ML19261D615

Annual Financial Rept 1978

ML19261D615
Person / Time
Site:	Millstone
Issue date:	12/31/1979
From:	CONNECTICUT LIGHT & POWER CO. (SUBS. OF NORTHEAST
To:
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ML19261D612	List: ML19261D611 ML19261D613 ML19261D614 ML19261D615
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NUDOCS 7906200377
Download: ML19261D615 (21)

Text

.

ANNUAL REPORT 1978 2286 174 NORTHEAST { {& p UTILITIIES __c____c_.

7906200317

l DIRECTORS WILLIAM B. ELUS LELAN F. SILUN, JR.

President, Chairman of the Board and Chief Executive Officer, Northeast Utilities Northeast Utilities WALTER F. FEE PETER M. STERN Executive Vice President, Vice President, Northeast Utilities Service Company Northeast Utilities Service Company WARREN A. GRETEN DONALD C. SWITZER Vice President, Vice Chairman, Northeast Utilities Service Company Northeast Utilities LEON E. MAGLATHUN, JR.

WALTER F. TORRANCE, JR.

Vice President and Chief Administrative Officer, Vice President, General Counsel & Assistant Secretary, Western Massachusetts Electric Company Northeast Utilities Service Company HERBERT W. SEARS ANTHONY E. WALLACE Vice President, Executive Vice President, Northeast Utilities Service Company Northeast Utilities Service Company OFFICERS LELAN F. SILUN, JR.

LEONARD A. O'CONNOR Chairman and Chief Executive Officer Vice President and Treasurer DONALD C. SWITZER HERBERT W. SEARS Vice Chairman Vice President WILLIAM B. ELLIS PETER M. STERN President Vice President WALTER F. FEE WALTER F. TORRANCE, JR.

Executive Vice President Vice President, General Counsel &

ANTHONY E. WALLACE Assistant Secrdary Executive Vice President CHARLES S. BEACH Regional Vice President-Western PHIUPT. ASHTON Vice President W. UNDSEY BOOTH Regional Vice President-Eastern i

ALBERT G. BAER Vice President THOMAS F. BRENNAN Regional Vice President-Central WARREN F. BRECHT Vice President EMIL B. GROSS Regional Vice President-Southern ROBERT S. BROMAGE Vice President ALBERT E. MAGEE Regional Vice President-Northern WILUAM G. COUNSIL i

Vice President WARREN A. HUNT Conttoller 7}

RAYMOND E. DONOVAN Vice President ROBERT W. BISHOP 8'C#'Y WARREN A. GRETEN Vice President ROY M. SEGER FRANCIS L. KINNEY

^*SI5"' b'C'"Y Vice President ROBERTC. ARONSON Assistant Treasurer JACK R. McCLENDON Vice President and General Manager-Gas DONALD G. PARDUS Assistant Treasurer

The Connecticut Light and Power Company March 5,1979 To The Shareholders:

The Annual Report of Northeast Utilities, which provides coverage of the entire Northeast Utilities system, including The Connecticut Light and Power Companf, has been mailed to all CL&P preferred shareholders. This report is brief for that reason.

The financial statements and statistical data included in this report show the results of operations of the Companyin 1978.

On October 3,1978, the Connecticut Supreme Court released its decision on the ap-peals taken by The Connecticut Public Utilities Control Authority (PUCA) and others from the Connecticut Court of Common Pleas decision regarding the Company's 1977 rate decision. The Supreme Court held that the lower court had erred in ordering the PUCA to reconsider the Company's request for an attrition allowance. In all other respects the lower court's decision was sustained.

As a result of the Supreme Court's upholding of the lower court's decision regarding certain operating expenses, the Company filed a proposal with the PUCA to levy a sur-charge that would recover about 56.6 million in such expenses. Hearings were held on this proposal in January 1979 and the P'UCA granted the Company permission to recover the 56.6 million through a surcharge to be added to customers' bills over a five month period commencing February 1979.

The Company filed an application with the PUCA in February 1979 for increased electric and gas rates totaling approximately 587.6 million. Hearings on this application are expected to commence in early April and a decision is expected by late July 1979.

In July, the Company filed with the Federal Energy Regulatory Commission (FERC) new increased wholesale rates aggregating approximately $2.5 million. FERC suspended the effectiveness of these rates until February 1,1979. The Company is now billing these rates subject to possible refund pending FERC's decision.

The Company sold in March 1978 $40 million of 9-1/4% First Mortgage Bonds due in 2008 at a cost of 9.30%. The proceeds from this sale were used to retire short-term debt which had been incurred to finance the Company's continuing construction program.

Several organizational changes were made to unify the Boards of Directors and Offices of all operating companies of the Northeast Utilities system.

2286 176 1

Donald C. Switzer was elected Vice Chairman and William B. Ellis was elected President of the Company. Other changes included the elections of Herbert W. Sears as a Director, Walter F. Torrance, Jr. as a Director and Vice President, Walter F. Fee as Executive Vice President, Philip T. Ashton, William G. Counsil, Raymond E. Donovan, Jack R. McClendon and Peter M. Stern as Vice Presidents and Robert W. Bishop as Secretary.

