges to wholesale customers by approximately $5,165,000 on an annual basis. The rates were collected from March 2, 1976 until February 1, 1979 subject to refund pending the final decision of FERC. An initial decision of the presiding administrative law judge would require refunds of approximately $1,300,000 for the thirty five months the rates were in ef fect, plus interest of approximately $265,000 as of December 31, 1979. All of the principal parties have appealed that decision to the Commission. The Company has tentatively reached a settlement agreement with three of the municipal customers (City of Groton, City of Norwich and Borough of Jewett City) which received somewhat more than half of the total service rendered under the R-3 rates. Settlement with all customers served under the rate on the basis of that agreement would result in refunds which were fully accrued by the Company as of December 31, 1979. It is the opinion of management that it is unlikely that the cmounts of refunds the Company will ultimately be required to make, as a result of either the settlement agreement or a final FERC decision, which are in excess of the amounts which have l been accrued by the Company would have a material effect on its results of operations. Management Audit DPUC is required by law to institute management audits of companies such as the Company at regular intervals, which audits may result in DPUC ordering implementation of new management practices or procedures. In April 1977, the independent consulting firm conducting such an audit of the Company instituted by DPUC reported its conclusion that the Company is well-managed. In March 1980, such an audit was commenced with respect to the gas operations of the Company. REGULATORY AND ENVIRONMENTAL REQUIREMENTS AND PROCEEDIHGS Public Utility Regulation The Company is subject to regulation by DPUC, which has jurisdiction, among other things, over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, the issue of securities, standards of service, management efficiency, and construction and operation of generating, transmission, and distribution facilities. The Company is subject to the general supervision of DPU with respect to all dealings with WMECO and !!WP. The Company is also subject to the jurisdiction of the New !!ampshire Public Utilities Commission for limited purposes in connection with its ownership interest in the Scabrook units. Northeast Utilities is registered with the SEC as a holding company under the Public Utility llolding Company Act of 1935. Under that Act, the SEC has jurisdiction over Northeast Utilities and the Company with respect to, among other things, the issuance of securities, sales and acquisitions of securities and utility assets, intercompany loans, services performed by and for associated companies, accounts and records and dividends. The Company is a public utility under Part II of the Federal Power Act and is subject to regulation by FERC with respect to, among other things, interconnection and coordination of facilities, wholesale rates and accounting procedures. Enacted and proposed national energy legislation contains provisions dealing with energy conservation, energy taxes and utility rate regulation. The Company is unable to predict, at this time, what effect this legislation will have on its rates, sales, revenues or net income. Environmental Impact Requirements The National Environmental Policy Act of 1969 (NEPA) requires that detailed statements of the environmental effect of generating and transmission facilities be prepared'in connection with various applications to PERC, the Nuclear _

Regulatory Commission (NRC) and other Federal agencies for licenses or permits with respect to the construction or operation of such facilities. Federal licensing agencies are required by NEPA to make an independent environmental evaluation of proposed facilities as part of their action. Massachusetts law reguires all state agencies to determine the environmental impact of any construction proposed by private companies in areas over which they exercise jurisdiction and also as to such construction to make "a finding that all feasible measures have been taken to avoid or minimize impact", and requires in certain instances the preparation and dissonination among various state agencies of environmental impact reports pertaining to the proposed construction. See " Regulatory and Environmental Requirements and Proceedings - State Generation and Transmission Siting Laws" with respect to the requirements for state siting council approval for new generation and transmission facilities in Connecticut and Massachusetts. NRC Nuclear Plant Licensing As holders of licenses for the construction or operation of nuclear reactors, the Company, HELCO, WMECO and NNECO are subject to the jurisdiction of the NRC. NRC has broad regulatory and supervisory jurisdiction with respect to the construction and operation of nuclear reactors, including matters of public health and safety, financial qualifications, antitrust considerations and environmental impact. As a result of the March 28, 1979 accident at the Three Mile Island, Pennsylvania nuclear generating station (TMI), rigorous reexaminations of nuclear plant construction and operations have been undertaken by governmental commissions, industry groups and individual utilities. The TMI accident has also generated a multiplicity of legislative proposals in Congress and various state legislatures. On October 30, 1979, President Carter's commission on TMI issued its report which contained extensive recommendations on aspects of nuclear power; and on December 7, 1979 the President, while reaffirming his support for continued inclusion of nuclear power in his national encrgy policy, announced his agreement with the spirit and intent of those recommendations and his initiation of steps toward their implementation. The report of the NRC's independent study of TMI was released in late January 1980. The System has voluntarily adopted modifications of its operating procedures, operator training programs and emergency preparedness plans. The NRC has already promulgated numerous requirements in response to TMI which will (based upon preliminary engineering reviews) increase the capital costs of Millstone Unit No. 3 and Seabrook Unit Nos. 1 and 2 by approximately $1,000,000 and $2,000,000, [ respectively, and will require modifications to the Connecticut Ycnkee, Millstone No. I and Millstone No. 2 units costing, i i

approximately S5,000,000, S3,000,000 and $3,000,000, respectively. It is anticipated that additional changes in nuclear plant construction, including further backfitting of existing plants, and in nuclear plant operations will be ordered by the NRC. The System companies' actions and anticipated NRC orders will result in increases in the capital expenditures and operating costs associated with the nuclear plants in which they have entitlements. Some equipment modifications have already and may in the future require limited shutdowns or doratings of the plants which would not otherwise be necessary and which will result in additional costs for replacement power. Where modifications of nuclear facilities or operating procedures are required, delays in construction and costly modifications of planned and operating units may result, and it may sometimes be necessary to suspend the operation of a particular unit, or to reduce the level of its operation, until the modifications can be effected. The additional amounts of increased capital expenditures and operating costs, including costs of replacement power, cannot be determined at this time. Following the TMI accident, numerous class actions and several individual actions were commenced in the U.S. District Court for the Middle District of Pennsylvania seeking damages as a result of such accident. If the provisions of the Price-Anderson Act are determined to be applicable to the accident, and if total damages resulting from the accident exceed $140,000,000, then pursuant to the 1977 amendments to such Act, the System companies would be required to pay their share of such excess. The System companies' share would be a maximum of $5,000,000 for each of the two operating Millstone units, plus their pro rata share of a maximum of $5,000,000 for each of the other operating nuclear units in which they have an ownership interest. Pending proceedings before the NRC on nuclear plants owned by System companies or in which they participate or propose to participate include: an application for a full term (40 years from initial licensing), full power operating license for Millstone Unit No. 1, which is presently operating under a provisional license, and an application for the operating license for Millstone Unit No. 3. The Millstone Unit No. 2, Yankee Atomic, Connecticut Yankee, Maine Yankee and Vermont Yankee units have full term full power operating licenses. A construction permit for Millstone Unit No. 3 was issued by the NRC in August 1974 and the unit is presently under construction, although its in-service date has been delayed to 1986. The Environmental Protection Agency (EPA) has approved the use of a once-through cooling water system for this unit, but the approval is subject to revision. The construction permit for this unit was-for a term which expired on October 1, 1979. Application for extension of this permit was made prior to its scheduled expiration; under applicable rules of the NRC, the permit will continue in effect until the application for extension is acted upon by the NRC. NRC construction permits for Seabrook Unit Nos. 1 and 2 were issued in 1976, and these units are presently under construction. The licensing of these units has been plagued by lengthy delays and has been consistently opposed by a number of intervening groups, which have participated actively in administrative proceedings, filed numerous lawsuits and demonstrated at the construction site. Construction of the units was suspended in 1977 and 1978 for periods of seven months and three weeks, respectively, as a result of administrative proceedings and court appeals, several of which are still pending. Public Service Company of New Hampshire (PSNH), which presently owns a 50% ownership share in Seabrook Unit Nos. 1 and 2, has responsibility for the construction and scheduling of these units. PSNH has been and is experiencing serious difficulties in financing its construction program, particularly the Seabrook units. In view of these difficulties, PSNH is a ttempting to sell a 22% ownership chare in these units, and has obtained commitments for the sale of a 15% share to several New England utilities. The PSNH of fer may adversely affect a continued ef fort by the company to sell the remaining portion of its ownership interest in the Seabrook units. The PSNH sales are subject to various regulatory and shareholder approvals and there can be no assurance that such approvals will be g ran ted. If the approvals are not obtained, or if PSNH's financing program pending such approvals cannot be carried out, the in-service dates for one or both of the Seabrook units might have to be deferred, or construction of the units might have to he suspended until PSNH's financing problems are resolved, although PSNH has agreed not to suspend construction for an extended period without the consent of participating utilities holding ownership shares in the project aggregating at least 75%. On fiarch 20, 1980 PSNH announced a substantial reduction in the level of construction expenditures for the Seabrook units. The reduction is for an indefinite period and is estimated to reduce construction expenditures by approximately 50-60% while in effect. PSNH presently estimates that continuation of the reduction for more than a few months will delay the in-service dates of the units and increase the estimated total costs. The company cannot at this time predict the effect of this development on the Seabrook units or on the Company's construction program. The time required for the construction of generating facilities and for the completion of licensing and other regulatory proceedings relating thereto, which have become increasingly extensive, have compelled the System companies, as Wnll as other electric utilities, to make substantial investments in such facilities before the licensing and regulatory proceedings are final. Completion of construction of each of the three nuclear generating units in Which the System companies are participating is contingent, among other things, upon obtaining necessary regulatory approvals, permits and sufficient financing. While it is possible that future developments could lead to cancellation of one or more of the. units, such a possibility is considered unlikely.

However, if any of the units were cancelled, the System estimates the System companies' share of total costs would be substantially more than their then current investment; the precise amount would depend upon a number of factors, including the amount of termination charges and salvage and the results of negotiations in connection with contract terminacions.

The System companies would apply to applicable regulatory authorities for app. oval to anortize such shares of total costs over an appropriate future period and to recover such costs through their rates, but the System cannot predict Whether and to What extent such recovery would be permitted. Certain groups have proposed restrictive legislation in Connecticut, Maine, Massachusetts, New Hampshire and the United States Congress, and others have participated in disruptive demonstrations, filed lawsuits, participated in administrative proceedings and raised questions regarding nuclear power and the ultimate cost thereof as compared with other fuels. The System cannot accurately predict the uffect of these matters on che scheduled in-service dates or construction costs of the three nuclear generating units in which it is participating or on the operation of other nuclear units in Which the System companies have ownership interests. However, it is possible tha t such natters may delay or prevent construction, or require modifications or shutdowns, of such plants: any of which could have a substantial adverse impact on the System. Water Ouality Requirements The Federal Clean Water Act (CWA) established a requirement that every " point source" discharger of pollutants into navigable waters must obtain a National Pollutant Discharge Elimination System (NPDES) permit specifying the allowable amount and constituents of its effluent. In order to obtain such a permit, a discharger must meet technology-based effluent standards and must also demonstrate that its effluent will not cause established standards for the physical and chemical quality of the receiving waters to be exceeded. The System's initial NPDES permits for its generating units expired in 1979. With respect to System plants in Massachusetts, new permits were issued in January 1980 and will expire October 1, 1980. With the exception of the Millstone units, new permits have been obtained for System plants in L.

