ML20076E646

Forwards Annual Financial Repts 1982 & Vermont Electric Cooperative,Inc Annual Financial Rept 1981.SEC Form 10-K & Related Info Also Encl

ML20076E646
Person / Time
Site:	Seabrook
Issue date:	07/27/1983
From:	Devincentis J PUBLIC SERVICE CO. OF NEW HAMPSHIRE, YANKEE ATOMIC ELECTRIC CO.
To:	Harold Denton Office of Nuclear Reactor Regulation
Shared Package
ML20076E650	List: ML20076E646 ML20076E664 ML20076E671 ML20076E675 ML20076E685 ML20076E690 ML20076E693 ML20076E703 ML20076E714 ML20076E722 ML20076E727 ML20076E730
References
SBN-540, NUDOCS 8308240592
Download: ML20076E646 (644)

Text

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c SEABROOK STATION s I Compusayof ALJdLIC SERVICE Newv'ampshire Engineering Office:

1671 Worcester Road Fromingham, Mossochusetts 01701 (617) - 872 8100 July 27,1983 3BN- 540 T.F. L3.1.5 United States Nuclear Regulatory Commission Washington, DC 20S55 Attention: Mr. Harold R. Denton, Director Ofitee of Nuclear Reactor Regulation Rei ere nce s : (a) Construction Permits CPPR-135 and CPPR-136, Docket i Nos. 50-443 and 50-444

Subject:

Submitt al of 1982 Annual Financial Reports

Dear Sir:

Pursuant to 10C?R30.7)('a,', we have enclosed one copy of the 1982 Annual Financial Reporta o", 'ach of the Seabrook Statior. Joint Owners. A listing of the Joint Owners-In also enclosed.

Please contact me should you require additional information or copies of the Financial heports.

L Very truly yours, YANKEE ATOMIC ELECTRIC COMPANY civ / Q hs' John DeVincentis h ,

Project Manager' ALL/bal, Enclosure

• cc: Atomic Safety and Licensing Board Service List [

8308240592 830727 PDR ADOCK 05000443 I PDR g 00 k

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4 JOINT OWNERS Public Service of New Hampshire The United Illuminating Company Massachusetts Municipal Wholesale Electric Company

- New England Power Company Central Maine Power Company The Connecticut Light and Power Company Connonwealth Electric Company Montaup Electric Company Bangor Hydro-Electric Company New Hampshire Electric Cooperative, Inc.

Central Vennont Public Service Corporation Maine Public Service Company Fitchburg Gas & Electric Light Company Vermont Electric Cooperative, Inc.

Taunton Municipal Lighting Plant Commission Hudson Light and Power Department I

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SECURITIES AND EXCHANCE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K q ANNUAL REPORT PURSUANT TO SECTION 13 OR 15-(d) 0F

/ THE SECURITIES EXCHANGE ACT OF 1934 I

[ For the fiscal year ended December 31, 1982. Commission file number 1-5324 NORTHEAST UTILITIES (Exact name of registrant as specified in its charter)

MASSACHUSET'fS 04-2147929 (State or other jurisdiction of incorporation (IRS Employer Identification Number) or organization) 174 Brush Hill Avenue, West Springfield, Massachusetts 01089 (Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code (413) 785-5871 Securities registered pursuant to Section 12(b) of the Act:

Name of each exchange Title of each class on which registered Common Shares, $5.00 par value New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act:

None 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 durir.g the preceding 12 months (or for ouch 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 l State the aggregate market value of the voting stock held by nonaffiliates of the I

registrant.

Aggregate market value: $1,138,091,962, based on a closing sales price of $12 5/8 per snare on March 1, 1983.

Indicate the number of shares outstanding of each of the registrant's classes of common steck, as of the latest practicable date.

Class outstanding et March 1, 1983 Common Shares, $5.00 par value 90,145,898 shares l

Documents incorporated by reference:

g Portions of the Proxy Statement dated March 26, 1983 are incorporated by reference into Part III.