Four retirements were noted in 1978. Retiring as Directors were Paul H. Mehrtens after 36 years of system service and Joseph R. Maher after 31 years of system service. Retiring as Vice Presidents were John B. Madigan after 38 years of system service and Robert H.

Pearson after 31 years of system service.

Sincerely, t h*

President Chairman 2286 177 2

AUDITORS' REPORT To the Board of Directors of The Connecticut I.ight and Power Company:

We have examined the balance sheets of The Connecticut Light and Power Company (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) as of December 31,1978 and 1977, and the related statements of income, retained earnings and sources of funds for gross property additions for the years then ended. Our examination was made in accordance with generally accepted auditing standards, and accordingly included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.

In our opinion, the accompanying financial statements present fairly the financial position of The Connecticut Light and Power Company as of December 31, 1978 and 1977, and the results of its operations and the sources of funds for gross property additions for the years then ended, in conformity with generally accepted accounting principles consistently applied during the periods.

ARTHUR ANDERSEN & CO.

Hartford, Connecticut, February 14,1979.

2286 178 3

The Connecticut Light and Power Company STATEMENTS OF INCOME For the Years Ended December 31.

1978 1977 I

(Thousands of Dollars)

Operations Excluding Gas Operations To Be Sold Operating Revenues

$431,465 5403.500 Operating Expenses:

Operation -

Fuel 114,422 113,464 Other 90,661 83,463 Maintenance 34,186 28,197 Depreciation 46,999 46,512 Federal and state income taxes (Note 3) 14,175 8,747 Taxes other than income taxes 39.321 37.675 Total operating expenses 339,764 318.058 Operating Income 41.701 85.442 Other Income:

Allowance for equity funds used during construction 10,406 9,266 Equity in earnings of regional nuclear generating companies 2,097 1,991 Other, net 56 (46)

Income taxes applicable to other income-credit (Note 3) 374 328 Net otherincome 12.933 11,539 income before interest charges 104,634 96,981 Interest Charges:

Interest on long-t_erm debt 51,794 47,864 Otherinterest 4,369 2,392 Allowance for borrowed funds used during construction (10,586)

(8.554)

Totalinterest charges 45,577 41,702 Net income From Continuing Operations 59,057 55,279 Net Income From Gas Operations To Be Sold (Note 4) 2,418 2.280 Net Income S 61,475 5 57,559 STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1978 1977 (Thousands of Dollars)

Balance at begmning of period

$158,747 5154,414 Noincome 61,475 57,559 Cash dividends on preferred stock (14,644)

(14,644)

Cash dividends on common stock (34,630)

(38,582)

Balance at end of period (a) 5170,948 5158,747 (a) At December 31, 1978, retained earnings of $56,900,000 were available for payment of cash dividends on common stock.

The accompanying notes are an integral part of these financial statements.

]hb 4

The Connecticut Light end Power Company STATEMENTS OF SOUllCES OF FUNDS FOR GROSS PROPERTY ADDITIONS For the Years Ended December 31, 1978 1977 (Thousands of Dollars)

Funds Generated From Operations From continuing operations:

Income from continuing operations S 59,057 5 55,279 Principal noncash items -

Depreciation 46,999 46,512 Deferred income taxes, net 10,520 6,111 Amortization of deferred charges and other noncash items 3,289 5,203 Amortization of deferred fuel costs 253 3,822 Allowance for funds used during construction (20.992)

(17.820)

Total from continuing operations 99,126 99,107 From gas operations to be sold 5,574 5.626 Total funds from operations 104,700 104,733 Less - Cash dividends paid on:

Common stock 34,630 38,582 Preferred stock 14.644 14.644 Net funds generated from operations 55.426 51,507 Funds Obtained From Financing Proceeds from issuance of long-term debt 39,755 56,308 Increase in short-term debt 1,105 2,845 Repayment oflong-term debt (16.031)

(31)

Net funds from financing 24,829 59,122 Other Sources (Uses) Of Funds Decrease (increase) in net current assets (excluding short-term debt and long-term debt due within one year):

Cash and special deposits 3,573 (2,123)

Receivables and accrued utility revenues (7,071) 979 Fuel, materials and supplies (3,200)

(6,700)

Accounts payable (3,421) 9,679 Accrued taxes 2,352 (20,264)

Revenues to be refunded to customers (Note 2) 10,022 4,699 Other, net 6.194 78 Net change 8,449 (13,o52)

Sales of utility plant (Note 9) 11,732 21,801 Deferred fuel costs 306 (1,463)

Other, net (1.074) 2.928 Net other sources (uses) of funds 19,413 9.614 Total Funds For Construction From Above Sources 99,668 120,243 Allowance For Funds Used During Construction (electric and gas) 21,127 18.069 GROSS PROPERTY ADDITIONS

$120,795 5138.312 Composition Of Gross Property Additions:

Electric utility plant

$114,796 5127,860 Gas utility plant 3,790 6.442 Nuclear fuel 2.209 4.010 Total 5120.795 5138.312 2286 180 The accompanying notes are an m. tegral part of these financial statements.