connecticut, which permits will expire in January 1985. These permits contain provisions which allow a reopening in order to reflect new and presumably more stringent requirements now under review by EPA. The Millstone permit will be delayed temporarily because of The Connecticut Department of Environmental Protection (DEP)'s request for additional information with respect to thermal discharge at the Millstone site. Compliance with the NPDES requirements has necessitated substantial expenditures and may require further expenditures in the future. The CWA requires EPA to develop technology-based effluent standards for certain potentially toxic ~ chemical pollutants discharged from electric generating facilities. Further chemical waste treatment facilities for the System's generating plants may be required to comply with such standards. Because of the uncertainties with respect to toxic pollutant standards and other uncertainties, the CWA's ultimate cost impact on the System cannot be estimated, but additional modifications, in some cases extensive and involving substantial cost, may ultimately be required for one or more of the System's generating facilities. Air Quality Requirements Under the federal Clean Air Act (CAA), EPA has promulgated national ambient air quality standards for certain air pollutants, including sulfur oxides, particulate matter and nitrogen oxides. EPA approved an implementation plan for the achievement, maintenance and enforcement of these standards l proposed by the DEP and approved, with exceptions, the plan proposed by the Massachusetts Department of Environmental Cuality Engineering. In order to comply with these regulations, the System companies are required to burn oil having no more than 0.5% and 2.2% sulphur content in Connecticut and' Massachusetts, recpectively. These regulations also include other air quality standards, emission performance standards and monitoring, and testing and reporting requirements which are applicable to the System's generating stations, and further restrict the construction of new sources of air pollution or the modification of existing ones by requiring that both construction and op3 rating permits be obtained and that a new or modified source will not result in the violation of the EPA's natio'nal air quality standards or its regulations for the prevention of significant deterioration of air quality. Because of the latter requirements, future construction of fossil-fired generating i units may be hindered or precluded in the System's service area, depanding on pollutant levels over which the System companies i hava no control. O

Toxic Substances and Hazardous Waste Regulations Under the federal Toxic Substance Control Act (TSCA) of 1976, EPA issued regulations in 1978 and 1979 which control the use and disposal of polychlorinated bipheryls (PCBs), which were used as an insulating fluid in many electric utility transformers and capacitors until TSCA prohibited any further manufacture of such PCB equipment. The System companies have taken numerous steps to conform to the provisions of these regulations and have begun incurring increased costs for disposal of used equipment in accordance therewith. The System anticipates that these costs will increase further in the future, once high temperature incinerators have been built by waste disposal companies and approved by EPA for the disposal of PCB fluids, but the total cost for the eventual disposal of all equipment with PCBs cannot be estimated at this time. Under the federal Resource Conservation and Recovery Act (RCRA) of 1976, the storage, treatment and disposal of hazardous wastes and the disposal of some nonhazardous wastes will become subject to new EPA regulations to be issued during 1980. The extent to which the System companies' activities will be affected by these regulations is unknown at this time. ~ However, it appears that the activities most likely to be affected are those relating to disposal of ash and sludge from coal-fired units if and when any of the System companies' oil-fired units are converted to coal. The cost of compliance with RCRA regulations cannot be estimated at this time. FERC Hydro Plant Licensing System operating companies hold licenses granted under Part I of the Federal Power Act for the operation and maintenance of eight hydroelectric plants, including the Northfield Plant in which the Company has a 53% interest. System companies have pending applications with FERC under Part I 'f the Act for i o licenses with respect to fourteen other existing hydroelectric plants. Federal Power Act licenses may be issued for terms of fifty years or less as determined by FERC. Any plant so licensed is subject to recapture by the United States or licensing to f others, after expiration of the license, upon payment to the licensee of the lesser of fair value or the net investment in the project plus severance damages less certain amounts earned by the licensee in excess of a reasonable rate of return. Licenses gran' ed are customarily conditioned upon the development by the licensee of recreational and other nonpower uses at each licensed plant, and conditions may be imposed with respect to Ipw flow augmentation of streams and fish passage facilities. e - -

State Generation and Transmission Siting Laws In Connecticut, construction or modification of electric generation and transmission facilities and certain other utility facilities may not be commenced without a certificate of environmental compatibility and public need from the Connecticut Power Facility Evaluation Council (PFEC). The System has received from time to time certificates for various transmission lines and a certificate for Millstone Unit No. 3. PFEC has concluded hearings in a proceeding to weigh the various factors which bear on the feasibility and costs of undergrounding some or all overhead transmission and distribution lines in Connecticut. If all or a significant part of the transmission and distribution lines of the System were required to be installed underground, substantial additional costs would have to be incurred by the System with respect to proposed or existing lines. No significant action has been taken in this proceeding in the last several years, and it is not presently known When it will be concluded. The Company is faced with a DEP order to place underground an existing transmission line's river crossings. The order has been appealed to the courts, and the outcome of 4 this proceeding cannot be predicted. The cost of this undergrounding and possible future undergroundings ordered by PFEC would be substantial. In Massachusetts, electric generation and transmission facilities cannot be built unless they are consistent with a long-range forecast of electric power needs and facility requirements for their market areas which has been approved by the Energy Facilities Siting Council (EFSC). In addition, the EFSC may issue necessary state permits for such facilities under certain circumstances Where such permits have been denied by other state agencies. The Massachusetts Constitution requires that the disposition of, or changes in the use of, certain public lands must be approved by a two-thirds roll-call vote of each branch of the state legislature. The public lands include lands used for parks, wildlife and game preserves, water supplies, public recreation, great ponds and like uses. Accordingly, the acquisition of transmission rights of way over public lands in Massachusetts is difficult, and any need to acquire rights therein may delay and increase the cost of transmission facilities in Massachusetts. General The System expects that compliance with the foregoing environmental impact, hydro and nuclear licensing, water and air quality, plant and transmission siting and other regulatory and environmental requirements, and further developments in these and other areas of regulation, will require it to incur substantial capital expo..ditures for equipment modifications and additions, monitoring equipment and recording devices and to incur substantial additional operating expenses. The total amount of these expenditures is not now determinable. The requirements in these areas may also~cause substantial delays in the completion of required new facilities. t 4 { l l 4 Item 2. Summary of Operations .i The information required is contained under the capticas - " Summary of Operations" and " Management Discussion and Analysis of Summary of Operations" on pages 16 through 18 of Registrant's Annual Report to Shareholders for the year ended December 31, 1979, attached hereto and made a part hereof as Exhibit A, which information is incor-porated herein. Item 3. Properties Except for its interests in the Northfield Mountain pumped storage plant, the Company's present utility system is located wholly within the state of Connecticut. The principal plants and other pro-perties comprising its system, of which certain substation equipment, data processing equipment, vehicles and office space are leased, are located either on land which is owned in fee or on land, as to which the Company owns perpetual occupancy rights adequate to exclude all parties except possibly state and federal governments, which has been reclaimed and filled pursuant to permits issued by the U.S. Army Corps of Engineers. Substantially all of the property is subject to the lien of the Company's indenture securing its outstanding mortgage bonds, and to certain other liens, encumbrances and minor restrictions, none of which impairs the usefulness of such properties in the Company's business. With few exceptions, lines and mains are located on or under streets or highways, or on properties either owned or leased by the Company or occupied under rights obtained from the owners. As of December 31, 1979, the electric generating plants of the Company and the Company's power entitlements from the generating plants of the four Yankee regional nuclear generating companies in which the Company is one of the stockholders were as follows: Name Plate Net Year Rating Capability Name, Town, Location Type Installed (Kilowatts) (Kilowatts) Millstone Plant Nuclear 1970 350,595(a) 349,800(a) (Waterford-Long Island Sound) 1975 482,247(a) 461,100(a) 832,842 810,900 Montville Plant Steam 1954-1971 489,900 492,000 (Montville-Thames River) 2 Diesels 1967 5,500 5,500 495,400 497,500 Northfield Plant Pumped 1972-1973 448,380(a) 530,000(a) (Northfield and Erving, Storage Massachusetts-Connecticut River) Devon Plant Steam 1942-1958 429,000 463,000 (Milford-Housatonic River) Gas Turbine 1966 16,320 18,700 445,320 481,700 l

Name Plate Net Year Rating Capability Name, Town, Location Tyge Installed (Kilowatts) (Kilowatts) Norwalk Harbor Plant Steam 1960-1963 326,400 338,000 (Norwalk-Long Island Sound) Gas Turbine 1966 16,320 17,000 342,720 355,000 Shepaug Plant Hydro 1955 37,200 47,000 (Southbury-Housatonic River) Rocky River Plant-Pumped 1928-1952-31,000 31,000 (New Milford-Housatonic Storage River) Stevenson Plant Hydro 1919-1936 30,500 28,700 (Monroe-Housatonic River) 5 Small Hydro Plants 14,660 14,100 7 Gas Turbine Plants 153,532 172,800 Total Company Generating Plants 2,831,554 2,968,700 Regional Nuclear Generating Plants (Company Entitlements) Connecticut Yankee Atomic Power Company (Connecticut) (25% entitlement) Nuclear 1968 150,075 145,000 Maine Yankee Atomic Power Company (Maine) (7.2% entitlement) Nuclear 1972 58,193 59,600 Vermont Yankee Nuclear Power Corporation (Veracnt) (5.4% entitlement) Nuclear 1972 30,398 28,500 Yankee Atomic Electric Company (Massachusetts) i (15% entitlement) Nuclear 1961 27,750 26,400 Total Regional Nuclear Generating Plants 266,416 '259,500 Total Generating Plants 3 097,970 .3 228,200 1 1 (a) Represents Company's 53% share as tenant in common with other System companies. . i. _

As of December 31, 1979, the Company had 22 transmission-substations with an aggregate capacity of 9,812,489 kVA and 194 distri-bution substations with an aggregate capacity of 4,430,610 kVA. Its transmission system included 226 circuit miles of overhead 345 kV lines, 870 circuit miles of overhead 115 kV lines, 63 circuit miles of overhead 69 kV lines, 6 cable miles of 138 kV submarine cable and 12 cable miles of underground 115 kV cable. The Company's distribution system included 12,963 pole miles of overhead lines and 261 conduit bank miles of under-j ground lines. It has in service 147,690 line transformers with an i aggregate capacity of 5,465,173 kVA. [ As of that date the Company had 6 propane plants, 3 LNG holders, 7 gas storage holders with a total capacity of approximately 6,000 Mcf and approximately 1,736 miles of gas distribution mains. From January 1,1975, through December 31, 1979 the Company made gross property additions and betterments to utility plant aggregating $658,236,000 and retired or sold property having an aggregate cost of $137,619,000, resulting in net additions during that period of $520,617,000. J The Company occupies owned or leased office buildings and service buildings which house offices, storerooms and garages. The Company's properties are well maintained and in good operating condition. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, the Company, in the opinion of its counsel, has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to sell electricity and gas in the areas in which it is now supplying such service. In addition to the right to sell electricity and gas as set forth above, the franchises of the Company include, among others, rights and powers to manufacture, generate, purchase, ' ansmit and distribute electricity and gas, to sell electricity and gas at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of the Company include the power of eminent domain. Item 4. Parents and Subsidiariqs This information is unctanged from that reported in the Annual Report on Form 10-K filed by the Registrant for the year ended December 31, 1977 except that a subsidiary of the Registrant, The Windsor Locks Canal Company, which is not a sif.mificant subsidiary, was sold to the Dexter Corporation of Windsor Locks, Connecticut. i Item 5. Legal Proceedings On February 13, 1973, six' Connecticut municipalities which own and cperate municipal electric utility systems and purchase all or part of . -~

.~ their ele.ctric power from the Company, commenced an antitrust-action in. the United States District Court for the District of Connecticut against the Company, Northeast Utilities, ESLCO and the Service Company claiming treble damages in the amount of $64',500,000. The defendants have denied the allegations made by the plaintiffs, and the defendant, the Company, has filed a counterclaim for damages. Three of the plaintiffs (City of Groton, City of Norwich and Borough of Jewett City) have settled their. claims for amounts which have been accrued by the Company as of December 31, 1979 and have stipulated that their actions be dismissed with prejudice. Settlement negotiations with the three remaining plaintiffs (Town of Wallingford, Second Taxing District of the City of Norwalk and. Third Taxing District of the City of Norwalk) have terminated, and trial of i the action is presently under way. The Company's appeal from a June 30, 1973 order of the DEP which would require the undergrounding of a 345/115 kV transmission line crossing the Connecticut River at Haddam was substantially sustained in a June 29, 1978 court decision. However, that decision has been vacated on the ground that it was rendered beyond the statutory time period, and-the appeal must'be reargued and redecided. The Company estimates that the cost of the underground crossing would be'approximately $10,500,000, in 1983 dollars, if the DEP order is sustained. The following sections, which are included in " Item 1. Business", discuss additional legal proceedings: " Rates" for information with respect to rate and fuel adjustment clause proceedings before regulatory commissions and the courts; " Fuel for Generating Stations" for information with respect to the disposition of the action against Westinghouse Electric Corporation for its repudiation of its contract to supply uranium for Millstone Unit No. 3 and with respect'to the conversion of oil-fired generating units to_ coal; and " Regulatory and Environmental Requirements and Proceedings" for information with respect to proceedings involving generating plants and transmission lines and with respect to contingent liabilities of the Company, llELCO and WMEC0 under the Price-Anderson-Act for damages resulting from the Three Mile Island nuclear plant accident of March, 1979. Item 6. Increases and Decreases in Outstanding Securities and In-l debtedness (a) The Registrant had no increases or decreases in equity. securities during 1979. (b) and (c) The Registrant had no increases or decreases.in debt recurities during 1979. Item 7. Changes in Securities and Changes in Security for Registered Securities The Registrant.had no changes'either in securities or in-security for registered securities during 1979. i 9. ,+ -=,,

