ML19305D647
| ML19305D647 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 03/14/1980 |
| From: | HARTFORD ELECTRIC LIGHT CO. |
| To: | |
| Shared Package | |
| ML19305D642 | List: |
| References | |
| NUDOCS 8004150325 | |
| Download: ML19305D647 (60) | |
Text
-
SECURITIES AND EXCHANGE COMMISSION g
WASHINGTON, D. C.
20549
}
FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) 0F THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1979. Commission file number 0-522 THE HARTFORD ELECTRIC LIGHT COMPANY (Ex,act name of registrant as specified in its charter)
CONNECTICUT 06-0383630 (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 outstanding:
3.90% Series of 1949 6.56% Series of 1968 4.50% Series of 1956 9.36% Series of 1970 4.96% Series of 1958 7.60% Series of 1971 4.50% Series of 1963 9.60% Series of 1974 5.2b% Series of 1967 11.52% Series 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 cf common stock, as of the close of the period covered by this report.
Class Outstanding at December 31, 1979 Common Stock, $12.50 par value 3,291,916 shares 8 004150 Mk
Tile 11ARTFORD ELECTRIC LIGitT COMPANY ITEM 1. BUSINESS Tile COMPANY The flartford Electric Light 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 corporation, organized in 1881, and is qualified as a foreign corporation in Massachusetts.
The Company is the second lecgest 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 Connecticut Light and Power Company (CL&P) have undertaken studies to determine the appropriate course of action to be taken with respect to their gas properties.
In this connection a corporate merger of CL&P and the Company is under consideration.
PROBLEMS OF Tile 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, dif ficulty in meeting coverage requirements for the issuance of senior securities, difficulty in obtaining sufficient return on invented 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 longer 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 d:ferrals of previously planned construction programs primarily cs a result of difficulties in obtaining adequate rate relief cnd the reduced rate of increase in the use of electric energy.
(See " Construction and Financing Program", " Rates", " Northeast Utilities - Fuel for Generating Stations" and " Regulatory and rnvironmental Requirements.ind Proceedings".)
CONSTRUCTION,ND 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 (1housands of Dollars)
Electric Plant Production
$40,101
$53,951
$66,533
$59,594
$51,352 Substations and Transmission Lines 9,656 12,372 11,258 9,693 15,534 Distribution Operations 9,464 10,315 11,226 12,110 12,900 General 2,618 2,228 983 749 002 Gas Plant 2,312 3,045 2,522 2,681 2,845 lbtal S64,151 S81,911 S92,522 584,827 S83,433 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 $232,000 and $4,192,000 respectively for environmental control facilities.
Millstone Unit No. 3 in Waterford, Connecticut is the only major generating facility under construction in which the Company has an interest.
Although the Connecticut Division of Public Utility Control (DPUC) granted additional rate relief to CL&P and the Company 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 tha t unit continues to be scheduled for completion in 1986.
The following table sets forth anticipated construction expenditures for the Company's share of this unit..
i Millstone To ta l Ne t MW Ca pabili ty..................
1,150 Year-of planned Operation................
1986 Estimated Company Expenditures (Thousands of Dollars)*
Before 1980 (Actual).....................
$122,540 1980................................
30,507 1981................................
35,879 1982................................
46,135 1983................................
46,068 1984................................
44,867 After 1984..............................
50,743 Estimated Construction Cost per kw.......
1,800 Company Ownership........................
18.2%
Figures do not include cost of nuclear fuel and represent only the Company's portion of the currently estinated 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 this unit frequently increase substantially over earlier projections due to inflation, increased licensing requirements, new environmental regulations, schedule deferrals and other causes.
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 l
to be installed in Montague, Massachusetts in which the Company has a 21% interest. In view of the suspension, the construction i
program amounts shown above include for the Montague units or.ly l
$400,000 per year for the continuation of selected environmental l
studies and for AFUDC.
The Company has expended approximately i
S7,683,000 to date on the Montague project.
The sale in prior years of an interest in Millstone Unit No. 3, the deferral to 1986 of Millstone Unit No. 3 and the suspension of the Montague project are not expected to have l
an adverse effect on reliability of customer service in the near term.
l The Company's ability to maintain the proposed construction expenditure level is primarily dependent upon its chility to obtain timely and adequate rate relief.
If adequate future rate relief cannot be obtained, the Company will be forced '
Y to consider further reductions in proposed projects and further sale of its interest in Millstone No. 3.
The Company estimates that its expenditures for nuclear fuel (af ter giving effect to the settlement of the Westinghouse litigation referred to under " Northeast Utilities System-Fuel for Generating Stations") will'be S2,199,000'in 1980, S3,989,000 in 1981, $2,826,000 in 1982, $1,501,000 in 1983 and $3,402,000 in 1984.
Fuel for Millstone Unit Nos. 1 and 2 is owned and' financed by Northeast Nuclear Energy Company (NNECO).
It is expectei that any increase required in the investment in nuclear fuel for Millstone Unit Nos. I 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 nas 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 after delivery of all such fuel to the reactor site.
A substantial portion o f th e funds required for fuel for those units is expected to be provided through the recovery through rates as an operating expense of the anortization of the fuel being burned in the unit reactors.
In addition to the aforesaid construction progran, the Company's financing requirements during the period 19R0-1984 also include $54,598,000 to meet long-term debt and preferred stock sinking fund and debt maturity requirements.
Of this amount, S27,287,000 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.
There is no assurance that Northeast Utilities can continue to srll its common shares in amounts necessary to provide the necesst.ry capital contributions to the Company.
The amount of short-term borrowings which raay 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 its 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 amounts of short-term borrowings outstanding at December 31,-1979, are set forth belcw.
U
r Limit Under Preferred Total Stock Short-Short-Current Provisions Term Term SEC at December Commercial Bank Debt Authorization 31, 1979 Paper Loans Outstanding
$33,695,000
$60,000,000
$147,379,000 S33,695,000 See Note 4 to financial statements with respect to credit lines available to the Company.
The indenture securing tire outstanding mortgage bonds of the Company requires for the issuance of additional bonds, except 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 addi,tional 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 caraings 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 vere, based on the amounts outstanding as of the end of such periods, as follows:
Preferred Bond Stock Year Ended Coverage Coverage December 31, 1977....
2.44 1.86 December 31, 1978....
2.12 1.79 December 31, 1979....
2.12 1.60 j
i In March 1980 the Company issued and sold $10,000,000 aggregate principal amount of its 13.35% First Mortgage Bonds, i
1980 Series.
Af ter giving ef fect to this sale, the Company's pro forma bond and preferred stock coverages as of December 31, 1979 were 2.02 and 1.55, respectively.
j The Company believes that its sale of additional securities will continue to depend on the adequacy of future cornings, on general conditions in securities markets and on f avorable market appraisal of the Company's securities and Wortheast Utilities common shares.
BUSINESS Electric Operations The Company furnishes retail electric service in Connecticut.
About 93% of the Company's operating revenues for 1979 cane from electric service.
Electric revenues for that period were derived 38% from residential customers, 39%
from commercial customers, 19% from industrial customers and the balance from others.
Through December 31, 1979 the all-time maximum demand on the Company's system was 1,157,300 kilowa t ts, which occurred on July 21, 1977.
The maximum demand on the Company's system during the twelve months ending December 31, 1979, was 1,114,600 kilowatts which occurred on August 2, 1979 at which time the generating capacity of the Company's generating plants (including the Company's entitlements in regional nuclear generating companies) was 1,931,800 kilowatts.
At the time of the peak, the Company was selling 68,500 kilowatts of capacity from its plants to other utilities and was purchasing 11,200 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.
Gas Operations The Company furnishes retail gas service in three separate service areas, not interconnected.
See " Northeast Utilities System - Disposition of Gas Properties".
About 7%
of the Company's operating revenues for 1979 came from gas service.
Gas revenues for that period were derived 48% from residentfal customers, 29% from commercial customers, 21% from industrial customers and the balance from others.
The Company and CL&P have since January 1, 1979, e f fec ted 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 CL&P uniform.
The bulk of the gas supplied by the Company is natural gas purchased under long-term contracts with Algonquin Gas Transmission Company (approximately 58%) and Tennessee cas~
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 4
f.
y,
t
~
t 1
naturali gas :are continuing to require the Company to use higher
= cost'liqueficd natural gas (LNG), substitute natural-gas (SNG)
~
and, to a lesser extent in recent'yearsi propane-to supplement its natural gas-supply..In addition, the natural gas suppliers
.of the Company have periodically obtained - rate increases for i
their' natural gas deliveries and have additional requests for i
rate increases pending before PERC.
These and other factors i-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.
2-i Arrangements have been made by the Company to obtain additional quantities of LNG, SNG and propane and to provide-additional storage for LNG.
Ilowever, the suppliers of LNG and I
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 -
l conditions, the Company expects that its -gas supplies will be
~
adequate to meet the anticipated demand through the 1984-1985 heating season.
l Pipeline natural gas, LNG and SNG provided 88%, 3.3%
and 8.2%, respectively,~'of the Company's requirements during 7 ~
1479, with propane 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 1
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 Annual Report i
to Shareholders for the year 1979 attached and made a part-hereof
!~
as Exhibit A which information is hereby incorporated herein.