5

The Connecticut Light and Power Company BALANCE SHEETS 8

At Decemher JI.

1978 1977 (Thousands of Dollars)

ASSETS Utility Plant:

Electric plant in service, at original cost S1,386,490

$1,324,285 Less: Accumulated provision for depreciation 341,560 304 636 1,044,921 1,019,649 Construction work in progress (Note 9) 288,796 262,607 Nuclear fuel, in process 7g 5.202 Net utility plant (for continuing operations) 1.341,005 1.287.458 Gas plant (to be sold), at original cost (including construction work in progress of 51,325,000 in 1978 and $2,410,000 in 1977) (Note 4) 121,971 118,786 Less: Accumulated provision for depreciation 20.646 18.178 Net gas plant (to be sold) 101,325 100.608 Total net utility plant 1,442,330 1.388.066 Other Property and Investments:

Investments in regional nuclear generating companies, at equity 23,643 23,570 investments in subsidiary companies, at equity 5,743 5,887 Other, at cost 5.816 5.808 35,202 35.265 Current Assets:

Cash and special deposits (Note 5) 5,061 8,634 Receivables, less accumulated provision for uncollectible accounts of $1,899,000 in 1978 and 51,716,000 in 1977 44,944 47,902 Due from affiliated companies 15,935 9,561 Accrued utility revenues 24,982 21,328 Fuel, materials and supplies, at average cost 35,005 31.805 Prepayments and other 847 648 126,774 119 878 Deferred Charges:

Unamortized debt expense 1,938 1,907 Deferred fuel costs 4,157 5.876 Other 9,190 5.801 15.285 13.584 Total Assets 51,619,591 51.556.793 2286 181 The accompanying notes are an integral part of these balance sheets.

6

1 At December 31, 1978 1977 (Thousands of Dollars)

CAPITALIZATION AND LIABILITIES Capitalization:

Common stock - $10 par value. Authorized 20,000,000 shares; outstandmg 8,931,014 shares S 89,310

$ 89,310 Capital surplus, paid in (no change during years) 208,614 208.614 Retained earnings 170.948 158.747 Total common stockholder's equity 468,872 456,671 Preferred stock (cumulative) - $50 par value. Authorized 6,000,000 shares; outstanding 3,900,000 shares (Note 6) 195,000 195,000 Long-term debt, net (Note 7)

_ 771,541 731,565 Total capitalization 1,435,413 1.383,236 Current Liabilities:

Notes payable to banks (Note 5) 5,500 Commercial paper (Note 5) 42,700 47,095 Long-term debt due within one year 31 16.031 Accounts payable 10,528 13,578 Due to affiliated companies 22,118 21,864 Accrued taxes 23,579 21,227 Accrued interest 19,974 17,458 Revenues to be refunded to customers (Note 2) 14,720 4,699 Other 8,074 4,197 147,224 146.149 Deferred Credits:

Accumulated deferred income taxes 7,490 8.142 Accumulated deferred investment tax credits 22,456 12,871 Other 7,008 6,395 36,954 27.408 Commitments and Contingencies (Notes 2,4 and 9)

Total Capitalization and Liabilities

$1,619,591 51.556,793 2286 182 7

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

SUMMARY

OF SIGNIFICANT ACCOUNTING POI.ICIES General: The Company, The Hartford Electric 1.ight Company (HELCO), Western Massachusetts Electric Company (WMECO) and Holyoke Water Power Company are the principal operating subsidiaries comprising the Northeast Utilities system (system) and are wholly owned by Northeast Utilities, a registered holding company under the Public Utility Holding Company Act of 1935. Other wholly owned subsidiaries of Northeast Utilities providing substantial support services to the system operating companies include Northeast Utilities Service Company (NUSCO) (a system service company supplying centralized ad-ministrative, accounting, engineering, financial, legal, operations, planning, purchasing and other services to the system companies), Northeast Nuclear Energy Company (NNECO)

(agent for the system companies in construction and operation of nuclear generating facilities and the financing of nuclear fuel for such facilities) and The Rocky River Realty Company and The Quinnehtuk Company (each a real estate company which rents administrative facilities to the system companies). All transactions among affiliated companies are on a recovery of cost basis and are subject to approval of various federal and state regulatory commissions having jurisdiction.

The Company is part of a New England bulk power system which provides for purchases and sales of electric energy through a regional dispatch control agency. Arrangements among the Company and system companies, outside agencies and other utilities covering inter-connections, interchange of electric power and sales of utility 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 regulation by FERC and the Connecticut Public Utilities Control Authority (PUCA) and follows the accounting policies prescribed by the respective commissions.