It,em S. Defaults upon Senior Securities There have been no material defaults upon any senior securit ies of the Registrant. Item 9. Approximate Number of Equity Security Holders The approximate number of holders of record of the Registrant's equity securities at Dectaber 31, 1979 was as follows: Number of Record Title of Class Holders Preferred Stock. $50 par value 8,922 Common Stock, $10 par value 1 It_em 10. Submission of Matters to a Vote of Security Holders Not applicable. Iten,11. Indemnification of Directors and Officers This information is unchanged from that reported in the Annual Report on Form 10-K filed by the Registrant for the year ended December 31, 1977. Item 12. Financial Statements, Exhibits Filed, and Reports on Form 8-K (a) 1. Financial Statements: The financial statements, including supporting schedules, are listed in the Index to Financial Statements filed as part of this Form 10-K. 2. Exhibits: A. Annual Report to Shareholders for the year ended December 31, 1979. B. Forms of proposed amendments to NEP00L Agreement, as amended.

• C.

The Company's quarterly report on Form 10-Q for the quarter ended March 31, 1979.

• D.

The Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1979.

• E.

The Company's quarterly report on Form 10-Q for the quarter ended September 30, 1979. )

I'

• F.

The Company's Current Report on Form 8-K dated February 8, 1979.

• G.

The Company's Current Report on Form 8-K dated June 27, 1979.

• H.

The Company's Current Report on Form 8-K dated Septembec. 26, 1979.

• Incorporated herein by reference to the files of the Securities and Exchange Commission.

(b) No reports on Form 8-K were. filed for the three months ended December 31, 1979. 1 4 I J.

PART II Item 13. Security ownership of Certain Beneficial Owners and Management As of December 31, 1979, ~ the Directors of the Company beneficially owned the following number of Common Shares of Northeast Utilities, a i registered public utility holding company which holds all of the unissued and outstanding Common Shares of the Company. There were 66,593,960 shares of !!ortheast Utilities outstanding at December 31, 1979. Each of.the following represents an amount which is less than one percent of the total Common Shares outstanding. Amount of Northeast Utilities shares Beneficially Name Owned

• by Directors William B. Ellis 1,000 Walter F. Fee 1,103 Warren A. Greten 1,483 Lecn E. Maglathlin, Jr.

200 Herbert W. Sears 753 l Lelan F. Sillin, Jr. 5,000 Peter M. Stern 1,252 Donald C. Switzer 2,182 Walter F. Torrance, Jr. 4,339 Anthony E. Wallace 2,325 Amount Beneficially Owned

• by Directors and Executive Officers as a Group (consisting of 21 individuals) 24,359 9
• As that term is interpreted by the Securities and Exchange Commission.

a

Item 14. Directors and Executive Officers The following information is provided with respect to each director and executive officer of the Company. The terns of each position expire as of the Annual Meeting in 1980, except as otherwise noted. First First Became Elected an as a Name Age Position Officer Director Lelan F. Sillin, Jr. 61 Chairman, Chief Executive 4/14/69 3/20/68 Officer and Director Donald C. Switzer 63 Vice Chairman and Director 10/01/75 1/25/71 William B. Ellis 39 President and Director 6/15/76 6/15/76 Walter F. Fee 58 Executive-Vice President - 10/01/75 4/23/73 Engineering & Operations; Director Anthony E. Wallace 64 Executive Vice President - 4/15/64 7/01/66 Regional Administration; Director Philip T. Ashton 45 Vice President - Transmission 5/01/78 Engineering & Construction Albert G. Baer 59 Vice President - System 10/01/75 Transmission & Distribution Warren F. Brecht 47 Vice President - Management 6/06/77 Information Systems and Controller Carroll A. Caffrey 53 Vice President - Human 7/18/79 Resources William G. Counsil 42 Vice President - Nuclear 5/01/78 Engineering & Operations Raymond E. Donovan 49 Vice President - Customer 3/01/78 Services Warren A. Greten(l) 55 Vice President - Fossil & 10/01/67 4/23/73 Hydro Production; Director Francis L. Kinney 47 Vice President - Public 4/04/69 Affairs Leon E. Maglathlin 53 Director 12/01/74 Jack R. McClendon 63 Vice President & General 4/01/78' Manager - Gas Leonard A. O'Connor 53 Vice President & Treasurer 2/16/70 Walter T. Schultheis 53 Vice President - Power Supply 7/18/79 Planning and Research Herbert W. Sears 61 Vice President - Purchasing 3/01/77 11/01/78 & Stores; Director Peter M. Stern 55 Vice President - Corporate 5/01/78 12/20/71 & Environmental Planning; Director Walter F. Torrance, Jr. 52 Vice President & General 3/01/78 4/17/78 Counsel; Director ' Robert W. Bishop 36 Secretary 5/01/78 (1) Mr. Greten resigned as a Vice President and a Director effective January 1, 1980. i l Name Business Experience During Past 5 Years Lelan F. Sillin, Jr. Chairmansince197g;responsiblefortheformulation of overall policy. Donald C. Switzer Elected Vice Chair =n in 1978, previously Executive Vice President (1976) of an affiliate since 1971; responsible for engineering and operations. Willian B. Ellis Elected President in 1978, previously Vice President (1976); responsible for finance and administration. Prior to joining the Company he was a partner in the Washington, D.C. office of the management consulting thefirm'sutilitypractice.jacipal-in-chargeof firm of McKinsey & Co. as pr Walter F. Fee Elected Executive Vice President in 1978, previously Vice President (1975) of an affiliate since 1971. Anthony E. Wallace First Elected Executive Vice President in 1966.3 Philip T. Ashton Elected Vice President in 1978, previously Director of transmission engineering and construction of an affiliate. Albert G. Baer Elected Vice President in 1975, previously Vice President of Operations of an affiliate. Warren F. Brecht Elected Vice President in 1977 and Controller in 1979; previously had been Assistant Secretary for Administration, U.S. Department of the Treasury. Carroll A. Caffrey Elected Vice President in 1979; previously Director-Industrial Relations (1973) and Director-Human Resources Group (1978). William G. Counsil Elected Vice President in 1978; previously Plant Superintendent for the nuclear units (1974) and Project Manager for a third unit (1976). Raymond E. Donovan Elected Vice President in 1978; previously Director of Corporate Development of an affiliate since 1973.4 Warren A. Greten First elected a Vice President in 1967 with responsi-bilities including engineering and operations and system production. Francis L. Kinney First elected a Vice President in 1974 with responsi-bilities including Corporate Secretary and Senior Counsel. Leon E. Maglathlin Elected Vice President of an affiliate in 1969 and Chie Administrative Officer of that affiliate in 1974 Name Business Experience During Past 5 Years Jack R. McClendon Elected Vice President in 1978; previously Division Manager since 1973. Leonard A. O'Connor Electgd Treasurer in 1970 and Vice President in 1975 Walter T. Schultheis Elected Vice President in 1979; previously Director-Capacity Planning (1974) and Director-Research and System Planning (1977). Herbert W. Sears Elected Vice President in 1964. Peter M. Stern Elected Vice President of an affiliate in 1968 with responsibilities for corporate and environmental planning. Walter F. Torrance, Jr. Elected Vice President in 1978; previously had been partner in the law firm of Carmody and Torrance in Waterbury, Connecticut and had represented the Company and its a regulatory and legal proceedings.ffiliates in Robert W. Bishop Elected Secretary in 1978, having been Assistant Secretary since 1977; previously had been associated with the Connecticut Energy Agency and the Connecticut Department of Planning and Energy Policy. 1Director of Irving Bank Corporation and its principal affiliate, Irving Trust Company, Hartford Steam Boiler Inspection and Insurance Company and Arthur D. Little, Inc. 2Director of CBT Corporation and its principal affiliate, Connecticut Bank and Trust Company. 3Director of Connecticut Water Service, Inc. Mohasco Corp., Society for Savings and the Connecticut Mutual Life Insurance Co. 4Director of Central Bank for Savings. 5Director of Third National Bank of Hampden County. 6Director of Bay Bank Valley. 7Director of MacDermid, Inc., The Woodbury Telephone Company and The Connecticut National Bank..

h There are no family relationships between any director or executive officer and any other director or executive officer of the Company. There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any director or executive officer during the past five years. Item 15. Management Remuneration and Transactions The Company is a wholly owned subsidiary of Northeast Utilities, a registered public utility holding company. All remuneration of officers of the Company, like other subsidiaries of~ Northeast Utilities, is received in the form of salaries paid by Northeast Utilities Service Company. All remunerations paid by the System and its subsidiaries during the year 1979 to each of the five highest paid Trustees or officers of the System or executive officers or Directors of its subsidiaries whose aggregate remuneration exceeded $50,000, and to all Trustees and officers of the System or executive officers or Directors of it s subsidiaries as a group, appears below. Cash and Cash-Equivalent Forms of Name of Individual Capacities in which Served (1) Remuneration (2) Lelan F. Sillin, Jr. Chairman of the Board and Chief $193,666 Executive Officer of Northeast Utilities Donald C. Switzer Vice Chairman of Northeast Utilities $128,933 William B. Ellis President of Northeast Utilities $121,400 Anthony E. Wallace Executive Vice President of Northeast $102,968 Utilities Walter F. Fee Executive Vice President of Northeast $ 88,069 Utilities Service Company All Trustees and officers of Northeast Utilities as a group, consisting of 22 i individuals as of 12/31/79 (which does not include Messrs. Wallace or Fee or any other individuals who are officers only of the subsidiaries) $876,491 (1) Each of the named individuals also served as an officer and a l Director of various subsidiaries of the System. l F (2) No. individuals receive benefits under life, health, hospitalization or medical reimbursement plans which are not available generally to all salaried employees. (3) Not included are contributions by the System and its subsidiaries under the retirement plan since such contributions cannot readily be calculated for individual participants in the plan. The aggregate contributions accrued in 1979 by the System and its subsidiaries on behalf of plan participants amounted to 12.24% of the total amount paid in wages to such participants. Additional information is set forth below. (4) Employees of Northeast Utilities and its subsidiaries, including the officers listed in the table above, are entitled to receive retirement benefits under a plan which provides for defined benefits in the event of retirement at a specified age and after a specified number of years of service, except as mentioned below in the case 3 of Mr. Sillin. Aggregate contributions are made annually to the retirement plan for the benefit of all employees covered by the plan. z The following table shows the estimated annual retirement benefits payable under the retirement plan assuming that retirement occurs at age 65, which for the officers listed above will occur with between 28 and 33 years of credited service. The benefits as presented do not take into account any reduction for joint and survivorship annuity payments. Annual Pension for Years of Participation Indicated Average Annual Earnings For the Highest Consecu-tive 60 Months of Last 120 Months Prior to Years of Service Normal Retirement 25 30 35 $ 75,000 $27,525 $ 33,030 $ 38,535 100,000 36,900 44,280 51,660 125,000 46,275 55,530 64,785 150,000 55,650 66,780 77,910 175,000 65,025 78,030 91,035 200,000 74,400 89,280 104,160 225,000 83,775 100,530 117,285 (5) Mr. Sillin was President of Central Hudson Gas & Electric Corporation prior to joining Northeast Utilities as President in April,1968. A contract entered into between Mr. Sillin and Northeast Utilities Service Company at the time of his employment provides that Mr. Sillin's benefits upon retirement will be computed as if his period of service with and compensation payable from Central Hudson Gas & Electric Corporation were counted as employment with and compensation from Northeast Utilities Service Company, but that'such benefits will be reduced by the value of retirement benefits payable to Mr. Sillin under Central Hudson's retirement plan. An additional ! (