1' i
j
. Employees
[:
As of December 31, 1979, only 184 non-union production-plant personnel remained on. the Company's payroll.. See
" Northeast Utilities System."
NORTEIEAST UTILITIES SYSTEM 1
f
. Operations 4
The Company, ' CL&P, Western Massachusetts Electric ' Company
- (WMECO),.'and flolyoke. Water? Power Company (llWP) are'the principal a.
a-
^
operating subsidiaries comprising the System.
Other subsid 1 aries 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 Systen 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 Ouinnehtuk Company, each a real estate company.
The Company and CL&P have consolidated their operations by means of a transfer of all Company personnel (other than production personnel) to CL&P.
CL&p is responsible for meeting the local servic'e needs of customers of both companies and bills the Company for work performed for the Company on a recovery of cost basis.
The Company and CL&P are continuing their investigation of the feasibility of a corporate merger, in which CL&P would be the surviving corporation.
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.
The System companies have pooled, since June 1,
- 1970, 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 coinpanies uni form.
Through December 31, 1979 the all-time maximum demand on the System was 3,955,200 kilowatts, which occurred on December 19, 1979 a t 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.
l
!4 i ; tb'
l 4
System kilowatthour sales for 1979 were 2.6% above the IcVel 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 i
fired units, and 3% with hydroelectric unitn.
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 operated as a single system through the New England Power Exchange, a regional dispatch control agency.
Provision is also made for the generating capacity responsibilities of participants and their transmission rights and responsibilities.
Operation of System generating facilities under pool dispatch results in substantial purchases and sales of electric energy by the System at prices determined in accordance with 'the NEPOOL Agreement.
CL&P presently owns an approximately 4.5% interest in Seabrook Units Nos. 1 and 2, two 1,150 MW nuclear generating-units under construction in Seabrook, New Hampshire and currently scheduled for operation in 1983 and 1985, respectively.
In prior years CL&P has sold all but approximately 4.5% of its original 12% ownership interest.
CL&P is continuing efforts to sell the remainder of its interest in the Seabrook units, but there is no assurance that such sales can be effected.
Millstone Unit No. 3 and the Seabrook units are the only major generating facilities under construction in which the System companies have an interest.
System companies have entered into agreements with other New England utilities covering the participation of such utilitics as joint owners in these three future nuclear units.
~
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, CL&P and WMECO are part owners with c*har 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 9.5%, 4%, 3.5%
and 9.5% interest, respectively.
The Company, CL&P 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, 1901 and 1982 will be approximately $32,700,000, $25,800,000 and $24,100,000, 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 other 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 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 is purchased under contracts for one year or less.
The cost per barrel has increased substantially from approximately $14.00 per barrel in December, 1977 to approximately $30.00 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 generating units to coal.
One such unit, HWP's Mt. Tom Station, is presently ~ subject to a prohibition order issued under the Energy 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
. 1
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 the 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 three of these ten units with an aggregate capacity of 433 MW and the estimated cost of conversion of all such Company units ranges from approximately S91,000,000 to approximately S270,000,000.
None of these costs are included in the construction program expenditures under " Construction and Financing Progran".
Although proposed federal legislation may provide funds to finance a portion of such conversion costs, the System companies are presently unable to finance any significa,nt 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.
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 from 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 unii.s in which System companies are participating, which cover the units' requirements through the following years:
Uranium Conversion to Concentrates llexafluoride Enrichment Fabrication Connecticut Yankee 1986 1985 1995 1986 Maine Yankee (1) 1986 1982 2000 1984 Vermont Yankee (l) 1982 1982 2001 1982 Yankee Atomic (1) 1982 1982 1999 1983 Seabrook tinit Ib.1(1) 1985 1987 2009 1986 Seabrook Unit Ib. 2(1) 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, CL&P, and UMECO and the other owners of Millstone Unit No. 3, in settlement of the owners' action against Westinghouse seeking danages 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
$2,000,000 in cash, will provide equipment and services for 1
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, ura ni um, equipment, rebates and services at $60,100,000, in 4
1979 dollars.
The considerations received in settlement of 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 f uel adjustment decision of November 30, 1979 and is reflected in Wholesale fuel adjustment charges approved by PERC.
Such provisions, which reflect' increases over previous levsis, also include amortiza tion, 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 "Nor theast Utilities System-Fuel for Generating Stations" in which the s
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 Millutone Unit No.
3, are expected to be adequa te 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.
flowever,
the System cannot predict at this time what difficulties will be encountered in the future regarding such disposal.
The 13RC, along with other federal agencies, is in the process of developing regulations and guidelines in this area.
It is possible that there will be substantial additional costs (above those 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 for their nuclear units on the basis of complete costs 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 $60-70 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 is reflected in the depreciation expense of the Company and CL&P and no portion of such costs is presently reflected in WMECO's depreciation expense.
See Note 1 to financial statements.
- i
4.
Disposition of Gas Properties In light of the termination of the November 27, 1974 agreement among the Company, CL&P and Connecticut Natural Gas-Corporation (CNC) for the sale of the Company's and CL&P's gas properties to CNG, the Company and CL&P 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 IIolding Company Act 4
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.
Retail Rates Connecticut law a f fords 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 af ter 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 level of the utility's rates is required.
On June 29, 1979 the DPUC issued a decision granting the Company an increase in gas and electric revenues stated to total S32,206,000, based on adjusted test year sales.
The Company had requested a $43,600,000 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 i
proceedings in which a preliminary decision was issued on flarch l
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 effective for service rendered on and after 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 9.94% for the Company.
The DPUC also sta ted
' 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 mechanism should
- o
-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 of 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 S3,002,000.
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; the re fore,
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 betwuen members of the DPUC panel which rendered the decision were in violation of the Connecticut Freedom of Information Act and requesting a decision to that effect and an order voiding any actions taken during such discussions.
At the request of the DPUC, the FOIC 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 thereaf ter until a further order by the Court.
On February 13, 1990 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 file i by the DPUC and the Company.
In management's opinion, the PsIC'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 19H0 for an increase in its retail electric and gas ratea.
Puel Adjustment Clauses The Company has a fuel adjustment clause applicable to its retail electric rates, and 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 alse) subject to retroactive review and appropriate adjusbnent by DPUC 2ach 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 Penruary 1980, the Company requested authorization from the DPUC to defer on its books, for reccvery in future rate proceedings, certain fuel-related expenses which are not currectly reflected in its fuel adjustment clause.
No action has been taken on this request.
Management Audit DPUC is required by law to institute management audits of companies such as the company at regular latervals, which a udits may resul t in DPUC ordaring 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 PROCEEDINGS 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 HWP.
Northeast Utilities is registered with the SEC as a holding _ company under the Public Utility Holding Company Act of 1935.. Under tha t Act, the SEC has' jurisdiction over Northeast Utilities and the' Company with respect to, among other things, r-f,;,
p 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 withj 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 ef fect this legislation will have on its rates, sales, revenues or net income.
Environmental Impact Requirements The National Environnental Policy Act of 1969 (NCPA) requires that detailed statements of the environmental ef fect of generating and transmission facilities be prepared in connec tion with various applications to FERC, the Nuclear Regulatory Commission (NPC) 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 requires 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 dissemination 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 recpect to the requirements for sta te siting council approval - for new generation and transmission facilities -in Connecticut and Massachusetts.
NFC Nuclear Plant Licensing As holders of: licenses for_ the construction or operation of nuclear - reactors, the Company, CL&P, 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.- '
~
F 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 governnental 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 rea ffirming his support for continued inclusion of nuclear power in his national energy policy, announced his agreement with the spirit and-intent of those recommendations and his initiation of steps towa rd their implementation.
The report of the NRC's independent study of TMI was released in late January 1980.
The System has voluntarily adopted nodifications 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. I and 2 by approximately $1,000,000 and $2,000,000, respectively, and will require modifications to the Connecticut Yankee, Millstone No. 1 and Millstone No. 2 units costing approximately $5,000,000, $3,000,000 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 nay in the future require limited shutdowns or deratings of the plants Which would not otherwise he 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 he 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,.
l and if total damages resulting from the a'ccident exceed
$140,000,000, then pursuant to the 1977 amendments to such Act, the System companies would be required to pay their share of i
such-excess.
The System companies' share would be a maximum of $5,000,000 for each of the two operating Millstone units, i
[' _
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 fron initial. licensing), full power operating license for Millstone Unit N0.
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 MRC in August 1974 and the unit is presently under construction, although its in-service date has been delayec 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.
Ute 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 Mos. 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 progran, particularly tle Seabrook units.
In view of these difficulties, PSNH is attempting to sell a 22% ownership share in these units, and has obtained commitments for the sale of a 15% share to several New England utilities.
The PSUH of fer may adversely affect a continued effort-by CL&P to sell the remaining portion of its, ownership intereut 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 granted.
If the approvals are.not obtained, or if PSNH's
.a 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 be 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 March 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 ccnstruction 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 System cannot at this time predict the effect of this development the Seabrook units or the System's construction program.
on 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 well 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 tha t 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 c? total costs would be substantially more than their then current invesdnent; 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 terminations.
The System companies would apply to applicable regulatory authorities for approval to amortize 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 effect of these ' matters on the scheduled in-service dates or construction costs of the three nuclear-generating units in which it is participating
_20_
or on-the operation of other nuclear units in which the System companies have ownership interests.