The Company is a part owner with other system and New England electric utilities of the stock of four regional nuclear generating compeies. These companies, with the Company's ownership interest shown parenthetically are: Connecticut Yankee 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 from these facilities is committed to the participants based on their ownership in-terests and is billed pursuant to contractual agreements which are approved by FERC.

Revenues: 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 regulatory commission. The Company accrues an estimate for energy delivered but unbilled at the end of accounting periods.

Nuclear Fuel: The Company, HELCO and WMECO own the Millstone Unit Nos. I and 2 as tenants in common and NNECO owns the nuc' ear fuel for such units. The cost of NNECO's nuclear fuel, based on a net salvage value of zero, is amortized on a unit-of-production method at rates based on estimated kilowatt-hours of energy 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 $10,404,000 and $10,869,000 in 1978 and 1977, respectively. The Company has requested the PUCA to allow the amortization of estimated spent fuel disposal costs on its 53 percent share of Millstone Unit Nos. I and 2 as part of its nuclear fuel costs. It is estimated that the Company's portion of the future disposal costs of Millstone Unit Nos.1 and 2 spent fuel, excluding prior period disposal costs, could approximate $2 - $3 million per year. If the prior period disposal costs are amortized over ten years as requested of the PUCA, such amortization would amount to an additional $1.5 - $2.0 million per year during such ten-year period. Storage for spent fuel at the Millstone nuclear station, including the facilities currently under construction at Millstone Unit No. 3, 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 3.66 percent in 1978 and 3.77 percent in 1977, are applied to the average plant in service during the year, 2286 183

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 accumulated provision for depreciation.

A study completed in 1976 estimated decommissioning costs for the two nuclear units owned by the system at approximately $70 million. This study contemplated a decom-missioning method with an indefinitely long period of time between retirement and com-pletion of the removal process. Preliminary results of a 1979 study indicate increased costs for three alternative methods of decommissioning. The complete removal of the facilities at the time of retirement method, with an estimated cost of $127 million, is the most viable and economic method of decommissioning these units. Depreciation rates recognized for regulatory rate setting for the Company include an element based on the recovery of a portion of the Company's share of the $70 million. The increased costs indicated by the 1979 study are not currently included in the Company's rates. It is estimated that, at such time as allowed by the PUCA, the Company's share of the depreciation expense for decommissioning will in-crease from approximately $1.2 million per year 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.

FederalIncome Taxes: The tax effect of timing differences (differences between the periods in which transactions affect income in the financial statements and the periods in which 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 commissi_ons. 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 collected in customers' rates when such taxes become payable.

See Note 3 for the detail of income tax expense.

Allotoance for Funds Used During Consiruction: The allowance for funds used during con-

~~

struction (AFUDC) represents the cstimated 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 plant. The AFUDC rate applied to construction work in progress for 1978 and 1977 wn 9 percent. The Company has not recorded the effect of compounding such rate.

Retirement Plan: The Company participates in a uniform noncontributory retirement plan covering all regular employees. It is the policy of the Company to provide for and fund the actuarial liability, which includes the current cost and the amortization of prior service cost over a period of 40 years. Total pension cost, part of which was charged to utility plant, approximated $6,800,000 in 1978 and $7,200,000 in 1977. At December 31,1978, the pension fund assets exceeded the actuarially computed value of the vested benefits. The unfunded actuarialliability of the plan was approximately $45,100,000 at December 31,1978.

Deferred Fuel Costs: The Company defers the changes in fuel costs which have not been billed under its fuel adjustment clauses.

(2)

RATE MATTERS The $14,720,000 of revenues to be refunded to customers results from FERC approved set-tiements between gas distribution companies and their gas suppliers which required refunds of certain amounts related to quantities of gas which were delivered to the Company in recent years. The refunds, which have been received from gas suppliers, will be passed on to the Company's customers by reducing their gas bills in February 1979. Refunds received in 1977 and originally included in other deferred credits have been reclassified consistent with the 1978 presentation.

The Company has collected certain revenues subject to possible refund under wholesale rate cases filed with FERC. Based on management's and its counsel's evaluations of the facts in 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.

2286 184 1

9

1 On January 19,1979, the PUCA approved the recovery of an aggregate of $6,588,000 by the Company from its electric and gas customers. This amount represents previously unrecovered costs which were found by the court to have been improperly disallowed by the PUCA in its 1977 rate case decision. The recovery of these costs will be recorded in revenues, as collected, during the first half of 1979.