N accrual of $49,248 to a separate reserve account was made in 1979 to satisfy Northeast Utilities' supplementary obligation under this contract. Directors of the Company do not receive any compensation for their service as a Director. 1 I i i i l f I i a 1 -l i i i _

SIGNATURE Pursuant to the requirements _of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. THE CONNECTICUT LIGHT AND POWER COMPANY (Registrant) Date March 28,1980 By /s/ William B. Ellis William B. Ellis President 1 i l~ l THE CONNECTICUT LIGHT AND POWER COMPANY INDEX TO FINANCIAL STATEMENTS Report of Independent Public Accountants - Incorporated herein by reference to page 15 of Registrant's Annual Report to Shareholders, a copy of which is submitted with this Form 10-K as Exhibit A. Financial Statements - All of which are incorporated herein by reference to pages 2 to 15 of Registrant's Annual Report to Shareholders, a copy of which is submitted with this Form 10-K as Exhibit A. Statements of Income for the years ended December 31, 1979 and 1978 Statements of Retained Earnings for the years ended December 31, 1979 and 1978 Statements of Sources of Funds for Gross Property Additions for the years ended December 31, 1979 and 1978 Balance Sheets at December 31, 1979 and 1978 Notes to Financial Statements at December 31, 1979 and 1978 Page Supplementary Note to Financial Statements F-2 Report of Independent Public Accountants on Schedules S-1 Schedules: V-Utility Plant (including Intangibles and excluding Nuclear Fuel) - Years Ended December 31, 1979 and 1978 S-2 -- S-3 V-Nuclear Fuel - Years Ended December 31, 1979 and-1978 S-4 -- S-5 VI - Accumulated Provision for Depreciation of Utility Plant - Years Ended December 31, 1979 and 1978 S-6 -- S-7 Y XII - Reserves - Years Ended December 31, 1979 and 1978 S-8 -- S-9 Schedules other than those listed above have been omitted because they are either not required or are not applicable, or because the required information is included in the financial statements or notes thereto. i F-1

THE CONNECTICUT LIGHT AND POWER COMPANY SUPPLEMENTARY NOTE TO FINANCIAL STATEMENTS DECEMBER 31, 1979 and 1978 (A) Supplemental Information to Statements of Income Year Ended December 31, 1979 1978 (Thousands of Dollars) Taxes, other than income taxes, charged to tax expense: State gross earnings $27,361 $22,338 Real and personal property 19,231 19,573 Payroll and other 4,152 3,279 150.,744 $45,L90 j Consent of Independent Public Accountants As independent public accountants, we hereby consent to the applica-tion of our report dated February 20, 1980 in the Company's Annual Report to Shareholders included in this Form 10-K to the supplemental note to financial statements. It should be noted that we have performed no audit procedures subsequent to February 20, 1980, the date of our report. Furthermore, we have not made an examination of any financial statements of the Company as of any date or for any period subsequent to December 31, 1979. ARTHUR ANDERSEN & CO. Hartford, Connecticut, March 24, 1980. F-2

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES In connection with our examination of the financial statements included in the Company's Annual Report to Shareholders filed with this Form 10-K, we have also examined the supporting schedules listed in the accompanying index. In our opinion, these schedules present fairly, when read in conjunction with the related financial statements, the financial data required to be set forth therein, in conformity with generally accepted accounting principles applied on a basis consistent with that of the preceding year. ARTHUR ANDERSEN & CO. Hartford, Connecticut, Februa ry 20, 1980. S-1

I.. THE CONNECTICUT LIGHT AND P0kER COMPANY UTILITY PLANT (INCLUDING INTANGIBLES AND EXCLUDING NUCLEAR FUEL) 'E YEAR ENDED DECEMBER 31, 1979 6 (Thousands of Dollars) COL. A COL. B COL C COL. D COL. E COL. F Balance at Other Changes-Balance beginning Additions Add (Deduct)- at close . Classification of period at cost Retirements Describe of period. - OWNED PROPERTY Utility Plant in' Service Electric $1,385,778 $ 36,737 $10,257 $ (1,205)(2) $1,411,106 53 (3) Gas 120,646 5,598 1,889 1,205 (2) 125,549 (11)(6) Construction Work in Progress Electric 288,796 71,548 (1) (41,416)(5) 318,730 (198)(4) y u Gas 1,325 883 (1) 2,208 Utility Plant Held for Future Use 712 255 967 Electric TOTAL OWED $1,797,257 $115,.02_1 $12,146 $(41,572) $1,858,560 (1).. Net. increase (decrease) during the year. (2) Transfer between electric and gas property. (3) ' Adjustment of prior year retirement. (4) Sale of substation. (5)- Sale of 71 interest of 11.5% ownership in Seabrook. (6) Transfer between Utility Plant in Service and Nonutility Property.

7 THE CONNECTICUT LIGHT AND POWER COMPANT UTILITY PLANT (INCLUDING INTANCIBLES AND EXCLUDING NUCLEAR FUEL) YEAR ENDED DECEMBER 31, 1978 (Thousaids af Do11xra) COL. A COL. 5 COL. C COL. D CDL. E COL. F Balance at Other Changes-Balance beginning Additions Add (Deduct)- at close Classification _ of period at cost Retirements Describe of period OWNED PROPERTY Utility Plant in Service Electric * $1,177.832 $69,848 $12,979 76 (2) $1,385,778 151,008 (4) (9) (3) 2 (5) Gas 107,776 4,191 562 9,231 (4) 120,646 10 (3) Construction Work in Progress Electric 259,642 38,755 (1) 2,008 (4) 288.796 (2.625) (6) (2,762) (7) (6,222) (8) 59 (4) 1,325 Gas 2,090 (824) (1) Utility Plant Held for Future Use m Electric 559 229 (76) (2) 712 ta. TOTAL OWNED 1.547.899 , _112.199 13.541 150.700 _1.797.257 LEASED PROPERTY Utility Plant in Service Electric 145,894 6,922 1,808 (151,008) (4) Cas 8,600 684 52 (9,232) (4) Construction Work in Progress Electric 2.965 (958) (1) (2,007) (4) Ces 320 (261) (1) (59) (4) TOTAL LEASED 157.779 6.387 1.860 (162.306) TOTAL $1.705.678 $118.586 $15.401 $ (11.606) $1.797.257 (1) Net increase (decrease) during the year. (2) Transfer between Utility Plant in Service and Utility Plant Held for Future Use. (3) Transfer between electric and gas property. m (4) Transfer of leasehold improvements between owned and leased property. This.resulted f rom the purchase of property @r-formerly leased from Connecticut Railway and Lighting Company. 2 (5) Adjustment of prior year retirement. h (6) Sale of substation. >-*e (7) Sale of.5% interest of 12% ownership in Seabrook. (8) Sale and lease back of substation equipment and buildings.

^ s s Y s sn ? THE CONNECTICITT LIGHT AND PohER COMPA.T N k: NUCLEAR FUEL YEAR ENDED DECEMBER 31 -1979 f- .(Thousands of Dollars) < =. 4 -Z, 4 ~ COL. A COL. A - ~ COL. C COL. D COL. E COL. F Balance at .Other Changes - ' Balance 1eginning ' Additions Add (Deduct)- at close Classification'- of period at cost Retirements Describe of period

Nuclear fuel'in process of refinement,

$11,095 4 . conversion, enrichment and fabrication $7,288 $6,<,20 $2,613 (1) . Accumulated provision for amortization (1.900)(2) (1,900) of nuclear fuel' assemblies.4 TOTAL NUCLEAR IVEL - $L288_ $pd2p $2f12 } @ 900) $ 9,195~ '{1)- During 1979, CIAP sold a portion of its 11.5% ownership in the Seabrook ' Plant being built in New Hampshire and the related nuclear fuel in process. -(2)'. Reclassification of r.uclear fuel disposal costs. L 3 A d u 'V e~ s. -f~

• k

-. m .l. m.' i. 1 m m.

THE CONNECTICUT LIGHT AND POWER COMPANY NUCLEAR FUEL YEAR ENDED DECEMBER 31, 1978 (Thousands of Dollars) COL. A COL. B COL. C COL. D COL. E COL. F Balance at Other Changes-Balance beginning Additions Add (Deduct)- at close Classification of period at cost Retirements Describe of period Nuclear fuel in process of refinement, conversion, enrichment and fabrication $5,202 $2,209 $123 (1) $7,288 (1) During 1978, CL&P sold a portion of its 12% ownership in the Seabrook plant being built in New Hampshire and the related nuclear fuel in process. Y. v e s l Ng W

y. a r-. M ( m. THE CONNECTICUT LIGHT AND POWER COMPANY ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT YEAR ENDED DECEMBER 31, 1979 -6: (Thousands of Dollars) f* w COL. A COL. B COL. C - COL. D -COL. E COL. F Additions Balance at Charged to Other Changes-Balance beginning Costs and . Add (Deduct). 'at close Description of period Expenses Retirements Describe of period ~_ ACCUMULATED Plt 0 VISION FOR-DEPRECIATION OF UTILITY m

PIMT A

Electric'. $341,569 $47,709 $ 8,491 .$1,092'(1) $381,879 Gas 20,646 3,216 1,967 _ 180 (1) 22.075 . Total _ $362,215 $50 925 $10,458 11,272 $403 M 2 (1)[ Depreciation charged.to Transportation and Fuel Stock Clearing Accounts. \\ m P r mm.-

THE CONNECTICUT LIGHT AND POWER CDMPANY ACCUMULATED PROVISION FOR DEPRECIATION OF UTILIIY PLANT YEAR ENDED DECEMBER 31, 1978 (Thousands of Dollars) COL. A COL. B COL. C COL. D COL. E COL. F Additions Balance at Charged to Other Changes-Balance at beginning Costs and Add (Deduct)- close of Description of period Expenses Retirements Describe period ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT U N Electric $304,636 $46,999 $11,796 $1,703 (1) $341,569 27 (2) Gas 18.178 2,907 780 274 (1) 20,646 67 (2) Total $32_2J14 SM $12,576 $g $g (1) Depreciation charged to Transportation and Fuel Stock Clearing Accounts. (2) Termination of lease with Connecticut Railway & Lighting Corporation. ?2 -lr s

1 THE CONNECTICUT LIGHT AND POWER COMPANY - un RESERVES Er 1 YEAR ENDED DECEMBER 31, 1979 E. (Thousands of Dollars) _h M COL. A COL. B COL. C COL. D COL. E Additions (1) (2) Balance at Charged to Charged to Balance Beginning Costs and Other Deductions-at End Description. of Period Expenses Accounts Irescribe of Period-RESERVES DEDUCTED FROM ASSETS ..TO WHICH THEY APPLY: Reserves for uncollectible accounts $1,899 Q $l 502 (a)- j_2,060 t [ . RESERVES NOT APPLIED AGAINST ASSETS: Injuries'and damages (b) $ 991 $ 972 $ 968 (c) $ 995 3,159 2,223.(d) 936 Medical. insurance (e)

TOTAL

$ 991 $4jl31 $3,191- $1 931 ~ 2 (a) - Amounts. charged off as uncollectible after deducting customers' deposits and ' recoveries of accounts previously charged'off.

(b) Provided to cover claims for injuries to employees, for workmen's compensation and for bodily injury to others and. property damage.

(c) Principally payments for various injuries and damages and expenses in connection therewith. (d) Principally payments for various employee medical expenses and expenses in connection therewith. (e).Provided to' cover claims for employee medical; insurance.