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NORTHEAST UTILITIES

-9 1982 Form 10-K Annual Report 5 Table of Contents P, ag,e, PART I Item 1. Businees The Company ......................................... 1 Rates ............................................... 2 General ........................................... 2 Connecticut Retail Rates .......................... 2 Massachusetts Retail Rates ........................ 3 Fuel Adjustment Clauses ........................... 4 011 Conservation Adjustment ....................... 5 Wholesale Rates ................................... 5 Construction and Financing Program .................. 6 Construction ...................................... 6 Financing Nuclear Fuel ............................ 13 Financing ......................................... 14 Electric Operations ................................. 18 Distribution and Load ............................. 18 Generation and Transmission ....................... 20 Foasil Fuels ...................................... 20

! Nuclear Generation ................................ 21 i

Gas Operations ...................................... 27

, Regulatory and Environmental Requirements and Proceedings ..................................... 29 Public Utility Regulation ......................... 29 i

i Environmental Impact Requirements ............... 30 i NRC Nuclear Plant Licensing ....... .............. 31 Water Quality Requirements ........ .............. 32 Air Quality Requirements .......................... 33 Toxic Substances and Hazardous Waste Regulations .. 33 FERC Hydro Proj ect Licensing . . . . . . . . . . . . . . . . . . . . . . 34 Segments of Business ................................ 35 Employees ........................................... 35 L

f Page Item 2.

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Properties ................................... 36  ;

Electric Properties ............................... 36

• Gas Properties .................................... 39 Franchises ........................................ 39 Item 3. Legal Proceedings ............................ 41 Item. 4 Submission of Matters to a Vote of Security Holders (Fourth Quarter 1982) ....... 42 PART II Item 5. Market for Registrant's Common Stock and Related Shareholder Matters .................. 42 Item 6. Selected Consolidated Financial Data ......... 42 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 42 Item 8. Financial Statements and Supplementary Data ........................................ 43 Item 9. Disagreements on Accounting and Financial Disclosure .................................. 43 PART III Item 10. Directors and Executive Officers of the Registrant .................................. 43 Item 11. Management Remuneration and Transactions .... 43

, Item 12. Security Ownership of Certain Beneficial Owners and Management ....................... 44 i Item 13. Certain Relationships and Related Transactions ................................ 44 PART IV l Item 14. Exhibits, Financial Statement Schedules

! and Reports en Form 8-K ..................... 44

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NORTHEAST UTILITIES '

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PART I Item 1. Business THE COMPANY Northeast Utilities (the Company) is the parent company of the North-east Utilities system (the System). It is not itself an operating company.

Through three of the company's wholly owned subsidiaries -- The Connecticut Light and Power Company (CL&P), Western Massachusetts Electric Company (WMECO) and Holyoke Water Power Company (HWP) -- the System furnishes electric service in most of Connecticut (excluding New Haven and Bridgeport and several smaller cities and towns) and in western Massachusetts. The System companies' retail electric service territories cover approximately 5,877 square miles in 208 cities and towns in Connecticut and Massachusetts with an estimated total population of 2.74 million. CL&P also furnishes retail gas service in portions of Connecticut. Its eleven separate gas service areas, not fully interconnected, cover approximately 1,321 square miles in 51 cities and towns in Connecticut with an estimated population of 1.22 million.

On June 30, 1982, two of the System companies -- The Hartford Elec-tric Light Company (HELCO) and CL&P's subsidiary The Connecticut Gas Company (Conn Gas) -- were merged into CL&P. Unless otherwise indicated, all CL&P information in this report for periods before June 30, 1982 incorporates information about HELCO and Conn Gas as if the mergers had already taken place; financial information about CL&P has been restated to reflect the mergers.

Other wholly owned subsidiaries of the Company provide substantial support services to the System companies. Northeast Utilities Service Company (the Service Company) supplies centralized accounting, administrative, data processing, engineering, financial, legal, operational, planning, purchasing and other services to the System companies. Northeast Nuclear Energy Company (NNECO) acts as agent for System companies in constructing and operating nuclear generating facilities. The Rocky River Realty Company and The Quin-nehtuk company are both real estate companies.

4 The System is operated on an integrated basis, under which the direc-tors and the principal officers of each operating subsidiary are (with some exceptions) the same.

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RATES General CL&P's retail electric and gas rate schedules are subject to the jurisdiction of the Connecticut Department of Public Utility Control (DPUC).

WMECO's retail electric rate schedules are subject to the jurisdiction of the Massachusetts Department of Public Utilities (DPU). HWP's contracts with industrial customers are filed with the DPU for information purposes, but the rates' charged are not subject tc the DPU's jurisdiction. CL&P's, WMECO's and IIWP's wholesale electric rates are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).