(3)

INCOME TAX EXPENSE The detail of the federal and state income tax provisions charged to continuing operations is set forth below:

Year Ended December 31, 1978 lo77 (Thousands of Dollars)

Current income taxes:

Federal 5 110

$ 469 State 3,171 1.839 Total current 3,281 2.308 Deferred income taxes, net:

Investment tax credits 10,225 7.455 Federal 279 (878)

State 16 (466)

Total deferred 10.520 6.111 Totalincome taxes 513.801 5 8.419 Such provision (credit) is included in the accompanying statements of income as follows:

Operating expenses S14,175 5 8,747 Other income (374)

(328)

Totalincome taxes 513,801 5 8,419 Deferred income taxes are comprised of the tax effects of timing differences as follows:

Investment tax credits

$10,225 5 7,455 1.iberalized depreciation 849 659 Unbilled revenues (348)

(489)

Deferred fuel costs 34 (784)

Unusual operating expenses deferred (487)

Other (240)

(243)

Deferred income taxes, net

$10,520

$ 6.111 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 from continuing operations are as follows:

Expected tax, at 48"o of pretax income from continuing operations 534,972 530,576 Tax effect of differer:ces:

Additional depreciation for tax purposes

. (7,889)

(8,171)

Allowance for funds used during construction -

not recognized as income for tax purposes (10,077)

(8,554)

Overhead costs of construction - expensed for tax purposes (1,884)

(2,103)

Investment tax credits (1,890)

(2,135)

Ahc _ated affiliated companies' losses (1,291)

(1,533)

Cost of removal - expensed for tax purposes (557)

(561)

State tax, net of federal benefit 1,657 714 Other. net 760 186 Totalincome taxes 513.801 5 8.410 Effective income tax rate I o ",

13*o At December 31,1978, the Company had unused and unrecorded investment tax credits amounting to approximately $7,500,000, which are available to offset federal income tax provisions for years through 1985.

2286 185 to

(4)

GAS OPERATIONS TO BE SOI.D In 1974, the Company entered into an agreement to sell its gas properties. In June 1977, the PUCA gave conditional approval of the sale but withheld final approval until a number of conditions, such as adequate financing and savings to customers, are met by the purchaser.

Certain conditions have not been met at year-end and the parties have agreed to extend the purchase agreement until September 1,1979. In the event the sale is not consummated, the Company will be required, under certain circumstances, to refund the deposit received in 1974, of $3,214,000, currently recorded in other deferred credits. Under the proposal, had the sale been completed on December 31, 1978, the Company would have been paid

$128,900,000. At December 31,1978, the gas properties had an aggregate net book value of

$104,080,000.

In segregating the results of gas operations to be sold, the Company allocates certain indirect expenses common to both electric and gas operations. The methods of allocation have been accepted by regulatory commissions for use in establishing rates to be charged to electric and gas service customers. Common operation and maintenance expenses are primarily allocated based on the relationship of electric and gas operating revenues to total operating revenues; interest charges and preferred stock dividends are primarily allocated based on the relationship of beginning of year utility plant in-service balances.

Summarized results of operations of the Company's gas properties are as follows:

Year Ended December 31, 1978 1977 (Thousands of Dollars)

Operating Revenues

$74,373 570.566 Operating Expenses:

Operation -

Purchased and produced gas 46,975 45,229 Other 9,875 9,651 Maintenance 2,838 2,875 Depreciation 2,907 2,794 Federal and state income taxes (870)

(1,474)

Taxes other than income taxes 5,788 5,460 Total operating expenses 67,513 64.535 Operating Income 6,860 6,031 Other Income, Net 403 374 Income before interest charges 7,263 6,405 Interest Charges, Net 4.845 4.125 Net Income From Gas Operations To Be Sold S 2.418 5 2.280 (5)

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 traction thereof, at the time of borrowing. The credit lines expire at various times in 1979 and, a!though these lines are generally renewable, the continuing availability of the urused lines of credit is subject to review by the banks involved. At December 31, 1978, the amount of unused available borrowing capacity under the credit lines available to the Company was $165,735,000:

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

$150,000,000.

2286 186 11

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.

Additional information with respect to short-term debt is as follows:

1978 1977 Weighted average interest rate for borrowings outstanding at end of period (excluding effect of compensating balances) 11.2 %

7.2 %

Maximum amount of borrowings outstanding at any month-end 559,900,000 556.075.000 Average daily borrowings during period 539,189,000 532.546.000 Weighted average interest rate during the period (based on the daily amounts out-standing and excluding effect of compensating balances) 8.6 *o 6.1 *o Rangeof maturities at December 31(in days) 2-47 4-60

~

(6)

PREFERRED LTOCK Details of preferred stock outstanding at December 31,1978 and 1977 are as follows:

Current Shares Description Redemption Price Outstanding Par Value (Thousands of Dollars)

$2.00 Series of 1947

$54.00 336,088

$ 16,804

$1.90 Series of 1947 52.50 163,912 8,196

$2.20 Series of 1949 52.50 200,000 10,000

$2.04 Series of 1949 52.00 100,000 5,000

$2.06 Series E of 1954 51.00 200,000 10,000

$2.09 Series F of 1955 51.00 100,000 5,000

$3.24 Series G of 1968 52.65*

300,000 15,000

$4.48 Series H of 1970 54.45' 300,000 15,000

$4.48 Series I of 1970 54.56*

400,000 20,000

$3.80 Series J of 1971 54.00*

400,000 20,000

$4.56 Series K of 1974 55.50*

1,000,000 50,000

$5.52 Series L of 1975 55.52*

400.000 20.000 3.900.000

$195.000

• Redemption price reduces in future years.