However, it is possible that such matters, 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 Quality Requirements The Federal Clean Water Act (CNA) established a requir ment 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 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 ef fluent s tandards 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.
j 1
1 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 "
I
the achievement, maintenance and enforcement of these standards proposed by the DEP and-approved, with exceptions, the plan proposed _by the Massachusetts Department of Environmental Quality Engineering.
In order to comply with these regulations, the System companies _are required to burn oil having nor more than 0.51 and 2.2% sulphur content in Connecticut and Massachusetts, respectively.
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 operating permits be obtained and that a new or modified source will not result in tho' violation of the EPA's national-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 units may be i.indered or precluded in the System's service area, depending on pollutant levels over which the System companies have no control.
Toxic Substances and Hazardous Waste Regulations Under the federal Toxic Substances 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 PCD equipment. The System companies have taken nunerous 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 (RCHA) 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 affect'ed are those relating to disposal of ashJand 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.
4 - L y
FERC Hydro Plant Licensing System operating companies hold licenses oranted under Part I of the Federal Power Act for the operation und maintenance of eight hydroelectric plants, including the Northfield Plant in which the Company has a 28% interest.
System companies have pending applications with FERC under Part I of the Act for 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 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 granted 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 i
low flow augmentation of streams and fish passage facilities.
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 j
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 certain existing transmission lines' river crossings.
The cost of these undergroundings 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 gane preserves, water supplies, public recreation, great ponds arul 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 recuire it to incur substantial capital expenditures 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.
W I __
E Item 2.
Summary of Operations The information required is contained under the captions
" 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 and its proposed interest in the proposed Montague units in Massachusetts, the Compar.y's utility system is located wholly within the state of Connecticut. The Company's generating stations and most of its other properties are owned in fee, although certain substation equip-ment, data pcocessing and office equipment, vehicles and office space are leased. With few exceptions, lines and mains are located on or under streets or highways or on properties either owned in fee by the Company or occupied under rights obtained from the owners. Substantially all of the property is subject to the lien of the Company's First Mortgage Indenture and Deed of Trust securing its outstanding First 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.
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)
Middletown Plant Steam 1954-1973 836,896 833,000 (Middletown-Connecti-cut River Gas Turbine 1966 18,594 22,000 855,490 855,000 Millstone Plant Nuclear 1970 185,220(a) 184,800(a)
(Waterford-Long Island Sound) 1975 254,772(a) 243,600(a) 439,992 428,400 Northfield Plant Pumped 1972-1973 236,880(a)
-280,000(a)
(Northfield and Erving,
. Storage Massachusetts-Connecticut River) i
e Name P' late-
. Net Year Rating Capability Name, town, Location Type Installed (Kilowatts)
(Kilowatts)
South Headow Plant Gas Turbines.
1970 167,400 196,000 (Hartford-Connecticut
_ River)
One Small Hydro Plant 19141 9,000
-10,200 Two Gas Turbine Plants 1967-1968 37,188 44,000
~
Total Company Generating Plants 1,745,950 1,813,600 Regional Nuclear Generating Plants (Company Entitlements) 1 Connecticut Yankee Atomic Power Company (Connecticut) (9.5%
entitlement)
Nuclear 1968 57,029 55,100 Maine Yankee Atomic Power Company (Maine) (3.6%
entitlement)
Nuclear 1972 29,096 29,800 Vermont Yankee Nuclear Power Corporation (Vermont)
(3.1% entitlement)
Nuclear 1972 17,722 16,600 Yankee Atomic ';1ectric Company (Massachusetts)
(9.5% entitlement)
Nuclear 1961.
17,575 16,7001 Total Regional Nuclear Generating Plants 121,422 i 118,200 Total Generating Plants-
_1,_867,372 1.;931,800
~(a) ~ Represents ' Company's.28% share as tenant in-common with oth'r System compantes.
e 1As of December 31, 1979, the Company had 13 transmission substations-with~an aggregate capacity.of. 4,075,301 kVA and 108 dis.
tribution substations with ~an aggregate capacity of 2,207,717 kVA.
Its
~
transmission system included 95~ circuit miles-of overhead 345.kV lines,,
=
~
-250 circuit miles of overhead 115 kV -lines,553 ' circuit miles of overhead 69 idt lines, 'andl16 cable miles of underground 115 ' kV ' cable. The Company's-distribution system. included.4,000 pole miles of' overhead lines and 286 conduit bank miles of underground' lines.
It has in service-49,354~line:
~
transformers with an.a'gregate capacity ofE2,629,367 kVA.
g
[-
p:.
'wy f N.'
,t 4
e I
.l i.
.t..
c.
1
As of that date the Company had 3 propane plants, 7 LNG plants, 2 gas storage holders with a-total capacity of approximately 2,000 Mcf and approximately 398 miles of gas distribution mains.
From Januar'y 1, 1975, through December 31, 1979 the Company made gross property additions and betterments to utility plant aggregating
$270,850,000 and retired or sold property having an aggregate cost of
$44,336,000, resulting in net additions during thatJperiod of $226,514,000.
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, transmit and distribute electricity and gas, to sell electricity apd 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 other,s as may be required by law.
The franchises of the Company include the p'ower of eminent domain.
Item 4.
Parents ' and Subsidiaries 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 5.
Legal Proceedings On February 13, 1973, six Connecticut municipalities which own and operate municipal electric utility systems and purchase all or part of their electric power from,CL&P, commenced an antitrust action in the United States District Court for the District of Connecticut against the Company, Northeast Utilities, CL&P, 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 CL&P 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 the action is presently under way.'
e
t-The Company has appealed from a June 29,_1973 DEP order which
- would require the undergrounding of two 345 kV transmission line crossings of the Connecticut River and the relocation of a third 345 kV crossing.
~
Decision of the appeal has been stayed pursuant to an agreement of the parties which provides that the third crossing will remain in'its present-location and the first two crossings, together with an adjacent 115 kV crossing, will be undergrounded at a cost of approximately $14,000,000, expressed in 1983 dollars.
Implementation of the agreement is subject to the receipt of approvals from the PFEC, the DPUC and the U.S. Army Corps of Engineers. The estimated cost of the undergrounding provided
(
for in the agreement has been included in the Company's construction budget.
On September 22, 1978, Henry Beckenstein d/b/a Beckenstein Brothers, real estate developers, and other plaintiffs owning or leasing commercial properties and receiving electric power from the Company i
brought a class action in the Connecticut Superior Court against the Company and NU seeking injunctive relief and damages in the amount of $5 million which plaintiffs claim resulted from the termination of an all-electric rate (Rate 30) in 1972. Rate 30 was a ra'te offered to commercial customers who used electric power as their only source of energy for space heating, lighting, cooling, cooking, water heating and power. The plaintiffs claim that they were induced to purchase electric g
power for all of their energy needs under the favorable all-electric rate on the basis that such rate would be available to them indefinitely.
As a consequence, the plaintiffs claim that they designed their buildings solely for electric power and that as a result of the termination of the all-electric rate, they are left with having to pay higher costs for electric energy in that it is not technologically and economically feasible to redesign and reconstruct their buildings for use of a different form of energy. The plaintiffs claim that the initial representations of the Company and the subsequent termination of the all-electric rate violate provisions of the Connecticut-Antitrust Act, constitute unfair trade practices and breaches of contract and violate a state statute prohibiting price discrimination in commercial transactions. The Company believes that there are meritorious defences to each of the allegations claimed by the plaintiffs. The Company has filed a motion for summary judgment, which has not been heard by the Court.
1 On October 26, 1979, the United States District Court for_the District of Connecticut dismissed a similar action commenced May 4,1978 by Henry Beckenstein 4/b/a Beckenstein Brothers, et al. on the ground that the plaintiffs. hed failed _ to state a claim over which the court had independent, federal subject matter jurisdiction upon which relief could be granted.
i The following sections, which are included in " Item 1. Business",
4 l
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 i
i l'
t
- t;
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, CL&P, 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-debtedness (a) The Registrant had no increases or decreases in equity securities during 1979.
(b) and (c) The Registrant had no reportable changes in the amount of debt securities and indebtedness outstanding 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.
Item 8.
Defaults upon Senior Securities There have been no material defaults upon any senior securities 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 December 31, 1979 was as follows:
Number of Record Title of Class Holders Preferred Stock, $50 par value 3,871 Common Stock, $12.50 par value 1
Item 10.
Submis_sion of Matters to a Vote of Security Holders Not applicable.
Item 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.
9)
+%a,&w 8
ey a
//
</[(gg?
3/
9
\\ f ?>? Q /
f l
\\
%N//)F
/v v
g,,,
W 9,
\\
IMAGE EVALUATION
\\
TEST TARGET (MT-3) l.0 lf E2 D?J l# mE p=2 l
ll w
1.1 I"2 UM
\\
.8 1.25 1.4 1.6 MICROCOPY RESOLUTION TEST CHART l
II/
4%
4 ////h
'#) A 4 l434/ Nr//
4
- %e w
s.:s
- .5 4
o
. ;q 4%
/
- h
^
n i
L. -. - -
' bm_
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.
i 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.
- F.