Connecticut Retail Rates Connecticut law provides that increased rates may not be put into effect without the prior approval of the DPUC, which has 150 days to act upon a proposed rate increase. If the DPUC does not act within that period, the proposed rates may be put into effect subject to refund. Interim rate in-creases, subjcct to refund, may be approved by the DFUC af ter a public hearing if they are found to be necessary to prevent substantial and material'deterio-ration of the financial condition, or the adequacy and reliability of service, of a utility. Under Connecticut law, the D20C is required to conduct a com-

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plete review and investigation of, and to hold a public hearing on, the finan-cial 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. The review may, and in the case of CL&P in recent >

years always has been, combined with a regular rate case.

l In recent rate decisions the DPUC has approved accounting principles and rate-making practices that improve CL&P's ability to recover its costs through rates. Certain adjustments to historical test year data are permitted to' reflect many of the conditions anticipated by CL&P during the first year amended rate schedules are to be in effect, including an allowance for the impact of inflation on the test year's operation and maintenance expenses, increased rate case and projected capitalization. Current DPUC practices also permit CL&P to accrue an allowance for funds used during construction (AFUDC) on a net-of-income tax basis and to normalize tax timing differences.

On December 14, 1382, the DPUC issued its decision in CL&P's 1982 retail rate case,' granting CL&P annual retail electric and gas revenue in-creases aggregating approximately $101.1 million, or 6.8 percent ($78.6 mil-lion, or 6.2 percent, for electric revenues and $22.5 million, or 10.2 percent, for gas revenues). The total increase granted was 79.5 percent of CL&P's a amended request. The DPUC authorized a 16.4 percent return on common equity in

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the rate base, which is 0.3 percent higher than the 16.1 percent return previ-ously allowed, but 1.1 percent below the 17.5 percent requested by CL&P. On

-} December 21, 1982 the DPUC approved revised rates reflecting the increased revenues; the revised rates are being charged with respect to service rendered

. to electric and gas customers on and after December 22, 1982.

In its decision the DPUC found that it is in the public interest and in the best interests of customers and shareholders that the construction of a third nuclear electric generating unit at the System's Millstone Point plant (Millstone 3) be continued. The current construction cost estimate for Mill-stone 3 of S.3.54 billion (including AFUDC) and the estimated in-service date of May, 1986, were found to be reasonable. The DPUC also found that abandonment of Millstone 3 would likely result in higher electricity costs for customers as well as greater financial and investment risk for the Company. The DPUC also found that the cost of electricity generat 3 by Millstone 3 over its projected useful life will likely be lower than the cost of energy from alternative sources over the same period, although such costs in the early years wculd be higher than replacemer.t oil costs. Additional information about Millstone 3 is found in many sections of this report. For detailed information, see " Con-struction and Financing Program -- Construction -- Millstone 3".

CL&P expects that it will be necessary to apply to the DPUC for additional rate relief in 1983, but the amount of rate relief to be requested and the time of application have not been determined.

Massachusetts Retail Rates Massachusetts law allows the DPU to suspend a proposed rate increase for up to six months. If the DPU does not act within the suspension period, the proposed rates may be put into effect. Interim rate increases, subject to refund, may be approved by the DPU after a public hearing if they are found necessary to avoid " probable, immediate and irreparable harm" to the business of the utility or to the interests of the customers or if they relate to known and measurable expenses which, based on DPU precedent, would not be an issue in the main proceeding.

f Under present rate making stendards, the DPU allows few adjustments I to historic test year expenses to reflect the conditions anticipated by a company during the first year amended rate schedules are to be in effect. The principal adjustments that are permitted are inflation adjustments to historic

( test year non-fuel operation and maintenance expense. Rate base and capital structure are based on test year-end levels adjusted for known and measurable changes. Because the DPU does not accept many forward-looking hdjustments, WMECO dcas not fully recover increasing costs through rates.

Current DPU practices permit WMECO to accrue AFUDC on a net-of-income tax basis and to normalize tax timing differences.