All or any part of eta 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, except that certain Series are, during their respective initial five-year redemption periods, subject to certain refunding limitations. The Series L preferred stock requires a sinking fund sufficient to retire a minimum of 20,000 shares at $50 per share each year commencing September 1,1980.

2286 187 12

~

(7)

LONG-TERM DEBT Details of long-term debt outstanding are as follows:

December 31, 1978 1977 (Thousands of Dollars)

First Mortgage Bonds:

3%

Series J, due 1978 5 -

$ 16,000 3%

Series K, due 1980 15,000 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 %

Series CC, due 2000 50,000 50,000 87/8% Series DD, due 2007 45,000 45,000 91/4% Series EE, due 2008 40.000 Total First Mortgage Bonds 754,600 730,600 Less due within one year 16,000 Total;irst Mortgage Bonds, net 754,600 714,600 Pollution Control Notes:

5.90%, due 1998 6,175 6,175 6.50%, due 2007 11,870 11,870 Other 248 280 Less due within one year 31 31 Unamortized premium and discount, net (1,321)

(1.329) long-term debt, net 5771,541 5731.565 Long-term debt maturities and cash sinking fund requirements on debt outstanding at December 31,1978, are as follows: 1979, 531,000: 1980, $15.031,000: 1981, 52,531,000: 1982, 5122,531,000 and 1983, $2,531,000. In addition, there is an annual 1% sinking and im-provement fund requirement, which amounts to $5,850,000 for 1979. Such sinking and im-provement fund requirement may be satisfied by the deposit of cash or bonds, or by cer-tification of property additic 4 All or any part of each outstanding series of first mortgage bonds may be redeemed by the Company at any time at established redemption prices plus.urued interest to the date of redemption, except certain series which 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 in principal amount each year commencing September 1,1981.

Essentially all utility plant is subject to the lien of the mortgage indenture.

2286 188 13

(8)

I. EASES The Company has entered into lease agreements for the use of substation equipment, data processing and office equipment, vehicles and office space. Since lease rentals are charged to expense for rate-making purposes, capitalization of these leases is not required. Had the 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 electric and gas operations, including rental payments on capitalizable leases, amounted to $5,329,000 for 1978 and $4,342,000 for 1977.

Future minimum rental payments, excluding executory costs such as real estate taxes, state use taxes, insurance and maintenance, under long-term noncancellable leases are ap-proximately as follows: 1979, $5,200,000: 1980, $5,400,000: 1981, $5,000,000: 1982,

$4,800,000: 1983, $4,900,000; and for years subsequent to 1983 an aggregate of 569,200,000.

(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 5107 million in 1979 and $680 million for the years 1980-1984.

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 and developing regulations established by various authorities in the areas of nuclear plant i

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. In addition, uncertainties related to the reprocessing or permanent storage of nuclear fuel may require revisions in future nuclear fuel costs.

At December 31, 1978, construction work in progress included an investment of

$263,000,000 in jointly owned nuclear generating facilities, as follows: a 34.5 percent interest in Millstone Unit No. 3 of 5184,800,000, an 11.5 percent interest in the Seabrook nuclear plant of 564,700,000, and a 39.8 percent interest in the proposed Montague nuclear plant of

$13,500,000. 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.

In October 1977, the PUCA granted 37 percent of the Company's requested rate increase.

Subsequently, the system announced certain reductions in its construction program and deferred the planned in-service date of Millstone Unit No. 3 from 1982 to 1986. The current estimated cost of Millstone Unit No. 3 is $2 billion when placed in service in 1986. In 1978, primarily because of regulatory delays, the system suspended its early site review effort for the Montague Units, but continues to perform meteorological and aquatic studies of the site and is continuing to capitalize AFUDC.

In 1979, the Company's construction program is expected to be financed from internal sources 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 in-cluding timely and adequate rate relief, growth in sales, performance of nuclear generating units, inflation, interest and preferred stock dividend rates and other factors, the nature and effect of which cannot be determined in advance. As part of its effort to finance its con-struction program and to reduce construction expenditures, the Company has entered into contracts to sell its current 11.5 percent interest in the Seabrook nuclear plant. In December 1978, the Company sold for $2,886,000 approximately.5 percent of its original 12 percent interest in Seabrook. On February 8,1979, the Company sold for $43,433,000 an additional 7 percent of its interest. The Company expects to sell its remaining 4.5 percent interest in the first half of 1979, and therefore, the forecasted construction expenditures above do not include any amounts for Seabrook. In 1977, the Company sold a 3.7 percent interest in Millstone Unit No,3, The U.S. Department of Energy has issued Prohibition Orders against burning oil in two of the Company's oil-fired generating units and requested a compliance schedule for con-version to coal. The Company is resisting the orders for both financial and enviconmental reasons. If the conversion requirements are made final, an expenditure of approximately 5146 million will be required in addition to currently forecasted construction expenditures.