THE CONNECTICUT LIGHT AND POWER COMPANY RESERVES YEAR ENDED DECEMBER 31, 1978 (Thousands of Dollars) COL. A COL. B COL. C COL. D COL. E Additions (1) (2) Balance at Charged to Charged to Balance Beginning Costs and Other Deductions-at End Description of Period Expenses Accounts Describe of Period RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $1,716 $2,808 $2,625 (a) $1,899 RESERVES NOT APPLIED AGAINST ASSETS: Y Injuries and damages (b) $ 993 $ 747 $ 749 (c) $ 991 (a) Amounts charged off as uncollectible after deducting. customers' deposits and recoveries of accounts previously charged off. (b) Provided to cover claims for injuries to employees, for workmen's compensation and for bodily injury to others and property damage. (c) Principails "myr*nts for various injuries and damages and expenses in connection therewith. N iii ir W ~

. -f'I {l Y ,.r. . " ^ .g9-W ' g' \\ m- + + - 4 -{'"' r f o e'*+ m g g ~ b 4 r ..g* g, < 3 -.

1. 7, b,,

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The Connecticut Light and Power Company March 14,1980 To the Shareholders: The Annual Report of Northeast Utilities, which provides coverage of the entire Northeast Utilities system, including The Connecticut Light and Power Company, has been mailed to all CL&P preferred stockholders. This report is brief for that reason. The financial statements and statistical data included in this report show the results of operations of the Company in 1979. As you will note, the Company's earnings showed a decline during 1979 and remained l significantly below the return allowed by the Connecticut Division of Public Utility Control (DPUC). Additional revenues generated by a $53.7 million rate increase, approved by the DPUC in June of 1979, were offset by the effects of rapid inflation, higher fos I fuel costs, expenses required for service restoration following storms, costs associated with im-plementing new requirements of the Nuclear Regulatory Commission as well as higher short-term interest rates. In addition, earnings were adversely affected by a lower level of nuclear generation than in 1978 and the operation, during the last five months of the year, of the Generation Utilization Adjustment Clause (GUAC), which was authorized by the DPUC as part of its 1979 rate decist.on. The GUAC should have a stabilizing effect on earnings in the future, however. The Company expects to file shortly for increased electric and gas rates. Carroll A. Caffrey and Walter T. Schultheis were elected Vice Presidents in 1979. Robert S. Bromage, Vice President, retired after 43 years of system service and Warren A. Greten, Vice President, resigned after 30 years of system service. Warren F. Brecht, previously Vice President - Financial Control and Information Services, was named Vice President - Management Information Systems and Controller when Warren A. Hunt became System Director - Revenue Requirements. Sincerely, e

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President Chairman l 1

The Connecticut Lightcnd Pow rCompany STATEMENTS OF INCOME For IIse Years Ended December 31, 1979 1978(a) (Tisotosartds of Dollars) Operating Revenues (Note 2) 5591,626 5505.838 Operating Expenses: Operation - Fuel used in generation 162,295 114,422 Cas purchased for resale 54,519 46,975 Other 121,723 100,536 Maintenance 43,163 37,024 Depreciation 50,925 49,906 Federal and stre income taxes (Note 3) 9,480 13,305 Taxes other than income taxes 50,669 45.109 Total operating expenses 492,774 407,27/ Operating income 98,852 98,561 Other income: Allowance for equity funds used during construction 9,542 10,473 Equity in earnings of regional nuclear generating companies 2,878 2,097 Other, net (737) 342 Income taxes applicable to other income-credit (Note 3) 639 424 Net other income 12,322 13.336 Income before interest charges 111,174 111.897 Interest Charges: Interest on long-term debt 57,099 56,319 Other interest 7,279 4,757 l Allowance for borrowed funds used during construction (11,051) (10.654) Total interest charges 53,327 50.422 Net Income (Note 2) S 57,847 5 61,475 (a) The 1978 financial statements have been restated, as discussed in Note 10. STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1979 1978 f Thotosands of Dollars) Italance at beginning of period 5170,948 $158,747 Net income 57,847 61,475 Cash dividends on preferred stock (14,645) (14,644) Cash dividends on common stock (33,179) (34.630) Italance at end of period (a) $180,971 5170.948 (a) At December 31, 1979, retained earnings of 567,000,000 were available for payment of cash dividends on common stock under the provisions of the Company's Indenture of Mortgage and Deed of Trust. Th : accompanying notes are an integral part of these financial statements. 2

The Connecticut Light and Power Company STATEMENTS OF SOURCES OF FUNDS FOR GROSS PROPERTY ADDITIONS For tise Years Ended December 31, 1979 1978(a) (Titousands of Dollars) Fus.Js Generated From Operations Net Income S 57,847 5 61,475 Principal noncash items - Depreciation 50,925 49,906 Deferred income taxes, net 6,004 9,557 Amortization of deferred charges and other noncash items 2,544 3,476 Amortization of deferred fuel costs 2,553 1,413 Allowance for funds used during construction (20,593) (21,127) Total funds from operations 99,280 104,700 Less - Cash dividends paid on: Common stock 33,179 34,630 Preferred stock 14,645 14,644 Net funds generated from operations 51,456 55,426 Funds Obtained from Financing Increase in short-term debt 40,045 1,105 Proceeds from issuance of long-term debt 39,755 Repayment of long-term debt (31) (16,031) Net funds from financing 40,014 24,829 Other Sources (Uses) Of Funds Decrease (increase) in net current assets (excluding short-term debt, long-term debt due within one year and preferred stock to be redeemed within one year): Cash and special deposits 3,500 3,573 Receivables and accrued utility revenues (29,834) (7,071) Fuel, materials and supplies (14,579) (3,200) Accounts payable 27,655 (3,421) Accrued taxes 2,374 2,352 Revenues to be refunded to customers (Note 2) 10,022 Other, net (21,218) 6,194 Net change (32,102) 8,449 Sales of utility plant (Note 9) 44,227 11,732 Energy adjustment clauses, net (7,185) 306 Other, net 4,437 (1,074) Net other sources (uses) of funds 9,377 19,413 Total Funds for Construction From Above Sources 100,847 99,668 Allowance For Funds Used During Construction 20,593 21,127 GROSS PROPERTY ADDITIONS S121,440 $120,795 Composition Of Gross Property Additions: Electric utility plant $108,540 5114,796 Gas utility plant 6,480 3,790 Nuclear fuel 6,420 2.209 Total S121,440 5120.795 (a) The 1978 financial statements have been restated, as discussed in Note 10. The accompanying notes are an integral part of these financial statements. 3

The Connecticut Light and Power Company BALANCE SHEETS At December 31, 1979 1978 (Thousands of Dollars) ASSETS Utility Plant, at original cost: Electric S1,412,073 51,386,490 Gas 125,549 120.646 1,537,622 1,507,136 Less: Accumulated provision for depreciation 403,954 362,215 1,133,668 1,144,921 Construction work in progress (Note 9) 320,938 290,121 Nuclear fuelin process, net 9,195 7,288 Total net utility plant 1,463,801 1,442,330 Other Property and Investments: Investments in regional nuclear generating companies, at equity 24,743 23,643 Investments in subsidiary companies, at equity 4,746 5,743 Other, at cost 5,826 5,816 35,315 35,202 Current Assets: Cesh and special deposits (Note 4) 1,561 5,061 Receivables, less accumulated provision for uncollectible accounts of S2,060,000 in 1979 and $1,899,000 in 1978 60,475 44,944 Due from affiliated companies 25,873 15,935 Accrued utility revenues 29,347 24,982 Fuel, materials and supplies, at average cost 49,584 35,005 Prepayments and other 2,029 84'7 168,869 126,774 Deferred Charges: Unamortized debt expense 1,777 1,938 Energy adjustment clauses, net 9,174 4,157 Other 6,882 9,190 17,833 -15,285 Total Assets S1,685,818 51,619,591 The accompanying notes are an integral part of these financial statements. 4

At Decernber31, 1979 1978 (Thousands of Dollars) CAPITAI.IZATION AND LIABILITIES Capitalization: Common stock - 510 par value. Authorized 20,000,000 shares; outstanding 8,931,014 shares S 89,310 $ 89,310 Capital surplus, paid in (no change during years) 208,614 208,614 Retained earnings 180,971 170,948 Total common stockholder's equity 478,895 468,872 Preferred stock not subject to mandatory redemption (cumulative) - $50 par value. Authorized 5,600,000 shares: outstanding 3,500,000 shares (Note 5) 175,000 175,000 Preferred stock subject to mandatory redemption (cumulative)- $50 par value. Authorized 400,000 shares: outstanding 400,000 shares (Note 6) 19,000 20,000 Long-term debt, net (Note 7) 756,596 771,541 Total capitalization 1,429,491 1,435.413 Current Liabilities: Notes payable to banks (Note 4) 23,000 5,500 Commercial paper (Note 4) 65,245 42,700 Long-term debt due within one year (Note 7) 15,031 31 Preferred stock to be redeemed within one year (Note 6) 1,000 Accounts payable 21,531 10,528 Due to affiliated companies 38,042 22,118 Accrued taxes 25,953 23,579 Accrued interest 18,848 19,974 Revenues to be refunded to customers (Note 2) 14,720 Other 7,385 8,074 216,035 147,224 Deferred Credits: Accumulated deferred income taxes 7,864 7,490 Accumulated deferred investment tax credits 26,914 22,456 Other 5,514 7,008 40,292 36,054 Commitments and Contingencies (Notes 2 and 9) Total Capitalization and Liabilities S1,685,818 51,619,591 5

The Connecticut Light and Power Company NOTES TO FINANCIAL STATEMENTS (1)

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES Generah The Connecticut Light and Power Company (the Company), 'The Hartford Electric Light Company (HELCO), Western Massachusetts Electric Company (WMECO) and Holyoke Water Power Ccmpany are the principal operating subsidiaries comprising the Northeast Utilities system (the system) and are wholly owned by Northeast Utilities, a registered holding company under the Public Utility Holding Company Act of 1035. Other wholly owned subsidiaries of Northeast Utilities providing substarttial support services to the system operating companies include Northeast Utilities Service Company (NUSCO) (a system service company supplying centralized administrative, accounting, engineering, financial, legal, operations, planning, purchasing and other services to the system companics), Northeast Nuclear Energy Company (NNECO) (agent for the system companies in construction and operation of nuclear generating facilities and the financing of nudear fuel for such facilities) and The Rocky River Realty Company and The Quinnehtuk Company (each a real estate ccmpany which rents administrative facilities to the system companics). All transactions among affiliated companies are on a recovery of cost basis, except for transactions with NNECO, which also include amounts representing a return on equity, and are subject to approval of various federal and state regulatory commissions having jurisdiction. The Company and HELCO have consolidated their operations by means of a transfer of all HELCO regional personnel (other than production personnel) to the Company. The Company is responsible for meeting the local service needs of customers of both companies and bills HELCO for work performed for HEl.CO on a recovery of cost b,uis. The Company and HELCO have been investigating the feasibility of a corporate nwrger, ;n which the Company would be the surviving corporation. i The Company is part of a New England buik power system which provides for purchases and sales of electric energy through a regional di patch control agency, Arrangements among ) the Company and system companies, outside agencies and other utilities covering inter-connections, interchange of electric power and sales of utiSty property are subject to regulation by the Federal Energy Regulatory Commission (FERC) or the Securities and Ex-change Commission (SEC). The Company is subject to further rn;ulation by FERC and the Connecticut Division of Public Utility Control (DPUC) and follows the accounting policies prescribed by the respectwe commissions. 1 The Company is a part owner with other system and New England electric utilities of the stock of four regional nuclear generating companies. These companies, together with the Company's ownership interest shown parenthetically are: Connecticut Yankce Atomic Power Company (25 percent), Yankee Atomic Electric Company (15 percent), Maine Yankee Atomic Power Company (8 percent) and Vermont Yankee Nuclear Power Corporation (6 percent). The Company's investment in these companies is accounted for on an equity basis. The electricity produced by these facilities is committed to the participants based cn their ownership interests and is billed pursuant to contractual agreements which are approved by FERC. Recemees: Revenues are based on authorized rates applied to customer consumption of utility services. Rates may not be increased without a formal proceeding before the appropriate i regulatory commission. The Company accrues an estimate for energy Jelivered but unbilled at the end of accounting periods. q Nuclear Fuel: The Company, HELCO and WMECO own Millstone I and 11 as tenants in common. NNECO owns the nuclear fuel for such units. The cost of NNECO's nuclear fuel is amortized on a unit-of-production method at rates based on estimated kilowatt hours of (nergy to be provided and is billed to the companies based on their percentage ownership in the units. The amount of nuclear fuel expense charged to the Company, based on its 53 percent ownership, aggregated 513.543,000 and $10,404,000 in 1979 and 1978, respectively. This includes a provision in 1979 for estimated spent nuclear fuel disposal costs on the Millstone units which the Company is allowed by the DPUC ; collect from customers: however, amounts collected from customers must be deducted from rate base. The Compa iy is not paying NNECO, the owner of the nuclear fuel, until NNECO has to make payments for 6