The Company's Current Report on Form 8-K dated June 29, 1979.
- G.
The Company's Current Report on Form 8-K dated September 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 3 months ended
. December 31, 1979.
PART II Item 13.
Security Ownership of Certain Beneficial Owners and Management i
As of December 31, 1979, the Directors of the Company beneficially I
owned the following number of Common Shares of Northeast Utilities, a l
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 Northeast 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.
l
1 Amount of Northeast Utilities shares Beneficially Name Owned
- by Directors 4
William B. Ellis 1,000 Walter F. Fee 1,103 Warren A. Greten 1,483 Leon E. Maglathlin, Jr.
200 Herbert W. Sears 753 Lelan F. Sillin, Jr.
5,000 i
Peter. M. Stern 1,252 Donald C. Switzer 2,182 i
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
- As that term is interpreted by the Securities and Exchange Commission.
t 4
L i
f 9
h A
9 i f
L
Item 14.
Directors and Executive Officers The following information is provided with respect to each director and executive officer of the Company. The terms of each position expires as of the Annual Meeting in 1,980, 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 Choirman 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 4/20/73 Engineering & Operations; Director Anthony E. Wallace 64 Executive Vice President -
10/01/75 4/14/69 Regional Administration; Director Philip T. Ashton 45 Vice President - Transmission 5/01/78 Engineering & Construction Albert G. Baer 59 Vice President - System 4/14/69 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 (1) 55 Vice President - Fossil &
10/01/75 4/20/73 Hydro Production; Director Francis L. Kinney 47 Vice President - Public 4/24/74 Affairs Leon.E. Maglathlin 53 Director 12/01/74 Jack R. McClendon 63 Vice President & General 4/01/78 Manager - Gas Leou rd A. O'Connor 53 Vice President F Treasurer 2/16/70 Wclter T. Schultheis 53 Vice President - Power 7/18/79 Supply 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
!,1 s.
Name Business Experience During Past 5 Years Lelan F. Sillin, Jr.
Chairman since 1970; responyible for the formulation of overall corporate policy.
Donald C. Switzer Elected Vice Chairman in 1978, previously Executive Vice President (1975) of an affiliate since 1971; responsible for engineering and operations.
I 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 firm of McKinsey & Co. as pr thefirm'sutilitypractice.jncipal-in-chargeof Walter F. Fee Elected Executive Vice President in 1978, previously Vice President (1975) of an affiliate since 1971.
Anthony E. Wallace First Elected Execgtive Vice President of an affiliate in 1966 i
Philip T. Ashton Elected Vice President in 1978, previously Director of transmission engineering and construction of an affiliate.
Albert G. Baer Elected Vice President of Operations in 1969.
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 two nuclear units (1974) and Project Manager for a third unit (1976).
Raymond E. Donovan Elected Vice President in 1978; previously Director4 of Corporate Development of an affiliate since 1973.
Warren A. Greten First elected a Vice President of an affiliate in 1967 with responsibilities including engineering and operations and system production.
t Francis L. Kinney First elected a Vice President in 1974 with responsi-bilities including corporate secretary and senior counsel.
Leon E. Haglathlin Elected Vice President of an affiliate in 1969 and Chie{AdministrativeOfficerofthataffiliatein 1974 l
I '
-=
Name Business Experience During Past 5 Years Jack R. McClendon Elected Vice President in 1978; previously Division Manager of an affiliate since 1973.
6 Leonard A. O'Connor Elected 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 proceedings.jts affiliates in regulatory and legal 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 affilate, Connecticut Bank and Trust Company.
3Director of Connecticut Water Service, Inc., Mohasco Corp., Seciety 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.
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 its 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
$128,933 Utilities William B. Ellis President of Northeast Utilities
$121,400 Anthony E. Wallace Executive Vice President of
$102,968 Northeast Utilities Service Company 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 individuals as of 12/31/79 (which does not include Messrs.
Wallace or Fee or any other individuals who are officers of the subsidiaries)
$876,491 (1) Each of the named individuals also served as an officer and a Director of various subsidiaries of the System.
(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 Systes 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.
I (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 of Mr. Sillin. Aggregate contributions are made annually to the retirement plan for the benefit of all employees covered by the plan.
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 i
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 Utilitiet 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 4 7 O
m >
w
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.
4 i'
4 4
i i
1 I
t I
j i
l I
I.
'\\
1
.i
SIGNATURE Pursuant to the requirements of Section 13 or IS(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 HARTFORD ELECTRIC LIGHT COMPANY (Registrant)
Date March 28,1980 By /s/ William B. Ellis William B. Ellis President.-
e
,-38.-
Li
THE HARTFORD ELECTRIC LIGHT COMPANY a
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 ac 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 j
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 i J
XII - Reserves - Years Ended December 31, 1979 and
.1978 S-8--S-9 Schedules other than those listed have been omitted because they are either not required. or are not applicable, or' because the _ required '
J information is included in the financial statements or notes thereto.
+
F-1
1 6.
THE HARTFORD ELECTRIC LIGHT COMPANY SUPPLEMENTARY NOTE TO FINANCIAL STATEMENTS DECEMBER 31, 1979 and 1978 (A) Supplemental Information to Statements of Income Year Ended December 111 1979 1978 (Thousands of Dollars)
Taxes, other than income taxes, charged to tax expense:
State gross earnings
$14,880
$12,318 Real and personal property 13,109 12,477 Payroll and other 1,845 1,519
}29,834
$2_6 31_4 1
Consent of Independent Public Accountants As independent public accountants, we hereby consent to the application 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.
l l
r l.
F-2 J1
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES i
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 i
generally accepted accounting principles applied on a basis consistent l
with that of the preceding year.
ARTHUR ANDERSEN & CO.
1 Hartford, Connecticut, February 20, 1980.
4 i
l i
i 6
(
o S-1
.. ~.
.._m
._m-4 THE HARTFORD ELECTRIC LIGHT COMPANY
{
UTILITY PLANT (INCLUDING INTA.NGIBLES AND EXCLUDING NUCLEAR FUEL)
YEAR ENDED DECEMBER 31, 1979 g'
(Thousands of Dollars) 4 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 Utility Plant in Service Electric
$751,424
$20,566
$4,344
$767,646 Gas 32,756 1,647 149 161 (2) 34,415 Construction Work in Progress Electric 118,628 31,960 (1) 150,588
. u,
- Gas.
909 209 (1) 1,118
' d, Utility Plant Held for Future Use Electric' 4,312 (161)(2) 4,151 Gas 28 28 TOTAL
$908,057
$54,382
$4,493
$957,946
~
'(1) Net increase during the year.
(2) Transfer between Gas. Utility Plant in Service and Electric Utility Plant Held for Future Use.
.. ~.
.. -. =
.~.
THE HARTFORD ELECTRIC LIGHT COMPANY UTILITY PLANT (INCLUDING INTANCIBLES AND EXCLUDINT NUCLEAR FUEL)
YEAR ENDED DECEMBER 31, 1978 (Thousands of Dollars)
COL. A COL. 5 COL. C COL. D COL. E COL. F Balance at Other Changes-Balance beginning Additions Add (Deduct)-
at close Classification _
of period at cont Retirements Describe of period Utility Plant in Service Electric
$730,442
$24,679
$3,697
$751,424
~
Gas 31,545 1,294 189 106 (2) 32,756 (3)
Construction Work in Progress m.g Electric 101,185 17,443 (1) 118,628 Cas 1,113 (204) (1) 909 Utility Plant Held for Future Use Electric 4,373 45 (106) (2) 4,312 (3)
Gas 28 28
. TOTAL
$868,686
$43,257
$3,886
$908,257__
(1) Net increase during the year.
(2) Transfer between Utility Plant in Service and Utility Plant Held for Future Use.
(3) Transfer between electric and gas preparty.
m
- 7' 2.
I
m
--_,-m._-._..____.
.,_..._,>._.,.m_,
t-4 i -
t N
THE HARTFORD ELECTRIC LICHT COMPANY I-NUCLEAR FUEL 0"
YEAR ENDED DECEMBER 31, 1979
's (Thousands of Dollars)
< = -
COL. A COL, E COL. C COL. D COL. E
, COL. F Balance at
.Other Changes-Balance beginning Additions Add (Deduct)-
-at close j
' gassituation of period at cost Retirements Describe of period co.
Nuclear fuel in process of refinement, M'
conversion, enrichment and fabrication
. $2,324
$2,025
$ 4,349 Accumulated provision for amortization of nuclear fuel assemblies (1,004)(1)
(1,004f TOTAL NUCLEAR FUEL.
$2,324
[2,025 Q
g)
$g (1) Reclassification of nuclear fuel disposal costs.
k 4
4 '
1 9
9 9
-r---
r,-- r er
r THE HARTFORD ELECTRIC LIGHT 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
$1,985
$339-S -
S--
$2,3E Yw k
o lirit W
THE HARTFORD ELECTRIC LIGHT COMPANY ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT E.
YEAR ENDED DECEssER 31, 1979 E.