2286 189 n

An antitrust lawsuit was instituted against the Company, Northeast Utilities, HELCO and NUSCO in 1973 by six Connecticut municipal-owned electric utilities for 564 million in treble damages and is still pending. In August 1978, the U.S. District Court issued a ruling denying the companies' motion for summary judgement. The action must now proceed to a hearing. In the opinion of counsel for the system, based upon all the facts now known to them, the system companies will nat be held liable for the antitrust offenses claimed in the plaintiffs' complaint.

(10) GENERAL IMPACT OF INCREASED COSTS (UNAUDITED)

Substantial increases in recent years in fossil fuel prices have generally been recovered directly by increased revenues under fossil fuel a~d purchased gas clauses. To recover increases in other operating expenses, frequent requests for general rate increases have been required. The increases in recent years in construction costs of utility plant have exceeded general rates of inflatim and the estimated replacement cost of such assets are significantly greater than the hista.. cal cost which forms the basis for revenue determination by the regulatory authorities.

The Company's ability to replace its productive capacity in the future will be contingent upon its ability to finance such replacement. This, in turn, will depend on the Company's ability to obtain adequate and timely rate relief. In compliance with the reporting requirements of the SEC, additional information with respect to replacement cost of productive capacity will be included in Annual Report Form 10-K filed with the SEC for the y.?ar 1978.

(11)

QUARTERLY FINANCIAL DATA (UNAUDITED) (a)

Summarized quarterly financial data for 1978 and 1977 are as follows:

Quarter Ended March 31 June 30 September 30 December 31 1978 (Thousands of Dollars)

Operating Revenues

$117,408 5100,417 S106,572 5107,068 Operating income S 18.777 S 20,527 5 25,53,

S 26,841 Net Income From

. - _ Continuing Operations S 11,040 S 12,495 S 17,372 S 18,150 Net Income (Loss)

From Gas Operations To Be Sold 2.613 (1,206)

(1,004) 2.015 Net Income S 13.653 9 11,289 5 16,368 5 20,165 1177 Operating Revenues

$107 664 S 02.413 5102.350 5101.073 Operating Income 5 27.297 5 20.305 5 21.743 5 16 007 Net Income From Continuing Operations S 20,194 5 12.6n S 13,834 5 8,574 Net Income (Loss)

From Gas Operations To Be Sold 1.046 (742)

(884) 1 060 Net Income 5 22.140 5 11.935 S 12 050 5 10.534 (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.

2286 190 15

t The Connecticut Light and Power Compan/

SUMMARY

OF OPERATIONS For the Years Ended December 31, 1978 1977 Operations Excluding Gas Operations To Be Sold Operating Revenues

$431,465 5403,500 Operating Expenses:

Operation and maintenance 239,269 225,124 Depreciation 46,999 46,512 Federal at:d state income taxes 14,175 8,747 Taxes other than income taxes 39,321 37.675 Total operating expenses 339,764 318.058 Operating income 91,701 85,442 Other Income, Net 12,933 11.539 Income BeforeInterest Charges 104,634 96.981 Interest Charges, Net 45,577 41,702 Net Income From Continuing Operations (before cumulative effect of accounting changes) 59,057 55,279 Net Incorne From Gas Operations To Be Sold (before cumulative effect of accounting changes) 2,418 2.280 Net income (before cumulative effect of accountingchanges) 61,475 57,559 Cumulative effect prior to January 1,1974 of accounting changes, relating to deferred fuel costs and unbilled revenues, net of applicable income taxes of 55,672,000:

Continuing operations Gas operations to be sold Net income S 61,475 5 57.559 Pro Forma Net income (assuming the 1974 accounting changes above were applied retroactively)

(a) The pro forma change for 1968 is estimated to be immaterial and, therefore, has not been computed.

2286 191 16

1976 1975 1974 1973 1968 (Thousands of Dollars) 5381.614 5363,210

$338,257 5248,743 5127.757 207,831 231,800 203,039 136,787 63,472 36,456 27,052 25,655 24,278 11,696 8,729 (1,259) 1,841 1,546 8,168 37.299 32.792 30.933 25.675 13.430 290,315 290,385 261,468 188,286 96.766 91,299 72,825 76,789 60,457 30,991 9,131 11.893 10.820 9,588 277 100.430 84,718 87,609 70.045 31.268 40,599 31.841 32,860 25.992 7.354 59,831 52,877 54,749 44.053 23,914 5.170 3.710 5.395 2.647 2.018 65,001 56,587 60,144 46,700 25,932 11,362 2.013 5 65,001 5 56.587 5 73,519 5 46,700 5 25,932 5 60,144 5 49. Q'4, (a) 2286 192

~

17

The Connecticut Light & Power Company MANAGEMENT DISCUSSION AND ANALYSIS OF

SUMMARY

OF OPERATIONS Comparison of the Year 1978 with the Year 1977 Operating revenues increased 528.0 million (6.9%) in 1978 over 1977, primarily due to a rate increase which was received in late 1977 and higher kilontt-hour sales. The increase in revenues was partially offset by a decrease in fuel cost recoveries, reflected in billings through lower fossil fuel clause charges on customers' bills.