^ On November 13, 1981 WMECO filed with the DPU an application for approval Uf amended rate schedules. As subsequantly revised, WMECO's request i

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sought increases of annual revenues aggregating approximately $24 million. The DPU issued an order on May 28, 1982 granting rate relief of approximately $4.3 million. The DPU authorized a 17 percent return on common equity in rate base, which is 1 percent higher than the 16 percent return previously allowed but

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2 percent below the 19 percent requested by WMECO. On July 28, 1982 the DPU issued an order denying WMECO's Motien for Reconsideration, but allowing an additional $127,000 in rate relief to reflect some of the calculation errors WMECO sought to be corrected by its Motion for Recalculation. As revised, the total amount of the increase was only 18 percent of che amount WMECO had requested.

See " Item 3. Legal Proceedings" for a description of legal and administrative proceedings involving CL&P and WMECC, which relate to a portion of the DPU's orders concerning the System's generation and transmission agree-ment.

On October 15, 1982 WMECO filed an aprlication with the DPU for approval of amended rate schedules reflecting increases of annual revenues ag-gregating apprckimately $24.1 million. WMECO also filed a petition for interin.

rate relief of $5.3 million. Each request was suspended for six months. If approved, the permanent rates would become effective May 1, 1983. IIearings on the permanent rate application are expected to end in early March, 1983. A decisien on the request for interin relief is pending.

Fuel Adjustment Clauses The System companies have fuel adjustment clauses applicable to their retail and wholesale electric rates, and CL&P has a purchased gas adjustment clause applicable to its retail gas rates.

In Connecticut, administrative proceedings are required by the DPUC cach month to approve the charges proposed for the following month under retail fossil fuel adjustment clauses and purchased gas adjustment clauses. Monthly fossil fuel and gas adjustment charges are also subject to retroactive review and appropriate adjustment by the DPUC each quarter after full public hearings.

The Connecticut clauses do not fully track changes in fossil fuel and purchased gas costs, but the DPUC allows CL&P to recover through future rates differences in actual fossil fuel and purchased gas expenses and the amounts currently recovered from customers through fuel adjustment clauses.

CL&P's retail rate schedules also include a nuclear generation utilization adjustment clause. This clause levels the effect on fuel costs caused by variations from a 70 percent composite nuclear generation capacity factor for the nuclear units in which CL&P has entitlements. See " Electric Operations -- Nuclear Generation -- General". The 70 percent composite capacity factor is used as a baseline because it is the capacity factor used in setting base rates. For the twelve-month period ending July 31 of each year, the amount of any additional fuel cost savings or any additional fuel cost expense resulting from the actual capacity factor for that period being above .

or belgw 70 percent will be either refunded tc or collected from customers over l

the following eleven months. However, tLe clause does not automatically permit q collection from customers to the extent that the factor is less than 55 percent

{ in the twelve-month period. For the period August 1, 1981 to July 31, 1982, the composite nuclear generation capacity factor was 74.1 percent, resulting in

. fuel cost savings of $20.6 million above the base level. That amount is being returned to customers by reducing their monthly bills through July 31, 1983.

In the previous year, the composite nuclear generation capacity factor was 57.3 percent. Additional fuel costs of $51.7 million below the base level were incurred in that year; under the clause, that amount was collected from customers over the subsequent twelve months. For the five months ended Decem-ber 31, 1982, the factor was 69.2 percent.

In Massachusetts the DPU must hold public hearings before permitting quarterly adjustments in WMECO's retail fuel adjustment clause. All fuel costs are collected on a current basis by maans of a forecasted quarterly fuel clause. Legislation enacted in 1981 added to the existing quarterly fuel clause mechanism a performance program related to fuel procurement and use.

The legislation also permits a penalty for failure to meet fuel procurement and use performanca goals sct for each utility. The DPU has established perfor-mance goals for WMEC0 for the period June, 1982 through May, 1983. All fuel clause revenues collected in Massachusetts are subject to potential refund, pending the DPU's examination of WMECO's actual performance. On January 20, 1983 WMECO appealed the DPU's order setting performance goals to the Massachu-setts Supreme Judicial Court, challenging the DPU's authority to set perform-ance standards for generating plants that are not wholly owned or operated by WMECO. The Court's decision is not expected until late 1983. While it continues to question the DPU's authority to set procurement standards for all System plants, WMECO is currently operating within the present performance standards and management believes that the likelihood of a significant refund of fuel clause revenues is remote.