(Thousands cf Dollars) d 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 De7eription of period Expenses Retirements Des c ribe of period ACCLifUIATED PROVISION FOR DEPRECIATION OF UTILITY Y
PLANT e
Electric
$171,613
$25,672
$3,759
$107 (1)
$193,633 Cas 7,616 880 211 25 (1) 8,310 Total
$179,22_9
$26,552
$3,970
$132
$201,9_43 (1) Depreciation charged to Transportation and Fuel Stock Clearing Accounts.
e
THE HARTFORD ELECTRIC LIQ 1T COMPANY ACCUMtTLATED PROVISION FOR DEPRECIATION OF UTILITY PIANT 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 Electric
$150,062
$25,496
$4,065
$120 (1)
$171,613 g
I"
~
' Ces 6,987 848 254 35 (1) 7,616 Total
$157,049
$26,344 h3M
$155
$179,229 (1) Depreciation charged to Transportation and Fuel Stock Clearing Accounts.
v2 V
8.
h
- 5
e.
1 THE HARTFORD ELECTRIC LIGHT COMPANY h
RESERVES S
YEAR ENDED DECEMBER 31, 1979 E.
(Thousand, of Dollars)
C
.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 Describe-of Period RESERVES-DEDUCTED FROM ASSETS TO WHICH THEY APPLY:
. Reserves for uncollectible accounts
$815
$1,224
$1_,214 (a)
$825 RESERVES NOT APPLIED AGAINST ASSETS:
m
. co Injuries and damages (b)
$464 58
$ 161 (c)
$361
' Medical insurance-(e) 377 83 (d) 294 TOTAL
$_464
$ 435
[-
$_jl4_4_
$655 (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.
(c).Provided to cover claims for employee medical insurance.
THE HARTFORD ELECTRIC LIGHT 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
$692
$1,822
$1,699 (a)
$815 RESERVES NOT APPLIED AGAINST ASSETS:
g Injuries and damages (b)
$297
{_ 380
$ 213 (c) 1464 (a) ' Amounts charged off as uncollectible after deducting customers' deposits and recoveries of accounts previously charged off.
(b) Provided to cover c' aims 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.
m
- 2*
8.
M H
9
N EXHIBIT A ANNUAL ghh REPORT tea 1979 l
l l
l l
IMMtTHEAST a nHLE D u i m ii.,g..gh THE HARTFORD ELECTRIC UGHTCOMPANY i
\\
DIRECTORS '
WILLIAM B. ELLIS '
LELAN F. SILLIN, JR.
Chairman of the Board and Chief Executive Officer, President,.
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. MAGLATHLIN, 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. SILLIN, JR.
LEONARD A. O'CONNOR Chairman and Chief Executive Officer Vice President and Treasurer DONALD C. SWITZER WALTER T. SCHULTHEIS Vice Chairman Vice President WILLIAM B. ELLIS HERBERT W. SEARS President Vice President -
WALTER F. FEE PETER M. STERN Executive Vice President Vice President ANTHONY E. WALLACE WALTER F. TORRANCE, JR.
Executive Vice President Vice President, General Counsel & Assistant Secretary PHILIPT. ASHTON CHARLES S. BEACH Vice President Regional Vice President-Western ALBERT G. BAER" W. LINDSEY BOOTH Vice President Regional Vice President-Eastern WARREN F. BRECHT THOMAS F. BRENNAN Vice President and Controller.
Regional Vice President-Central CARROLL A. CAFFREY
- EMIL B. GROSS Vice President Regional Vice Pres' denti outhern S
i WILLIAM G. COUNSIL
' ALBERT E. MAGEE -
Vice President Regional Vice President-Northern -
RAYMOND E. DONOVAN ROBERT W. BISHOP '
Vice President -
Secretary WARREN A. GRETEN* ~
ROY M. SEGER Vice President; Assistant Secretary FRANCIS L. K!NNEY -
ROBERT C. ARONSON -
'~
Vice President Assistant Treasurer JACK R._McCLENDON
- Vice President and General ManagersGas
- Resigned 1/1/80'
=" Resigned 2/29/80
~
e
.2
The Hartford Electric Light Company March 14,1980 To The Shareholders:
The Annual Report of Northeast Utilities, which provides coverage of the entire Northeast Utilities system, including The Hartford Electric Light Company, has been mailed to all HELCO 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 significantly below the return allowed by the Connecticut Division of Public Utility Control (DPUC). Additional revenues generated by a S32.3 million rate increase, approved by the DPUC in June of 1979, were offset by the effects of rapid inflation, higher fossil fuel costs, expenses required for service restoration following storms, costs associated with im-plementing new requirements of the Nuclear Regulatory Commission and 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 G;neration Utilization Adjustment Clause (GUAC), which was authorized by the DPUC as part of its 1979 rate decision. 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.
Later this month, the Company expects to sell, through a private placement, 510 million of 13.35% First Mortgage Bonds due in 1990.
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,
'd g.C222 :ill.
President Chairman 1
The Hartford Electric Light Company STATEMENTS OF INCOME For Ihe Years Ended December 31, 1979 1978(a)
(Thousands of Dollars)
Operating Revenues (Note 2) 5297,917
$259,022 Operating Expenses:
Operation -
Fuel used in generation 84,824 59,478 Gas purchased for resale 12,113 9,844 Other 64,152 58,213 Maintenance 20,216 16,939 Depreciation 26,552 26,344 Federal and state income taxes (Note 3) 5,867 7,171 Taxes other than income taxes 29,777 26,259 Total operating expenses 243,501 204,248 Operating Income 54,416 54,774 Other Income:
Alloveance for equity funds used during construction 4,956 4,370, Equity in earnings of regional nuclear generating companies 1,302 1,044 Other, net (31) 211 Income taxes applicable to other income-credit (Note 3) 206 60 Net other income 6,433 5,694 Income before interest charges 60,849 60,468 Interest Charges:
Interest on long-term debt 29,445 28,365 Other interest 2,090 1,042 Allowance for borrowed funds used during construction (4,682)
(3.734)
Totalinterest charges 26,853 25,673 Net Income S 33,996 5 34,795 (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 (Thousands of Dollars)
Balance at beginning of period
$117,157 5113,859 Net income 33,996 34,795 Cash dividends on preferred stock (6,626)
(6,626)
Cash dividends on common stock (18,879)
(24,871)
Balance at end of period (a) 5125,648 5117,157 (a) At December 31, 1979, retained earnings of $41,400,000 were available for payment of cash dividends on common stock under the provisions of the Company's First Mortgage Indenture and Deed of Trust.
The accompanying notes are an integral part of these financial statements.
2
The Hartford Electric Light Company STATEMENTS OF SOURCES OF FUNDS FOR GROSS PROPERTY ADDITIONS For the Years Ended December 31, 1979 1978 (a)
(Thousamis of Dollars)
Funds Generated From Operations Net income 533,996 S34,795 Principal noncash items -
Depreciation 26,552 26,344 Deferred income taxes, net 2,464 2.413 Amortization of deferred charges and other noncash items 1,149 1,689 Amortization of deferred fuel costs 720 210 Allowance for funds used during construction (9,638)
(8,103)
,243 57,348 Total funds from operations 55 Less - Cash dividends paid on:
Common stock 18,879 71,871 Preferred stock 6,626 6.626 Net funds generated from operations 29,738 25.851 Funds Obtained From Financing Increase (decrease) in short-term debt 33,695 (27,475)
Proceeds from issuance of long-term debt 39,701 Repayments of long-term debt (440)
(4.335)
Net funds from financing 33,255 7,8 31 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 3,501 (901)
Receivables and accreed utility revenues (11,886)
(5,499)
Fuel, materials and supplies (12,690)
(1,883)
Accounts payable 13,118 4,503 Accrued taxes (1,166) 2,436 Revenues to be refunded to customers (Note 2) 1,970 Other, net (3,807) 1,370 Net change (12,930) 1,996 j
Energy adjustment clauses, net (3,375)
(287)
Ci:wr, net 80 42 Net other sources (uses) of funds (16,225) 1,751 Total Funds For Construction From Above Sources 46,768 35,493 Allowance For Funds Used During Construction 9,63S 8,103 GROSS PROPERTY ADDITIONS
$56,406
$43,596 Composition Of Gross Property Additions:
Electric utility plant S52,525
$42,167 Gas utility plant 1,856 1,090 Nuclear fuel 2,025 339 Total S56,406
$43,596 (a) The 1978 financial statements have been restated, as discussed in Note 10.
i The accompanying notes are an integral part of these financial statements.
3
The Hartford Electric Light Company BALANCE SHEETS At December 31, 1979 1978 (Thousands of Dollars)
ASSETS Utility Plant, at original cost:
Electric 5771,797
$755,736 Gas 34,443 32,785 806,240 788,521 Less: Accumulated provision for depreciation 201,943 179,229 604,297
,609,292 Construction work in progress (Note 9) 151,706 119,536 Nuclear fuelin process, net 3,345 2,324 Total net utility plant 759,348 731,152 Other Property and Investments:
Investments in regional nuclear generating companies, at equity 11,553 11,130 l
Other, at cost 3,264 3,274 14,817 514,404 I
Current Assets:
l Cash and special deposits (Note 4) 531 4,031 j
Receivables, less accumulated provision for uncollectible accounts l
of $825,000 in 1979 and $815,000 in 1978 31,881 24,080 Due from affiliated campanies 10,118 7,764 l
Accrued utility revenues 14,313 12,582 Fuel, materials and supplies, at average cost 29,585 16,895 l
Prepayments and other 909 253 I
87,337 65,605 Deferred Charges:
l Unamortized debt expense 956 1,027 Energy adjustment clauses, net 4,063 1,456 Other 2,837 4,210 l
7,856 6,693 l
Total Assets 5869,358
$817,854 l
l l
l The accompanying notes are an integral part of these financial statements.