The increase in operating revenues was accompanied by an increase in operating expenses of

$21.7 million (6.8%). The most significant portion of this increase resulted from a $14.1 million (6.3%) increase in operation and maintenance expenses. This increase was due primarily to the operation and maintenance expenses associated with the Millstone Unit Nos. I and 2 outages for refueling and maintenance and the continuing impact of inflation. Federal and state income taxes increased due to higher taxable income and increased normalization of investment tax credits.

The increase in allowance for equity funds used during construction caused the increase in other income and reflects the growth in construction work in progress. Most of this growth in construction work in progress relates to the Company's share of Millstone Unit No. 3 and the Seabrook nuclear plant.

Interest charges increased due to the additional interest on a new bond issue in March 1978 and to an increase in short-term borrowings at higher interest rates. The increases were partially offset by an increase in the allowance for borrowed funds used during construction, which reflects growth in construction work in progress.

Income from gas operations to be sold increased due to a rate increase granted in late 1977.

Comparison of the Year 1977 with the Year 1976 Operating revenues increased $21.9 million (5.7%) in 1977 over 1976. This increase resulted primarily from higher fuel costs recovered through billings to customers and higher kilowatt-hour sales.

Although revenues increased in 1977, they were more than offset by an increase in operating expenses of $27.7 million (9.6%). This increase was due to escalating fuel costs and higher sales. In addition, the increase reflects the impact of inflation on salaries, wages, materials and services.

Depreciation increased in 1977 due to additions to utility plant and higher depreciation rates allowed by the PUCA. Federal and state income taxes increased in 1977 as a result of increased taxable income after the utilization of net operating losses and the increased normalization of investment tax credits.

The increase in allowance for equity funds used during construction caused the increase in other income and reflects growth in construction work in progress, most of which relates to the Company's share of Millstone Unit No. 3.

Income from gas operations to be sold decreased in 1977, primarily due to lower sales resulting from warmer weather coupled with higher operation and maintenance expenses which reflect the impact of inflation. Also contributing to the decrease was higher produced gas costs not recoverable through the purchased gas adjustment clause until a new clause was approved for implementation in September 1977.

2286 193 18

The Connecticut Light and Power Company STATISTICS Operating Revenues Utility Plant December 31, (Thousands)

(Thousands)(a)

Electric Gas Total 1968 5 636,109 5127,757 523,995 5151.752 1973 1,222,295 248,743 38,110 286,853 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 (a) includes gas utility plant to be sold, Average Average Annual Annual Cubic Feet Residential Electric Gas Kwh Sales Residential of Gas Sales Cubic Feet Customers Customers Employees (Millions)

Kwh Use (Millions) of Gas Used (Average) (Average) (December 31) 1968 6,457 5,905 16,085 74.765 462,747 112,253 3.212 1973 9,415 8,013 18,396 77,487 526,539 113,574 3,550 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 1,55,319 113,187 3.105 1977 10,221 8.079 18,420 78,458 565,224 113,374 3,540(b) 1978 10,560 8,077 18,720 79,358 574,438 113,621 3,936(b)

(b) Increases are due to the consolidation of the Company's and HELCO's operations.

2286 194 19

Address General Correspondence In Care Of:

Northeast Utilities Service Company Investor Relations Department P.O. Box 270 Hartford, Connecticut 06101 Tel. (203) 666-6911 General Office Selden Street, Berlin, Connecticut First and Refunding Mortgage Bonds Trustee and Interest Paying Agent Bankers Trust Company, Corporate Trust Operations P.O. Box 318, Church Street Station, New York, New York 10008 First and Refunding Mortgage Bonds Co-Transfer Agent The Connecticut Bank and Trust Company, Hartford, Connecticut 06115 Preferred Stock Transfer and Dividend Disbursing Agent The Connecticut Bank and Trust Company, Stock Transfer Department One Constitution Plaza, Hartford, Connecticut 06115 Preferred Stock Registrar Hartford National Bank and Trust Company, Hartford, Connecticut 06115 Preferred Stock Dividend Payment Dates 53.24,54.48 H and 54.48 I Series - January 1, April 1, July 1 and October 1 51.90,52.00,52.04,52.06,52.09 and $2.20 Series -

February 1, May 1, August I and November 1 53.80, 54.56 and 55.52 Series - M t-d I, June 1, September 1 and December 1 2286 195 The data contained in this Report are submitted for the sole purpose of providing information to present stockholders about the Company.

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2286 196 e

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