Oil Conservation Adjuctment To assist in financing the cost of converting HWP's oil-burning Mt. Tom station to coal-burning (see " Construction and Financing Program --

Construction -- Oil Reduction Efforts"), the System companies developed an oil conservation adjustment (OCA) rate mechanism. The OCA permits two-thirds of the fuel cost savings per kilowatthour (presently calculated as of the date of initial conversion) to be collected through rates and retained by the utility company until the full cost of conversion is paid. With the approval of the FERC, the DPUC and the DPU, the System companies have incorporated the OCA in their current retail and wholesale rates. Collection of OCA revenues began in December, 1981 and will continue for approximately three years.

Wholesale Rates CL&P has three municipal and one investor-owned wholesale electric

, customers. On December 30, 1982, the FERC accepted and approved agreements among CL&P and its wholesale customers reflecting a settlement of all aspects

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of the R-3, R-4, W-1 and W-2 wholesale rate cases pending at FERC and in the courts. Those cases have been terminated under the settlement. The customers f; ,

will receive an annual aggregate revenue reduction of $500,000 in the level of  ;[5 the existing W-1 rate, which became effective May 17, 1982, and an annual  !

aggregate revenue reduction of $500,000 in the level of the W-2 rate which will become effective on July 1, 1983. The customers have withdrawn or waived their '* '

rights to prosecute several pending and potential claims. No adjustments were made to the R-3 and R-4 rates, which vere charged from 1976 to 1982.

On December 3 and 6, 1982, WMECO filed rate schedule changes with the FERC for an annual increase totalling $900,000 in wholesale rates charged its three municipal and three investor-owned utility customers. All of the customers concurred in the requested increase. On January 18, 1983, the FERC accept (d the filing and permitted it to become effective as of November 1, 1982, as agreed to by the parties. In the filing, WMECO agreed not to seek to make effective any subsequent increase in its wholesale rates before July 1, 1983.

See " Item 3. Legal Proceedings" for a description of legal and administrative proceedings involving CL&P and UMECO, which relate to a portion of the DPU's order concerning the system's generation and transmission agree-ment, and antitrust litigation with certain of CL&P's wholesale customers.

CONSTRUCTION AND FINANCING PROGRAM Construction General The System companies have substantial financial commitments for their construction programs for the next several years, principally to complete Millstone 3. The System's construction program expenditures, including AFUDC, in the period 1983 through 1987 are estimated to be as follows:

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1983 1984 1985 1986 1987 1 (Thousands of Dollars)

Electric Plant 0 Production ............. S539,943 $535,530 $359,484 S168,935 $ 50,854 Substations and Transmission Lines ... 24,934 26,559 14,055 8,648 19,233 Dietribution Operations. 49,648 53,353 56,348 60,737 65,236 General ................ 15,714 11,127 4,851 4,984 S,310 Gas Plant ............... 21,632 16,972 15,978 15,883 16,928 TOTAL $652,071 $643,541 $450,716 S259,187 S157,561 The data shown above, and other data in this repor t, are presented on the assumption that the System companies will retain their present interests in Millstone 3 and the Seabrook project. See " Millstone 3" and "Seabrook", below.

The 1983 and 1984 construction programs include approximately $3.6 million and $0.5 million respectively, for environmental control facilities.

Millstone 3 CL&P and WMECO are the lead participants responsible for constructing and operating Millstone 3, a 1,150 MW pressurized water reactor nuclear elec-tric generating unit under construction in Waterford, Connecticut. Millstone 3 is scheduled for completion in May, 1986. CL&P and WMECO's present collective share is 65 percent of the unit (representing 747.5 MW), of which CL&P owne 52.65 percent (605.5 MW) and WMECO owns 12.35 percent (142 MW).

On September 7, 1982, CL&P and WMECO announced the comp;etion of a detailed review of the cost of constructing Mills +one J. On the basis of that review, the total estimnted cost of the unit, including AFUDC, has increased 70 approximately $3.54 billion. The previous cost estimate was'approximately

$2.6 billion, based on a review completed in December, 1980. The May, 1986 scheduled in-service date remained unchanged. The approximate aggregate cost of CL&P's and WMECO's joint ownership interest in the unit is now estimated at

$2.3 billion, compared with the previous estimate of $1.69 billion.