such costs, The unpaid spent nuclear fuel costs, which amounted to $1,900 000 in 1979, were transferred frcm accounts payable to the accumulated provision for amortization of nuclear fuel assemblies. As approved by the DPUC, the estimated spent fuel disposal costs pertaining to fuel amortized prior to 1979 are being amortized over a ten-year period. StoraSe for spent fuel at the Millstone nuclear station, including the facilities currently under construction at Millstone 111, will be sufficient until at least the mid-1990's. Depreciation: The provision for depreciation is computed using the straight-line method at approved rates which are based on the estimated service lives of depreciable utility plant in service and estimated removal costs less expected salvage. The depreciation rates for the several classes of electric plant, which are equivalent to a composite rate of 3.5 percent in 1979 and 3.7 percent in 1978, and for several classes of gas plant, which are equivalent to a com-posite rate of 2.8 parcent in 1979 and 2.7 percent in 1978, are applied to the average plant in service during the year, other than for major facilities which are depreciated from the time such facilities are placed in service. At the time depreciable property is retired from service, the original cost, plus cost of removal less salvage of such property, is charged to the ac-cumulated provision for depreciation. A study completed in 1979 indicates that the complete removal commencing at the time of retirement of the two nuclear units in which the Company has a 53% ownership interest is the most viable and economic method of decommissioning these units. The Company's share of the total estimated decommissioning cost is $70.8 million. Depreciation rates recognized for regulatory rate setting for the Company include an element of decommissioning costs. It is e*timated that, at such time as the costs indicated in the 1979 study are allowed by the DPUC, depreciation expense will increase from approximately $1.1 million per year for the Company to approximately $2.8 million per year. Maintenance: The cost of maintenance, repairs and replacements of minor items of property is charged to maintenance expense. Replacements and renewals of items considered to be units of property are charged to the utility plant accounts. Federallncome Ta.res: The tax effect of timing differences (differences between the periods in which transactions affect income in the financial statements and the periods in whkh they affect the determination of income subject to tax), is accounted for as prescribed by and in accordance with the rate-making treatment of the applicable regulatory commissions. The Company follows the flow-through method except for FERC jurisdictional operations and the additional investment tax credits received as a result of the Tax Reduction Act of 1975, which requires normalization of such additional credits. It is expected that deferred taxes not provided for currently will be col lected m customers' rates when such taxes become payable. See Note 3 for the detail of income tax expense. Alloteance for Famh Used During Construction: The allowance for funds used during con-struction (AFUDC) represents the estimated cost of capital funds used to finance the Com-pany's construction program. The costs of construction are not recognized as part of the rate base for rate-making purposes until facilities are brought into service and, as permitted by applicable regulatory commissions, the Company charges AFUDC to the construction cost of utility piant. The AFUDC rate applied to construction work in progress for 1979 and 1978 was 9 percent. Through 1979, the Company did not record the effect of compounding such rate. Effective January 1,1980, the Company adopted an AFUDC rate of 9.5 percent and also adopted, subject to the approval by the DPUC, net-of-income tax accounting treatment. In addition, AFUDC on Millstone !!! and on that portion of Seabrook not currently under contract to be sold will be compounded semi-annually. Retirement Flan: The Company participates in the Northeast Utilities Service Company Retirement Plan (the Plan). The Plan, which covers all regular employees, is non-contributory. The system's policy is to annually fund an actuarially determined contribution, which includes that year's normal cost, the amortization of prior years' actuarial losses over fifteen years, and the amortization of prior service costs over forty years. At December 31, 1979, it is estimated that the Plan's unfunded liability was approximately $111,200,000 and that the Plan's assets exceeded the value of vested benefits. The Company's allocated portion of the system's contribution, part of which was charged to utility plant, appioximated $9,600,000 in 1979 and 59,700,000 in 1978. 7

Energy ' Adjustment Clauses: The Company's retail electric and gas rates include adjustment - clauws under which certain foasil fuel and purchased power costs and purchased gas costs, respectively, above or below base rate levels are charged or credited to cuwomers. As prescribed by the DPUC, costs not currently recovered under the adjustment clauses are deferred until recovery is permitted by the DPUC. Effective August 1,1979, the Company implemented a Generation Utilization Ad-justment Clause (GUAC),'as approved by the DPUC. Monthly, this clause levelizes the elfect on fuel costs caused by variations from a 70 percent nuclear generation factor. At the end of the twelve-month period, ending July 31 of each year, any deferred balance resulting from the actual nuclear generation factor being above or below 70 percent will be either refunded to or collected from customers over the subsequent twelve-month period. For the period August 1, 1979 to December 31, 1979, the nuclear capacity factor was 76.6 percent, resulting in a leveling charge to fuel expense of $5,242,000. As of December 31,1979, the components included in the energy adiustment clauses, net are as follows: Fuel and Purchased Power $10.027,000 Cas Purchased for Resale 4,389,000 GUAC (5.242,000) Total 59,174,000 (2) RATE MATTERS in June 1979, the DPUC hsued a decision granting the Company an increase in retail electric and gas revenues of 553.7 million. The level granted was 61 percent of the $87.6 million the Company had requested. The new rates went into effect in July 1979. In January 1979, the DPUC approved the recovery of an aggregate of $6,588,000 by the Company from Ms electric and gas customers, representing previously unrecovered costs which were found by the Connecticut Supreme Court to have been improperly disallowed by the DPUC in its 1977 rate case decision. The recovery of the:;e costs was recorded in revenue-during the first half of 1979. The $14,720,000 of revenues to be refunded to customerr.3 of December 31, 1978 resulted from FERC approved tettlements between gas distribution companies and their gas suppliers which required refunds to ultimate castor ers. The refunds were passed on to the Company's customers by reducing their gas bills in 1 ebruary 1979. The Company has collected certain revenues subject to possible refund under wholesale rate casas filed with FERC Based on management's and its counsel's evaluations of the facts in j these cases, it is the opinion of management that, if refunds are required in excess of provisions which have been recorded, any additional amounts would not have a material effect on the Company's results of operations. (3) INCOMETAX EXPENSE The detail of federal and state income tax provisions charged to operations is set forth below: Year Ended December 31, 1979 1978 Current income taxes: Federal 5 656-S 113 State 2,131, 3,211 Total current 2,837 3,324 1 Deferred income taxes, net: Investment tax credits ' 5,630 10,210 Federal 210 (473) State 164 '(180) - Totaldeferred 6,004 9,557 ' Total income taxes S 8,841 512,881 8 u ___

Year Ended December 31, 1979 1978 fThousands of Dollars) Such provision (credit) is included in the accompanying statements of income as follows: Operating expenses S 9,480 513,305 Other income (639) (424) Totalincome taxes S 8,841 512,881 Deferred income taxes are comprised of the tax effects of timing differences as follows: Investment tax credits S 5,630 $10,210 LiberalizeJ depreciation 963 849 Unbilled revenues (1,254) (474) Settlement credits - nuclear fuel (2,007) Energy adjustment clauses 2,910 (788) Other (238) (240) Deferred income taxes, net S 6,004 5 9,557 The principal reasons for the difference between total tax expense and the amount calculated by applying the federal in-come tax rate to pretax income are as follows: Expected tax, at 46% of pretax income in 1979 (48% in 1978) 530,677 535,691 Tax effect of differences: Additional depreciation for tax purposes (7,896) (8,864) Allowance for funds used during construction - not recognized as income for tax purposes (9,473) (10,142) Overhead costs of construction - expensed for tax purposes (2,245) (2,217) Investment tax credits (2,812) (1,691) Allocated affiliated companies' losses (1,273) (1,517) Cost of removal - expensed for ta'x purposes (1,367) (697) State tax, net of federal benefit 1,266 1,576 Other, net 1,964 742 Total income taxes S 8,841 S12,881 Effective income tax rate 13 % 17% _ At December 31,1979, the Company had unused and unrecorded investment tax credits' amounting to approximately $9,600,000, which are available to offset federal income tax provisions for years through 1986. (4) SHORT-TERM DEBT The Company utilizes bank loans and commercial paper to finance temporarily its continuing construction program. The system companies have joint bank credit lines with terms calling for interest rates equal to the prime rate or the prime rate plus a fraction thereof, at the time of borrowing. The credit lines expire at various times in 1980 and, although these lines are . generally renewable, the continuing availability of the unused lines of credit is' subject to-review by the banks involved. At December 31, 1979,. the amount of unused available - borrowing capacity under the credit lines available to the Company was S164,505,000 however, substantially all of these joint credit lines are also available to other system com-panies. The maximum amount of short-term borrowings as currently authorized by the SEC is - $135,000,000. Essentially all of the cash of the Company represents compensating balances in support of the system's lines of credit; however, the compensating balances are not subject to contractual restrictions on withdrawal, l. 9 W l --(. g

Additional information with respect to short-term debt is as follows: 1979 1978 Weighted average interest rate for borrowings outstanding at end of period (excluding effect of compensating balances) 14.7 % 11.2 % Maximum amount of borrowings outstanding at any month-end $88,245,000 559,900,000 Average daily borrowings during period 549,228,000 539,189,000 Weighted average interest rate during the period (based on the daily amounts out-standing and excluding effect of compensating balances) 12.3 % 8.6% Rangeof maturities at December 31(in days) _ 2-91 2-47 (5) PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION 4 Details of preferred stock outstanding are as follows: Par Value Current Shares December 31, Des. ription Redemption Price Outstanding 1979 1978 (Thousands of Dollars) 52.00 Series of 1947 554.00 336,088 5 16,804 S 16,804 51.90 Series of 1347 52.50 163,912 8,196 8,196 52.20 Series of 1949 52.50 200,000 10,000 10,000 $2.04 Series of 1949 52.00 100,000 5,000 5,000 $2.06 Series E of 1954 51.00 200,000 10,000 10,000 $2.09 Series F of 1955 51.00 100,000 5,000 5,000 $3.24 Series G of 1968 52.65* 300,000 15,000 15,000 54.48 Series H of 1970 54.45* 300,000 15,000 15,000 54.48 Series I of 1970 54.56* 400.000 20,000 20,000 $3.80 Series J of 1971 54.00* 400,000 20,000 20,000 $4.56 Series K of 1974 54.36* 1,000,000 50,000 50,000 Total preferred stock not subject to mandatory redemption 3,500,000 S175,000 $175,000

• Redemption price reduces in tuture years.

All or any part of each outstanding series of preferred stock may be redeemed by the Company at any time at established redemption prices plus accrued dividends to the date of redemption. (6) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock outstanding are as follows: Par Value Current Sha. es December 31, Description Redemption Price Outstandin,e 1979 1978 (Thousands of Dollars! 55.52 Series L of 1975 55.52* 400,000 20,000-20,000 Less preferred st ack to be redeemed within one year (1,000) Total preferred stock subject to mandatory redemption 19,000 20,000

• Redemption price reduces in future years.