4
At Decemher31, 1979 1978 (Thousands of Dollars)
CAPITALIZATION AND LIABILITIES Capitalization:
Common stock - $12.50 par value. Authorized 4,500,000 shares: outstanding 3,291,916 shares S 41,149 5 41,149 Capital surplus, paid in (no change during years) 109,457 109,457 Retained earnings 125,648 117,157 Total common stockholder's equity 276,254 267,763 Preferred stock not subject to mandatory redemption (cumulative) - $50 par value. Authorized 2,800,000 shares; outstanding 1,624,000 shar es (Note 5) 81,200 81,200 Preferred stock subject to mandatory redemption (cumulative) - $50 par value. Authorized 200,000 shares: outstanding 200,000 shares (Note 6) 9,500 10,000 Long-term debt, net (Note 7) 376,802 389,047 Total capitalization 743,756 748.010 Current Liabilities:
Commercial paper (Note 4) 33,695 Long-term debt due within one year (Note 7) 12,215 340 Preferred stock to be redeemed within one year (Note 6) 500 Accounts payable 9,149 6,279 Due to affiliated companies 22,912 13,708 Accrued taxes 17,197 18,364 Accrued interest 6,712 7,090 Revenues to be refunded to customers (Note 2) 2,968 Other 2,498 2,653 104,878 51,402 Deferred Credits:
Accumulated deferred income taxes 2,885 3,109 Accumulated deferred investment tax credits 15,774 13,046 Other 2,065 2,287 20,724 18,442 Commitments and Contingencies (Note 9)
Total Capitalization and Liabilities S869,358 5817,854 I
I 5
The Hartford Electric Light Company NOTES TO FINANCIAL STATEMENTS (1)
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES General: The Hartford Electric Ligh' Company (The Company), The Connecticut Light and Power Company (CL&P), Weste.n Massachusetts Electric Company (WMECO) and Holyoke Water Power Company 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 1935. Other wholly owned stabsidiaries of Northeast Utilities providing substantial 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 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, 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 CL&P have consolidated their operations by means of a transfer of all Company regional personnel (other than production personnel) to CL&P. CL&P is respon-sible for meeting the local service needs of customers of both companies and bills the Com-pany for work performed for the Company on a recovery of cost basis. The Company and CL&P have been investigating the feasibility of a corporate merger, in which CL&P would be the surviving corporation.
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 Division of Public Utility Control Authority (DPUC) 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 companies. These companies, together with the Company's ownership interest shown parenthetically are: Connecticut Yankee Atomic Power Company (9.5 percent), Yankee Atomic Electric Company (9.5 percent), Maine Yankee Atomic Power Company (4 percent) and Vermont Yankee Nuclear Power Corporation (3.5 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 on their ownership interests 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 DPUC. The Company accrues an estimate for energy delivered but unbilled at the end of accounting periods.
Nuclear Fuel: The Company, CL&P 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 energy to be provided and is billed to the companies based on their percentage ownership in 3
j the units. The amount of nuclear fuel expense charged to the Company, based on its 28 j
percent ownership, aggregated $7,155,000 and $5,497,000 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 to collect from customers; however, amounts collected from customers must be deducted from rate base. The Company is not paying NNECO, the owner of the nuclear fuel, until NNECO has to make payments for such costs. The unpaid spent nuclear fuel costs, which amounted to $1,003,000 in 1979, were transferred from accounts payable to the accumulated provision for amortization of nuclear 6
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. Storage 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 3.4 percent in 1979 and 3.5 percent in 1978, and for several classes of gas plant, which are equivalent to a com-posite rate of 2.7 percent 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 i
of retirement of the two nuclear units in which the Company has a 28 percent ownership interest is the most viable and economic method of decommissioning these units. The Company's share of the total estimated decommissioning coet is $37.4 million. Depreciation rates recognized for regulatory rate setting for the Company include an element of decom-missioning costs. It is estimated that, at such time as the costs indicated in the 1979 study are allowed by the DPUC, depreciation expense will increase from approximately $608,000 per year for the Company to approximately $1.5 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.
i FederalIncome Taacs: 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 acccrdance with the rate-making treatment of the DPUC. The Company follows the flow-through method, except for 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 ex-pected 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.
Allowance for Funds 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 i
base for rate-making purposes until facilities are brought into service and, as permitted by the DPUC, the Company charges AFUDC to the construction cost of utility plant. 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 III will be compounded semi-annually.
Retirement Plan: The Company participates in the Northeast Utilities Service Company Retirement Plan (the Plan). The Plan, which covers al! regular employees, is noncontributory.
The system's policy is to annually fund an actuarially determined contribution, which in-cludes th t 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 a< sets exceeded the value of vested benefits. The Company's allocated portion of the system's contribution, part of which was charged to utility plant, approximated $800,000 in
- 1979 and $600,000 in 1978.
Energy Adjustment Clauses: The Company's retail electric and gas rates include adjustment -
clauses under which certain fossil fuel and purchased power costs and purchased gas costs, respectively, above or below base rate levels are charged or credited to customers. As prescribed by the DPUC, costs not currently recovered under the adjustment clauses are
' deferred until recovery is permitted by the DPUC.
7
4 Effective August 1,1979, th: Company implem:nted a Generation Utilization Ad-justment Clause (GUAC), as approved by the DPUC. Monthly, this clause levelizes the effect 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 i
collected from customers over the subsequent twelve-month period. For the period August 1, i
1979 to December 31, 1979, the nuclear capacity factor was 76.6 percent, resulting in a leveling charge to fuel expense of $3,002,000.
As of December 31,1979, the components included in the energy adjustment clauses, net are as follows:
Fueland Purchased Power
$6,247,000 Cas Purchased for Resale 818,000 GUAC (3,002.000)
TOTAL
$4,063.000 i
(2)
RATE MATTERS In June 1979, the DPUC issued a decision granting the Company an increase in retail electric and gas revenues of $32.3 million. The level granted was 74 percent of the $43.6 million the Company had requested. The new rates went into effect in July 1979.
1 In January 1979, the DPUC approved the recovery of an aggregate of $3,593,000 by the Company from its 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 these costs was recorded in revenues during the first half of 1979.
I 1
The $2,968,000 of revenues to be refunded to customers as of December 31,1978 resulted from FERC approved settlements between gas distribution companies and their gas suppliers which required refunds to ultimate customers. The refunds were passed on to the Company's customers by reducing their gas bills in February 1979.
(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 (Thousands of Dollars) l Current income taxes:
Federal
$1,709
$2,844 State 1,488 1,845 Total current 3,197 4,689 I
' Deferred income taxes, net:
Investment tax credits 2,687 3,106 Federal.
(241)
(612) l State
- 18 (81)
Totaldeferred 2,464 2,413 l
Totalincome taxes
$5,661
. $7,102 Such provision (credit) is included in the accompanying statements of income as follows:
Operating expenses
$5,867
$7,171 Otherincome (206)
(69)
- Totalincome taxes -
$5,661 -
$7,102 ~
8 r
I e
Year Ended December 31.
j 1979 1978 Deferred income taxes are comprised of the tax effects of timing differences as follows:
Investment tax credits
$2,687
$3,106 Unbilled revenues (420)
(425)
Settlement credits-nuclear fuel (653)
Energy adjustment clauses 1,151 33 Other (301)
(301)
Deferred income taxes, net
$2,464, 52,413 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) 518,242 S20,110 Tax effect of differences:
Additional depreciation for tax purposes (4,843)
(5,407)
Allowance for funds used during construction -
not recognized as income for tax purposes (4,433)
(3,890)
Overhead costs of construction - expensed for tax purposes (1,036)
(894)
Investment tax credits (1,639)
(1,469)
Allocated affiliated companies' losses (716)
(810)
Cost of removal-expensed for tax purposes (604)
(658)
State tax, net of federal benefit 813 917 Other, net (123)
(797)
Totalincome taxes S 5,661 5 7,102 Effective income tax rate 14 %
17 %
(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 $168,450,000:
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
$60,000,000.
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.
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) 15.2 %
Maximum amount of borrowings outstanding at any month-end 533,695,000 530,800,000 Average daily borrowings during period 513,271,000 5 8,365,000 Weighted average interest rate during the period (based on the daily amounts out-standing and excluding effect of compensating balances) 13.8 %
g Range of maturities at December 31(in days) 2-50 9
(5)
PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION Details of preferred stock outstanding are as follows:
Par Value Current Shares December 31.