New and revised regulatory requirements, such as those in the areas of seismic and fire protec'cion, are responsible for approximately 60 percent of the increased costs. Other major causes of the increase are an increase to 9.25 percent, net-of-tax and compounded semi-annually, in the AFUDC rate estimate used af ter 1982, design modifications resulting from industry experi-ence, revisions to escalation predictions and changes in assumed tax rates.

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As of December 31, 1982 CL&P and WMECO had invested approximately

$1.071 billion in Millstone 3, including AFUCC of $246.3 million. Their m construction voenditures for the unit, including AFUDC, are estimated to be i approximately $4a4.4 million in 1983, S444.1 million in 1984, $298.5 nillion in 1985, and $103.1 million in 1986. At December 31, 1982 construction of the project was approximately 60 percent complete. The Company expects that construction will be substantially completed by the end of 1984, with pre-operational testing and initial fuel loading taking place in 1985.

Although it cannot assure thut the current estimate of the cost of completing Millstone 3 will not be exceeded, n.anagement of the Company believes that the current estimate in reasonable. Engineering, material purchasing and construction are at advanced staces, reducing the likelihood of major changes which could significantly alter the ultimate cost of constructing the unit. In the opinion of management, there are also fewer adverse outside factors at presant that are likely to increase the ultimate cost, because inflation rates and bortcwing rates have fallen and are projected to remain lower than in recent years, and because the rate at which the Nuclear Regulatory Commission (NRC) has published new regulations affecting the cost of constructing nuclear units has alowed. Nevertheless, many factors that are outside the Company's control, such as charges in the regulatory climate, delays or other diffi-culties occurring in the licensing process, extended labor stoppages, higher borrowing ccets and higher inflation rates, could cause the cost of construct-ing Millstone 3 to increase and could delay completion of the unit.

CL&P and WMECO were parties to contracts expiring on December 31, 1982 for the sale of interests representing an aggregate of 49.6 megawatts of Millstone 3 to four other utility systems. On the basis of their recent reviews of the estimated cost of constructing Millstone 3 and their power supply needs, three of the utility systems permitted their contracts to lapse.

These three utilities had been committed to purchase an aggregate of 42.7 mega-watts. The fourth utility system has extended its contract through June 30, 1983, but has reduced its commitment from 6.9 megawatts to 1.73 negawatts.

CL&P and WMECO intend to continue their efforts to reduce their ownership interests in Millstone 3.

A municipal utility holding a 0.365 percent joint ownership intexest in Millstone 3 has advised the Company that it is unable to make firther payments for its share of the cost of constructing the unit. CL&P and WMECO are reviewing the actions available to them.

Seabrook CL&P has a 4.05985 percent ;oint ownership interest in the Seabrook nuclear electric generating plant (two units with a rated capacity of 1,150 MW each) under construction at a site in Seabrook, New Hampshire. Public Service Company of New Hampshire (PSNH) is the le,d participant responsible for con-structing and scheduling Seabrook Units 1 and 2. On November 30, 1982, PSNH reported the completion of a review of the estinated cost and scheduling of the -

units. PSNH estimated that Unit I would be completed in December, 1984 and Unit 2 would be completed in March, 1967, at a total cost of 55.12 billion, 1

including AFULC at PSNH's rate. Subsequently it was decided to reduce 1983

• construction to a level that would result in a further deferra] of Unit 2's 3

completien date to July, 1987. PSNH estimates that this additional deferral

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will result in additional costs of approximately $122 million, including AFUDC e at PSNH's rate. The two units were previously expected to be completed in February, 1984 and May, 1986, respectively, at a cost of $3.56 billion.

PSNH attributed the higher cost estimate to such items as increased material and labor requirements, increased design and engineering complexities, increased quality assurance requirements, added costs due to deferral of scme work on the units in 1960 and 1981, additional financing costs, and corrections to the previous estimate. PSNH reported that the delayed completion date estimates reflect progress that has been slower than planned, primarily because of increased labor requirements resulting largely from enginecrir.g changes.