The Series L preferred stock (the Series) requires a sinking fund sufficient to retire a minimum of 20,000 shares at 550 per share each year commencing September 1,1980. In case of default on sinking fund payments, no payments may be made on any junior stock by way . of dividends or otherwise (other than in shares of junior stock) so long as the default con-tinues. The Company's preferred stock provisions would prohibit the redemption or purchase 10

of shares of the Series if th: Company is in arr::rs with respect to payment of dividends on - any outstanding shares of preferred stock, There were no changes during the year in the Series. All or part of the Series may be redeemed by the Company at any time at established redemption prices plus accrued dividends to the date of redemption, except that during the - initial five-year redemption period, the Series is subject to certain refunding limitations. (7) LONG-TERM DEBT Details of long-term debt outstanding are as follows: December 31, 1979 1978 fThousands of Dollars) First Mortgage Bonds: 3% Series K, due1980 S 15,000 5 15,000 23/4% Series L, due 1984 10,000 10,000 31/4% Series M, due 1982 35,000 35,000 31/4% Series N, due 1985 20.000 20,000 37/8% Series O, due 1988 30,000 30,000 47/8% Series P, due 1990 25,000 25,000 41/2% Series Q, due 1986 9,600 9,600 43/8% Series R, due 1993 25,000 25,000 6% Series S, due 1997 30,000 30,000 61/2% Series T, due 1998 20,000 20,000 67/8% Series U, due 1998 40,000 40,000 83/4% Series V, due 2000 40,000 40.000 87/8% Series W, due 2000 40,000 40,000 73/8% Series X, due 2001 30,000 30,000 75/8% Series Y, due 2002 50,000 50,000 75/8% Series Z, due 2003 50,000 50,000 83/4% Series AA, due2004 65,000 65,000 9% Series BB, due 1982 85,000 85,000 11 % SeriesCC, due2000 50,000 50.000 87/8% Series DD, due 2007 45,000 45,000 91/4% Series EE, due 2008 40,00_0 40,000 Total First Mortgage Bonds 754,600 754.600 Pollution Control Notes: 5.90%, c' :e 1998 6,175 6,175 6.50%, due 2007 11,870 11,870 Other 218 248 Less due within one year 15,031 31 - Unamortized premium and discount, cet (1,236) (1,321) long-term debt, net $756,596 M1,541 Long-term debt maturities and cash sinking fund requirements on debt outstanding at December 31,1979, are as follows: 1980, $15,031,000; 1981, 52,531,000: 1982, $122,531,000: 1983,52,531000 and 1984, $12,531,000. In addition, there is an annual 1 percent sinking and improvement fund requirement, which amounts to $5,850,000 for 1980. Such sinking and iroprovement fund requirement may be satisfied by the deposit of cash or bonds, or by cer-tification of property additions. All or any part of each outstanding series of first mortgage bonds may be redeemed by the Company at any time at establir,hed :edemption prices plus accrued interest to the date of redemption, except certain series whkh are subject to certain refunding limitations during - their respective initial five-year redemption periods. The Series CC bonds require a sinking fund sufficient to retire a minimum of $2,500,000 irr principal amount each year commencing September 1,1981. Essentially all utility plant is subject to the lien of the mortgage indenture. -(8) LEASES The Company has entered into lease agreemmts for the use of substation equinment, data processing and office equipment, vehicles and office space. Since lea <e rentals are charged to -11

' expense for r te-making purposes, capitalization of these luses is not required. Had thy Company capitalized the leased property at the beginning of the lease terms, the effect on assets, liabilities, expenses or net income would not be material. Rental payments charged to operations, including rental payments on capitalizable leases, amounted to $5,775,000 for 1979 and $5,329,000 for 1978. Future minimum rental paynjents, excluding executcry costs such as real estate taxes, state use taxes, insurance and maintenance, under long term noncancellable leases are ap-proximately as follows: 1980, 56,800,000: 1981, 55,600,000: 1982, 55,100,000: 1783, $5,200,000; 1984, 54,500,000; and for the years subsequent to 1984, an aggregate of $57,700,000. (9) CONSTRUCTION PROGRAM, FINANCING AND CONTINGENCIES The Company is engaged in a continuous construction program and currently forecasts construction expenditures, including nuclear fuel, to be approximately $159.2 million in 1980 and $845 mil! ion for the years 1981-1985. The construction program is subject to periodic review and revision. and actual con-struction expenditures may vary from such estimates due to various factors such as revised load estimates, inflation, the availability and cost of capital, and the granting of timely and adequate rate relief by regulatory commissions. It is expected that compliance with present dnd dOVeloping regulations established by various authorities in the areas of nuclear plant licensing and safety, land use, water and air quality, and other environmental matters will require additional capital expenditures and increased operating costs not now determinable in amount. Substantial capital and operating expenditures have been budgeted by the Company in response to known and anticipated requirements of the U.S. Nuclear Regulatory Com-mission (NRC) as a result of its analysis of the Three Mile Island accident. However, ad-ditional expenditures may be required as a result of further NRC analysis of the accident. In cddition, uncertainties relata! to the reprocessing or permanent storage of nuclear fuel may require revisions in future nuclear fuel costs. At December 31,1979, construction work in progrest included an investment of $285.6 million in jointly owned nuclear cenerating facilities, as follows: a 34.5 percent interest in Millstone 111 of $232.3 million, a 4.5 percent interest in the Seabrook nuclear plant of $38.8 million, and a 39.8 percent interest in the proposed Montague nuclear plant of $14.5 million. All the companies owning undivided interests in these jointly owned facilities are required to provide their own financing in order to support their portion of construction costs. The Millstone 111 nuclear unit is being constructed for a 1986 in-service date. The an-ticipated cost of the Company's 34.5 percent ownership share of the unit, assuming approval by the appropriate regulatory commissions of the neuf income tax accounting treatment, as discussed in Note 1, will be 5713 million. As part of its effort to finance its construction program and to reduce construction expenditures, the Company has sold a 7.5 percent interest in Seabrook and is attempting to sell its remaining 4.5 percent interest in Seabrook. The Company currently anticipates selling a 1.5 percent interest in Seabrook in 1980,4vhich would reduce the Company's current six-year construction and nuclear fuel program expenditures approximately 519 million. The Company continues to attempt to sell its remaining interest. In 1978, because of regulatory delays and financial constraints, the system suspended its early site review effort for the Montague facility but continues to perform meteoro!ogical and aquatic studies of the site and to capitalize AFUDC. In 1980, the Company's,;onstruction program is expected to be financed from internal sources, long-term financing and short-term debt. Future earnings and the Company's ability to meet earnings coverage requirements for long-term financing will be affected by a number of factors. including timely and adequate rate relief, growth in sales, performance of nuclear generatir.g units, inflation, interest and preferred stock dividend rates and other factors, the nature and effect of which cannot be determined in advance. The current six-year construction program does not include any funds for the conversion of any of the Company's oil-fired generating units to coal. Certain of the Company's units may be subject to federal orders prohibiting the use of oil. The estimated cost of conversion of . units which the Company believes are presently under consideration by the federal govern-12

ment for conversion, ranges from approximately $137 million to approximately $306 million, depending on the environmental requirements applicable to each unit. An antitrust action was instituted against NU, CL&P, HELCO and NUSCO in 1973 by six Connecticut municipally owned electric utilities claiming 564,500,000 in treble damages. Three of the plaintiffs have settled their claims for amounts which have been accrued by the system companies as of December 31,1979. The claims of the remaining three plaintiffs, for which amounts have also been accrued, must proceed to trial. In the opinion of counsel for the system, based upon all the facts now known to them, the system companies will not be beh' liable for the antitrust of fenses claimed in the plaintiffs' complaint. (10) TERMINATION OF AGREEMENT FOR THE SALE OF THE GAS PROPERTIES On October 1,1979, the Company, HELCO and Connecticut Natural Gas Corporation (CNG) jointly terminated their agreement under which gas properties of the Company and HELCO would be sold to CNG. The Company and HELCO are currently reevaluating the future of their gas businesses in light of SEC requirements that a registered holding company limit its utility operations to providing either electric or gas service. The 1978 financial data has been restated to eliminate the discontinued operations disclosure reflected in the 1978 Annual Report in order to conform with the 1979 presentation. (11) SEGMENTS OF BUSINESS Segments of Business information relating to the Company's electric and gas operations for the years er.ded December 31,1979 and 1978 can be located in the Statements of Segments of Business on page 19 of this Annual Report. (12) QUARTERLY FINANCIAL DATA (UNAUDITED) (a) Summarized quarterly financial data for 1979 and 1978 are as follows: Quarter Ended March 31 June 30 September 30 December 31 1979 (Thousands of Dollars) Operating Revenues S160,081 S125,896 5144,889 5160,760 Operating Income S 31,423 S 15,397 5 25,667 5 26,365 Net Income S 21,195 S 5,819 5 15,442 S 15,391 1978 (b) Operating Revenues $148.190 $114,222 5116,112 5127,314 Operating Income 5 22,449 5 20,389 5 25.651 S 30.072 Net Income 5 13.653 $ 11,289 $ 16,368 S 20,165 (a) Fluctuations between quarters within a year and as compared to the previous year are primarily due to seasonal variations and the impact of nuclear performance. However, the comparison of the third and fourth quarters of 1979 have been levelized for the impact of nuclear performance due to the implementation of the GUAC, as discussed in Note 1, Energy Adjustment Clauses. (b) 1978 data has been restated to include amounts related to gas operations. (13) IMPACT OF CHANGING PRICES (UNAUDITED) The following supplementary information was prepared on the basis prescribed by the Financial Accounting Standards Board in Statement of Financial Accounting Standards No. 33, Financial Reporting and Changing Prices", for the purpose of providing certain in-formation about the effects of changing prices. It should be viewed as an estimate of the approximate effect of inflation, rather than a precise measure. Specifically, fixed assets, and related depreciation expense appearing in the primary, historical cost financial statements have been restated on two bases, constant dollar and current cost amounts. Restatement of - other items would not materially affect the restated amount of net income. 13

Statement of Income Adjusted for Changing Prices For the Year Ended December 31,1979 Conventional Constant Dollar Current Cost Historical Average Average Cost 1979 Dollars 1979 Dollars (Millions of Dollars) Operating revenues $592 5592 5592 Fuel used in generation 162 162 162 Gas purchased for resale 54 54 54 Depreciation and nuclear fuel amortization 50 97 113 Other operation and maintenance expenses 167 167 167 Federal and state income taxes 9 9 9 Interest expense 53 53 53 Taxes other than income taxes 51 51 51 Other income 12 12 12 Net income (loss) (excluding reduction to net recoverable cost) S 58 5 11(b) $ (5) Increase in specific prices (current cost) of fixed assets and nuclear fuel held during the year (a) 5308 Reduction to net recoverable cost 5(87) (11) Effect of increase in general price level (367) Excess of increase in general price level over increase in specific prices af ter reduction to net recoverable cost (70) Gain from decline in purchasing power of net amounts owed 128 128 Net S 41 5 58 (a) At December 31,1979, current cost of fixed assets and nuclear fuel, net of accumulated depreciation, was 53,037,656,000, while historical cost or net cost recoverable through depreciation was 51,469,451,000. (b) including the reduction to net recoverable cost, net income (loss) on a constant dollar basis would have been (576,000,000) for 1979, Five Year Comparison Of Selected Supplementary Financial Data Adjusted For Effects Of Changing Prices Years Ended December 31, 1979 1978 1977 1976 1975 (in Millions of Average 1979 clollars) Operating revenues $592 $563 5568 $574 5565 llistorical cost information adjusted for generalinflation Net income (loss) (excluding reduction to net recoverable cost) 5 11 j Net assets at year-end at net recoverable cost 5453 Current cost information Net income (lossHexcluding reduction to net recoverable cost) 5 (5) Excess of increne in general price level over increase in specific prices atter reduction to net i recoverable cost S 70 Net assets at year-end at net recoverable cost S453 GeneralInformation Gain from decline in purchasing power of net amounts owed $128 Average consumer price index 217.3 195.4 181.5 170.5 161.2 14 L