Description Redemption Price Outstanding 1979 1978 (Thousands of Dollars) 3.90% Seriesof1949
$50.50 160,000 5 8,000 S 8,000-4.50% Series of 1956 50.75 104,000 5,200
- 5,200 4.96% Series of 1958 50.50 100,000 5,000 5,000 4.50% Series of 1963 50.50 160,000 8,000 8,000 5.28% Series of 1967 52.09*
200,000 10,000 10,000 6.56% Series of 1968 52.26*
200,000 10,000 10,000 9.36% Series of 1970 54.38*
200,000 10,000 10,000 7.60% Seriesof1971 53.51*
200,000 10,000 10,000 9.60% Series of 1974 54.66*
300,000 15,000 15,000 Total preferred stock not subject to mandatory redemption 1,624,000 581,200 581,200
- Redemption price reduces in future 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.
i (6)
PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock oustanding are as follows:
Par Value Current Shares December 31, Description Redemption Price Outstanding 1979 1978,
(Thousands of Dollars) 11.52% Series of 1975 55.76*
200,000 10,000 10,000 i
Less preferred stock to be redeemed within one year (500)
Total preferred stock subject to mandatory redemption S 9,500 510,000
- Redemption price reduces in future years.
The 11.52% Series of 1975 preferred stock (the Series) requires a sinking fund sufficient to retire a minimum of 10,000 shares at $50 per share each year commencing October 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 continues. The Company's preferred stock provisions would prohibit the redemption or purchase of shares of the Series if the Company is in arrears with respect to payment of dividends on any nutstanding shares of preferred stock. There were no changes during the year in the Series. til or part of the Series may be redeemed by the Company at any time at l
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 i
limitations.
(7)
LONG-TERM DEBT j
Details of long-term debt outstanding are as follows:
(
December 31, 1979 1978 l
(Thousands of Dollars) i First Mortgage Bonds:
23/4% Series C, due1980
$ 10,006 5 10,000-25/8% Series, due 1982 5,292 5,532 31/8% Series D,
. due 1984 7,431 7,536 5%
- Series, due1987 15,000 15,000 43/8% Series E, due1988 18,000 18,000 41/4% Series, due 1993 15,000 15,000 41/2% Series, due1994 12,000 12,000 10
December 31, 1979 1978 (Thousands of Dollars) 55/8% Series, due 1997
$ 20,000
$ 20,000 61/2% Series, due1998 10,000 10,000 71/8% Series, due1998 25,000 25,000 91/4% Series, due2000 20,000 20,000 75/8% Series, due 2001 30,000 30,000 71/2% Series, due 2002 35,000 35,000 71/2% Series, due 2003 40,000 40,000 91/4% Series, due 2004 30,000 30,000 11 %
- Series, due1982 20,000 20,000 11 1/2 % Series, due1995 30,000 30,000 93/8% Series, due 2008 40,000 40.000 Total First Mortgage Bonds 382,723 383,068 Pollution Control Notes:
5.90% due1998 3,262 3,262 6.50% due 2007 4,130 4,130 Less due within one year (including $95,000 of reacquired First Mortgage.%nds in 1979) 12,310 340 Unamortized premium and discount, net (1,003)
(1,073) long-term debt, net
$376,802
$389,047 Long-term debt maturities and cash sinking fund requirements on debt outstanding at December 31,1979, are as follows: 1980, $12,215,000; 1981, $2,215,000; 1982, $26,787,000; 1983, $1,975,000 and 1984, $8,932,000. In addition, there is an annual 1 percent sinking and improvement fund requirement amounting to $3,000,000 for 1980. Such sinking and im-provement fund requirement may be satisfied by the deposit of cash or bonds, or by cer-l 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 established redemption prices plus accrued interest to the date of redemption, except that certain series are, during their respective initial five-year redemption periods, subject to certain refunding limitations. The 11%% Series bonds requires a sinking fund sufficient to retire a minimum of $1,875,000 in principal amount each year commencing October 1,1980.
Essentially all utility plant is subject to the lien of the mortgage indenture.
(8)
LEASES he 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 operations, including rental payments on capitalizable leases, amounted to $2,337,000 for 1979 and $2,462,000 for 1978.
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: 1980, $2,000,000; 1981, $1,800,000; 1982, $1,700,000; 1983,
$1,7c0,000; 1984, $1,400,000; and for the years subsequent to 1984, an aggregate of
$15,500,000.
(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 $66.3 million in 1980 and $437 million 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 11
4 i} '
load estimates, inflation, the availability and cost of capital, and the granting of timely and adequate rate relief by the DPUC. It is expected that compliance with present and developing 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 ad-ditional 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 Commission (NRC) as a result of its analysis of the Three Mile Island accident. However, additional ex-penditures may be required as a result of further NRC analysis of the accident. In addition, uncertainties related to the reprocessing or permanent storage of nuclear fuel may require revisions in future nuclear fuel costs.
At December 31,1979, construction work in progress included an investment of $130.4 h
million in jointly owned nuclear generating facilities consisting of an 18.2 percent interest in Millstone ill of $122.7 million. and a 21 percent interest in the proposed Montague nuclear 1
plant of $7.7 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-j ticipated cost of the Company's 18.2 percent ownership share of the unit, assuming approval by the appropriate regulatory commissions of the net-of-income tax accounting treatment, as discussed in Note 1, will be $377 million. In 1978, because of regulatory delays and financial constraints, the system suspended its early site review effort for the Montague facility but a
continues to perform meteorological and aquatic studies of the site and to capitalize AFUDC.
in 1980, the Company's construction 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 generating units, inflation, interest and preferred stock dividend rates and other factors, the i
nature and effect of which cannot be determined in advance.
1 i
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 subjected 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 i
government for conversion, ranges from approximately $91 million to approximately $270 j
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 $64,500,000 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 held liable for the antitrust offenses claimed in the plaintiffs' complaint.
(10) TERMINATION OF AGREEMENT FOR THE SALE OF THE GAS PROPERTIES On October 1,1979,the Company, CL&P and Connecticut Natural Gas Corporation (CNG) jointly terminated their agreement under which gas properties of the Com >any and CL&P would be sold to CNG. The Company and CL&P are currently reevaluating ti e future of their gas businesses in light of SEC requirements that a registered holding company limit its utility ~
operations to 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 l
. Segments of Business information relating to the Company's electric and gas operations for l
. the years ended December 31,1979 and 1978 can be located in the Statements of Segments of -
l Business on page 19 of this Annual Report.-
' ~
12
(12) QUARTERLY FINANCIAL DATA (UNAUDITED) (e)
Summarized quarterly financial data for 1979 and 1978 are as follows:
Quarter Ended March 31
, June 30 September 30 December 31 (Thousands of Dollars) 1979 Operating Revenues
$76,106 565,766
$77,511
$78,454 Operating Income
$15,702 5 9,341
$15,%7
$13,406 Net income
$10,720
$ 4,416
$10,829
$ 8,031 1978 (b)
Operat'ng Revenues 569,298 559,602 563,917 566,205 i
Operating Income
$10,212 511,953 515,382 517,227 Net Income 5 5,488 5 6,093 510 178 512.036 (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
$298 5298 5298 Fuel used in generation 85 85 85 Cas purchased for resale 12 12 12 Depreciation and nuclear fuel amortization 27 51 60 Other operation and maintenance expenses 83 83 83 Federal and state income taxes 6
6 6
Interest expense 27 27 27 Taxes other than income taxes 30 30 30 Other income 6
6 6
Net income (loss)
(excluding reduction to net recoverable cost)
$ 34 5 10(b)
$ 1 Increase in specific prices (current cost) of fixed assets and nuclear fuel held during the year (a) 5167 Reduction to net recoverable cost S(43)
(7)
Effect of increase in general price level (194)
Excess of increase in general price level over increase in specific prices after reduction to net recoverable cost (34)
Gain from decline in purchasing power of net amounts owed 61 61 Net S 18 5 27 (a) At December 31,1979, current cost of fixed assets and nuclear fuel, net of accumulated depreciation, was $1,617,783,000, while historical cost or net cost recoverable through depreciation was $762. 514,000.
(b) Including the reduction to net recoverable cost, net income (loss) on a constant dollar basis would have been (533,000,000) 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 dollars)
Operating revenues
$298 5288 S291 5296 5302 Ilistorical cost information adjusted for i
generalinflation l
Net income (loss) (excluding reduction to net I
recoverable cost)
S 10 Net assets at year-end at net recoverable cost 5261 l
Current cost information l
Net income (loss)(excluding reduction to net recoverable cost) 5 1 Excass of increase in general price level over increase in specific prices after reduction to net recoverable cost
$ 34 Net assets at year-end at net recoverable cost
$261 GeneralInformation Gain from decline in purchasing power of net amounts owed S 61 Average consumer price index 217.3 195.4 181.5 170.5 161.2 14
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 determinad 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 multiplying 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 the increases in specific prices of plant indicates that, for the year 1979, general inflation was greater 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. Therefore, the excess of the cost of plant stated in terms of constant dollars or current cost that exceeds the historical cost of piant 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 pur-chasing power of net amounts owed is primarily attributable to the substantial amount of debt which has been used to finance property, plant and equipment.
Auditors' Report To the Board of Directors of The Hartford Electric Light Company:
We have examined the balance sheets of The Hartford Electric Light Company (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) as of December 31,1979, 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 ac-cepted audning standards and, accordingly, inclu.ded such tests of the accounting records and such other auditing procedures as we consider necessary in the circumstances.
In our opinion, the financial statements referred to above present fairly the financial position of The Hartford Electric Light 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 Hartford Electric Light Company
SUMMARY
OF OPERATIONS (a)
For the Years Ended December 31, 1979 1978 Operating Revenues
$297,917 5259,022 Operating Expenses:
Operation and mamtenance 181,305 144,474 Depreciation 26,552 26,344 Federal and state income taxes 5,867 7,171 Taxes other than income taxes 29,777 26,259 Total operating expenses 243,501 204,248 Operating In:ome 54,416 54,774 Other Income, Net 6,433 5,694 Income Before Interest Charges 60,849 60,468 Interest Charges, Net 26,853 25,673 Income (before cumulative effect of accounting changes) 33,996 34,795 i
l Cumulative effect prior to January 1,1974 of accounting changes, relating to energy adjustment clauses and unbilled revenues, net of applicable income taxes
(
of $3,018,000 N:t Income 5 33,996 5 34,795 Pro Forma Net Income (assuming the 1974 accounting changes above were applied retroactively) l (a) These financial statements have been restated, as discussed in Note 10.
(b) The pro form change for 1969 is estimated to be immaterial and, therefore, has not been computed.
i I
i 16
1977 1976 1975 1974 1969 (Thousands of Dollars)
$242,846
$232,461
$223,968
$192,833
$92,753 128,221 120,711 131,655 114,263 45,395 25,742 21,858 16,980 16,179 9,162 7,779 4,342 780 (2,021) 5,193 25,939 26,089 23,624 21,251 11,646 187,681 173,000 173,039 149,672 71,396 55,165 59,461 50,929 43,161 21,357 4,924 4,098 6,118 4,910 1,303 60,089 63,559 57,047 48,071 22,660 23,337 24,127 21,489 20,686 6,787 36,752 39,432 35,558 27,385 15,873 7,118
$ 36,752_
$ 39,432 5 35,558 5 34,503
$15,873
$ 27,385 (b) 17
The H:rtford Electric Light 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 f Thousands of Dollars)
Operating revenues.
538,895 15.0 516,176 6.7 Operation and maintenance expenses:
Cost of fuel and gas....
27,615 39.8 1,548 2.3 Other operation expenses...
5,939 10.2 10,899 23.0 Maintenance..........
3,277 19.3 3,807 29.0 Provision for depreciation.
208
.8 602 2.3 Provision for income taxes..
(1,304)
(18.2)
(608)
(7.8)
Other taxes......
3,518 13.4 320 1.2 Allowance for funds used during construction....
1,534 18.9 546 7.2 Interest and other charges (excluding allowance for borrowed funds used during construction).
2,128 7.2 2,367 8.8 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 $3.6 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 due primarily to a rate increase which was received in late 1977 and higher kWh sales.
Operation and Maintenance Expenses Operation and maintenance expenses increased in 1979 and 1978 by $36.8 million (26 percent) and $16.3 million (13 percent), respectively. The most significant portion of the increase in 1979 was a fuel and gas cost increase of $27.6 million (40 percent). Fuel cost increases in 1979 were attributable to escalating fossil fuel prices, additional purchases of interchange power, and increased nuclear fuel costs. Nuclear fuel expenses increased due to an increase in fuel prices and the provision for the ultimate disposal of spent fuel. Another contributing 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 i
maintenance. Maintenance expense increases in 1979 were due to increased maintenance expenditures on fossil and nuclear plants of $2.0 million (28 percent) and the continuing impact of inflation.
Taxes Federal and Connesticut state income taxes decreased in 1979 due to lower taxable income and the lower federal statutory rate. Income taxes increased in 1978 primarily due to the utilization of a lesser amount of investment tax credits. Taxes other than income taxes iucreased in 1979 largely due to an increased Connecticut gross earnings tax as a result of higher revenues. In Connecticut, 5 percent of all utility revenues are paid to the state as a gross earnings tax.
Other income Other income consists mainly of the allowance for equity funds used during construction
.(AFUDC). Total AFUDC, including the portion classified as a credit to interest charges, increased by
$1.5 million (19 percent) in 1979 and $500,000 (7 percent) in 1978. The increase in AFUDC for 1979 represents growth in the average monthly balance of construction work in progress which is primarily due to the Company's investment in the construction of nuclear projects.
Interest Charges Total interest charges (excluding the credit for allowance for borrowed funds used durmg construction) increased in 1979 and 1978 by $2.1 million (7 percent) and $2.4 million (o percent),
respectively. Increased short-term borrowings and higher rates on these borrowings contributed to the increase in 1979. Additional interest charges were incurred in both 1979 and 1978 due to the interest on a new bend issue in April 1978.
18
The Hartford Electric Light Compeny STATEMENTS OF SEGMENTS OF BUSINESS 1979 1978 1977 1976 1975 (Thousands of Dollars)
For the Year Ended December 31, Operating Information Electric Operations:
Operating revenues
$277,o43 5241,584 5227,794 5219,444 5212.572 Operating expenses, excluding provision for income taxes 219,688 182,200 166,763 157.401 162,530 Pre-tax operating income 57,955 59,384 61,031 62,043 50,042 Provision for income taxes 5,736 6,879 7,861 4,523 750 Allowance for funds used during construction (AFUDC) 9.567 8.039 7,476 5,942 10.046 Operating income and AFUDC 5 61,786 5 60.544 5 60.646 5 63.462, 5 59.338 Depreciation expense 5 25.672 5 25.496 5 24.926 5 21,081 5 16,240 Capital expenditures 5 54.550 5 42,506 5 47.697 5 53.576 5 68,752 Gas Operations:
Operating revenues 5 20,274 5 17,438 5 15,052 5 13,017 5 11,396 Operating expenses, excluding provision for income taxes 17,946 14,877 13,139 11.257 9.729 Pre-tax operating income 2,328 2,561 1,913 1,760 1.667 Provision (credit) for income taxes 131 292 (82)
(181) 30 AFUDC 71 65 82 46 36 Operating income and AFUDC 5 2,268 5 2,334 5 2,077 5 1.987 5 1,673 Depreciation expense 5
880 848 5
816 777 5
740 Capital expenditures 5 1,856 5 1.090 5 1,972 5 2.013 5 1,263 At December 31, Investment information:
Identifiable assets (a)
Electric
$735,603 5708,158 5691,066 5676,197 5647,714 Cas 27,527 26,296 25,919 24,752 23,486 Nonallocable assets 106,228 83.400 76,207 82.577 82.253 Total assets
$869,358 5817.854 5793,192 5783.526 5753,453 (a) Includes construction work in progress, materials and supplies and allocated common utility property.
19
The Hartford Electric Light Company STATISTICS Operating Revenues Utility Plant December 31, (Thousands)
(Thousands)
Electric Gas Total 1969 5402,886
$ 85,851 5 6,902
$ 92,753 1974 731,434 182,059 10,774 192,833 1975 798,544 212,572 11,396 223,968 1976 832,468 219,444 13,017 232,461 1977 870,671 227,794 15,052 242,846 1978 910,381 241,584 17,438 259,022 1979 961,291 277,643 20,274 297,917 Average Average Annual Annual Cubic Feet Residential Electric Gas Kwh Sales Residential of Gas Sales Cubic Feet Customers Customers Employees (Millions)
Kwh Use(a)
(Millions) of Gas Used (Average) (Average) (December 31) 1%9 4,073 5,763 4,547 74,568 264,799 32,589 1,773 1974 5,014 6,703 4,601 75,233 282,999 31,188 1,677 1975 5,066 6,703 4,384 71,853 285,881 31,091 1,544 1976 5,283 6,930 4,598 77,981 288,055 31,012 1,395 1977 5,424 6,942 4,490 76,554 291,671 31,001 951 (b) 1978 5,567 6,963 4,627 75,753 295,387 30,909 187 (b) 1979 5,691 6,924 4,979 73,187 300,013 30,801
.184 (a) Based on residential equivalent customers, reflecting total dwelling units.
(b) Decreases are due to the consolidation of the Company's and CL&P's operations.
20
- 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 Mortgage Bonds' Trustce and Interest Paying Agent The First National Bank of Boston, Corporate Trust Department P.O. Box 644, Boston, Massachusetts 02102 Preferred Stock Transfer and Dividend Disbursing Agent.
Hartford National Bank and Trust Company, Stock Transfer Department 150 Windsor Street, Hartford, Connecticut 06115 Registrar United Bank and Trust Company, Hartford, Connecticut 06103 Dividend Payment Dates,
5.28%,9.60% and 11.52% -January ' April 1, July 1 and October 1 4.50%,4.96%,'6.56% and 9.36% -February 1, May 1, August 1-
. and November 1 3.90%,4.50% (1963) and 7.60% -March 1, June 1, September 1 and December l' a
' The data contained in this Report are subrnitted for the soIe purpose of providing information to.
- present stockholders about the Company.
r" I
l r.
i
(
t I
l l
\\
J l
f i
t l
l l
l I
I 1
l l
l NORTHEAST UTILITIES THE CONNECTICUT LIGHT ANO POWER COMPANY THE HARTFORDLECTRIC LIGHTCOMPANY '
WESTERN MASSACHUSETTS ELECTRIC COMPANY HOLYOKE WATFR POWER COMPANY
'I
{
NORTHEAST UTillTIES SERVICE COMPANY NORTHE AST FAJCLE AR ENERGY COMPANY l
.