Constant dollar amounts represent historical costs stated in terms of dollars of equal purchasing power, as measured by the average level of the Consumer Price Index for all Urban Consumers (CPI-U) during the year. With the exception of CWIP, which has been escalated for AFUDC during the construction period, the data for plant was determined by applying the applicable CPI-U to the historical cost of each plant function for which an average age was determined. Constant dollar restatement corrects distortions caused by recording transactions in dollars of varying purchasing power. The restated amounts do not purport to be appraised value, replacement cost, current value, or the individual prices of particular goods and services in the current market: nor are they indicative of the Company's future capital requirements. Current cost amounts reflect the changes in specific prices of plant from the date the plant was acquired to the present, and are based on estimates of the costs to acquire or produce today, assets identical to those owned or assets having the same service potential as the assets owned. The current cost of plant and equipment was determined by indexing the historical costs of each plant function, for which an average age was determined by the applicable Handy-Whitman Index of Public Utility Construction Costs. Both the constant dollar and current cost amounts of land have been estimated by using the CPI-U. The current year's depreciation expense for both constant dollar and current cost methods was determined by applying the Company's depreciation rates to the indexed plant amounts. Ac-cumulated depreciation under both methods was estimated for each major plant function by 4 niultiplying the respective cost data by a percentage representing the expired life of existing facilities of each function at December 31,1979. Fossil fuel inventories and the cost of fossil fuel used in generation have not been restated from their historical cost as regulation permits the recovery of fuel costs through the operation of ad-justment clauses. For this reason, fuel inventories are considered to be monetary assets. As prescribed in Statement of Financial Accounting Standards No. 33, income taxes were not adjusted. The excess of the increase in general prices over Ine increases in specific prices of plant indicates that, for the year 1979, general infidun ~meater than the increase in specific prices of plant. Under the rate-making process prescribed by the regulatory commissions to which the Company is subject, only the historical cost of plant is recoverable in revenues as depreciation. Tlierefore, the excess of the cost of plant stated in terms of constant dollars or current cost that exceeds the historical cost of plant is not presently recoverable in rates as depreciation, and is reflected as a reduction to net recoverable cost. During a period of inflation, holders of monetary assets suffer a loss of general purchasing power while holders of monetary liabilities experience a gain. The gain from the decline in purchasing power of net amounts owed is primarily attributable to the substantial amount of debt which has been used to finance property, plant and equipment. 1 Auditors' Report To the Board of Directors of The Connecticut Light and Power Company: We have examined the balance sheets of The Connecticut Ught and Power Company (a Con-necticut corporation and a wholly owned subsidiary of Northeast Utilities) as of December 31,1979; i and 1978, and the related statements of income, retained earnings and sources of funds for gross property additions for the years then ended.- Our examinations were made in accordance with generally accepted auditing standards and, accordingly, included such tests of tl e accounting records and such other auditing procedures as we considered necessary in the circumstances. In our opinion, the financial statements referred to above present fairly the financial position of - The Connecticut Light and Power Company as of December 31,1979, and 1978, and the results of its operations and the sources of funds for gross property additions for the years then ended, in con- . formity with generally accepted accounting principles applied on a consistent basis. ARTHUR ANDERSEN & CO. Hartford, Connecticut, February 20,1980. 15

The Connecticut Light and Power Company

SUMMARY

OF OPERATIONS (a) For Ihe Years Ended December 31. I979 1978 Operating Revenues 5591,626 5505,838 Operating Expenses: Operation and maintenance 381,700 298,957 Depreciation 50,925 49,906 Federal and state income taxes 9,480 13,305 Taxes other than income taxes 50,669 45,109 Total operating expenses 492,774 407,277 Operating income 98,852 98,561 Other income, Net 12,322 13,336 Income Before Interest Charges 111,174 111,897 Interest Charges, Net 53,327 50.422 Income before cumulative effect of accounting changes 57,847 61,475 Cumulative effect prior to January 1,1974 of i accounting changes, relating to energy adjustment clauses and unbilled revenues, net of applicable income taxes of 55,672,000 Net Income 5 57,847 _5 61,475 Pro forma Net Income (assuming the 1974 accounting changes above were applied retroactively) (a) These financial statements have been restated, as discussed in Nc,te 10. (b) The pro forma change for 1969 is estimated to be immaterial and, therefore, has not been computed. l 16

1977 1976 1975 1974 1969 (Thousands of Dollars) 5474,066 5450,261 5419,361 5386,080 5165,310 282,879 259,751 273,027 234,151 91,526 49,306 39,098 29,624 28.058 13,212 7,273 8,381 (1,172) 4,021 5,008 43,135 42,719 37,370 34,906 19,525 382,503 349,949 338,849 301,226 129,271 91,473 100,312 80,512 85,763 36,048 11.013 0,536 12,300 11,105 3,609 103,386 100,848 02,812 06,958 39,657 45,827 44.847 36,225 36.814 12.480 57,559 65,001 56,587 60,144 27,177 13,375 S 57,550 5 65.001 5 56,587 5 73,519 5 27,177 5 60,144 (b) 17 l 1

The Connecticut Light & Power Company MANAGEMENT DISCUSSION AND ANALYSIS OF

SUMMARY

OF OPERATIONS A summary of the changes in the principal items affecting earnings is shown below: Increase /(Decrease) 1979 vs.1978 1978 vs.1977 Amount Percent Amount Percent (Thousands of Dollars) Operating revenues.. S85,788 17.0 $31,772 6.7 Operation and maintenance expenses: Cost of fuel and gas... 55,417 34.3 2,704 1.7 Other operation expenses.... 21,187 21.1 7,422 8.0 Maintenance... 6,139 16.6 5,952 19.2 Provision for depreciation. 1,019 2.0 600 1.2 Provision for income taxes... (3,825) (28.7) 6,032 82.9 Ot her ta xes............... 5,560 12.3 1,974 4.6 Allowance for funds used during constructicn.... (534) (2.5) 3,057 16.9 Interest and other charges (excluding allowance for borrowed funds used during construction)......... 3,302 5.4 6,575 12.1 Operating Revenues The revenue increase in 1979 resulted principally from the rate increase granted by the DPUC in July 1979 and from additional fuel cost recoveries resulting from rising fuel prices. Additional revenues were received in 1979 due to a temporary surcharge amounting to S6.5 million to recover costs which were found by the Connecticut Supreme Court to have been improperly disallowed by the DPUC. The revenue increase in 1978 was primarily due to a rate increase which was received late in 1977 and higher kWh sales. Operation and Maintenance Expenses Operation and maintenance expenses increased in 1979 and 1978 by 582.7 million (28 percent) and $16.1 million (6 percent), respectively. The most significant portion of the increase in 1979 was a fuel and gas cost increase of $55.4 million (34 percent). Fuel cost increases in 1979 were attributable to escalating fossil fuel prices, additional purcht & 4 interchange power, and increased nuclear fuel costs. Nuclear fuel expenses increased due L tcrease in fuel prices and the provision for the ultimate disposal of spent fuel. Another contre g factor was the implementation of GUAC which deferred fuel cost reductions related to the high nuclear performance for the months of August through December 1979. The most significant portion of the operation and maintenance expense increase in 1978 related to costs associated with the Millstone I and 11 outages for refueling and maintenance. Maintenance expense increases in 1979 were due to increased maintenance expenditures j on fossil and nuclear plants of $3.2 million (22 percent) and the continuing impact of inflation. l Taxes l Federal and Connecticut state income taxes decreased in 1979 due to lower taxable income and the lower federal statutory rate. Income taxes increased in 1978 due te higher taxable income and I l increased normalization of investment tax credits. Taxes other than income taxes increased in 1979 largely due to an increased Connecticut gross earnings tax as a result of higher revenues. In Con-necticut,5 percent of all utility revenues are paid to the state as a gross earnings tax. i 1 Other Income Other income consists mainly of the a!!owance for equity funds used during construction (AFUDC). Total AFUDC, including the portion classified as a credit to interest charges, decreased by 5500,000 (3 percent) in 1979 and increased by 53.1 million (17 percent) in 1978. The decrease in 1979 i is due to the impact on construction work in progress of the sale of a portion of the Company's in-terest in the Seabrook nuclear project. Interest Charges Total interest charges (excluding the credit for allowance for borrowed funds used during construction) increased in 1979 and 1978 by $3.3 million (5 percent) and $6.6 million (12 percent), respectively. Increases in 1979 were due to increased short-term borrowings at higher rates. Ad-ditional interest charges were incurred in both 1979 and 1978 due to the interest on a new bond issue in April 1978. 18

i The Connecticut Light cnd Power Company STATEMENTS OF SEGMENTS OF BUSINESS 1979 1978 1977 1976 1975 (TIsousarsds of Dollars) For the Year Ended December 31, Operating Information Electric Operations: Operating revenues 5505,970 S431,465 5403,500 5381,614 5363,210 Operating expenses, excluding provision for income taxes 404,975 325,589 309,311 281,586 291,644 Pre tax operating income 100,995 105,876 94,189 100,028 71,566 Provision (credit) for income taxes 9,798 14,175 8,747 8,729 (1,259) Allowance for funds used during construction (AFUDC) 20,496 20,992 17,820 14,247 20,666 Operating income and AFUDC 5111,693 5112,693 5103,262 5105,546 593,491 Depreciation expense S47,709 546,999 546,512 536,456 527,052 Capital expenditures 5114,960 $117,005 5131,870 5134,162 5146,797 Gas Operations: Operating revenues $85,656 574,373 570,566 568,647 556,151 Operating expenses, excluding provision for income taxes 78,319 68,383 66,009 59,982 48,377 Pre-tax operating income 7,337 5,990 4,557 8,665 7,774 Provision (credit) for income taxes (318) (870) (1,474) (348) 87 AFUDC 97 135 249 124 136 Operating income and AFUDC 57,752 56,995 56,280 59,137 57,823 Depreciation expense 53,216 52,907 S2,794 52,642 52,572 Capital expenditures _ 56,480 S3,790 56,442 55,674 55,294 At December 31, Investment Information: Identifiable assets (a) Electric S1,365,867 51,347,958 51,294,262 51,233,318 S1,148,267 Cas 106,651 102,135 101,434 97,790 95,173 Nonallocable assets 213,300 169,498 161,097 161,972 175,791 Total assets $1,685,818 51,619,591 51,556,793 51,493,080 $1.419,231 (a) Includes construction work in progress, materials and supplies and allocatal common utility property. 19

The Connecticut Light and Power Company STATISTICS Operating Revenues Utility Plant Decernber31, (Thousands) (Thousands) Electric Gas Total 1969 $ 731,564 $139,112 $26,207 $165,319 1974 1,338,057 338,257 48,732 386,989 1975 1,482,884 363,210 56,151 419,361 1976 1,605,256 381,614 68,647 450,261 1977 1,710,880 403,500 70,566 474,066 1978 1,804,545 431,465 74,373 505,838 1979 1,867,755 505,970 85,656 591,626 Average Average Annual Annual Cubic Feet Residential Electric Gas Kwh Sales Re.sidential of Gas Sales Cubic Feet Custorners Custorners Employees (Mi.' lions) Kwh Use (Millions) of Gas Used (Average) (Average) (Decernber31) 1969 7,161 6,436 17,910 78,491 476,743 113,316 3,251 1974 9,358 7,774 18,965 80,736 538,526 113,563 3,456 1975 9,175 7,694 17,564 75,622 546,407 113,356 3,263 1976 9,802 8,057 19.246 82,084 555,319 113,187 3,105 1977 10,221 8,079 18,420 78,458 565,224 113,374 3,540(a) 1978 10,360 8,077 18,720 79,358 574,438 113,621 3,936(a) 1979 10,882 8,080 20,572 76,733 585,034 114,723 3,834 l (a) Increases are due to the consol:dation of the Company's and HELCO's operations. i 20

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