CL&P's actual expenditures, including AFUDC but excluding nuclear fuel, for the Seabrook project through December 31, 1982 were approximately

$95.1 million. On the basis of the two recent revisions by PSNH, CL&P esti-mates that its share of the costs would increase from approximately $133.9 million to approximately $211.5 million, an increase of $77.6 million (57.9 percent). Its construction expenditures for the Seabrook units,

' including AFUDC, are estimated to be $37.4 million in 1983, $33.0 million in 1984, $20.7 million in 1985, S18.3 million in 1986 and $7.0 million in 1987.

PSNH has been experiencing difficulties in f3nancing its construction program. If PSNH's financing program or the financing programs of other participants cannot be carried out, the construction and in-service dates for one or both of the Seabrook units night be deferred further, or construction of one or both of the units might be suspended until such financial problems are resolved. Any such deferral or suspension, or delay for any reason, would increase substantially the estimated cost of completing the Seabrook project.

An independent engineering firm has been engaged by PSNH to review and confirm PSNH's recent cost and scheduling estimates. CL&P is receiving periodic interim reports from the consultant, but CLOP has not conducted an independent review of PSNH's construction and schedule estimates and is not able to assure that both units will be completed at the estimated times and Costs.

l In 1982 the New Hampshire Public Utilities Commission (NHPUC) attempted to prohibit PSNH from using the proceeds of financings for the

construction of Seabrook Unit 2 until completion of Unit 1 or a reduction of

! PSNH's ownership interest in the Seabrook project from approximately 35 percent i to 28 percent, a level which the NHPUC believed was more consistent with PSNH's I

financing capabilities. PSNH's offer to other utilities of portions of its

, interest in the project received no substantial responses. Upca appeal of the

! NHPUC's order prohibiting such use, the New Hampshire Fupreme Court, in a i, three-to-two decision, vacated the NHPUC's order, concluding that the NHPUC does not have the authority to impose such a prohibition on financings.

! Other proceedings, before the NHPUC and before other governmental bodies in New Hampshire and elsewhere, involvo questions about the need to 1

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r complete one or both units and the ability of PSNH and other participants to finance their interests in the project. CL&P has not independently examined .

PSNH's and other participants' abilities to finance their respective shares of '

the units.

Oil Reduction Efforts The System has dcveloped a comprehensive energy conservation and supply plan entitled the " Northeast Utilities Conservation Program for the 1980s and 1990s" . (NU 80s/90s) . The major goals of NU 80s/90s are to reduce the System's oil dependence and to assist customers to take cost effective conser-vation actions. The customer conservation elements of the program are intended to make customers aware of conservation's potential, to inform them about preferred technical and economic means of conservation, and to provide them with selected conservation services.

A specific goal of NU 83s/90s is to cut the System's use of oil in the generation of electricity. The principal actions which were proposed to meet the System's oil-reduction targets are the following:

o Placing Millstene 3 in service by 1986, as scheduled, while retaining a substantial part of the System's present ownership; o Adding hydroelectric capacity, including imported sources, and encouraging customer-owned cogeneration and small power production, including refuse-derived and hydroelectric energy; and o Converting the most suitable System oil burning units to coal, provided that such conversion is cost-effective and can be financed by the System.

l i While reduction of the use of oil for generating electricity remains I a specific goal of the System, occurrences since NU 80s/90s was developed in l

carly 1981 have adversely affected the System's ability to inplement an aggres-sive coal conversion effort. As a result, NU 80s/90s' specific target of reducing the percentage of oil used in generation to ten percent by 1907 cannot l be met, although substantial reductions are still contemplated.

l Restrictive environmental standards, the delay that results from uncertainty in regulatory and environmental standards and lower oil price projections all contribute to likely increases in the estimated costs of

< converting suitable oil burning units to coal and reductions in the expected l cost benefits from conversion.

Significant uncertainty has been created in Connecticut by a recent l

preliminary decision of a Connect 4. cut Departnent of Environmental Protection hearing officer in a case involving an unaffiliated utility company. If upheld, the decision would require emissions from a converted coal burning plant to meet the very restrictive standards imposed by the federal government ,

3 on new emission sources. The cost of meeting new source standards at CL&P's  ;

} s Norwalk Harbor or Devon sites would in the Ccmpany's judgment be prohibitive, if they could be met at all.

• In the current economic and regulatory climate, therefore, the Company has decided that it will complete the conversion of HWP's 148 PW Mt. Tom Station in Holyoke, Massachusetts, as described below, that it will continue its technical studies for the conversion of up to an additional seven units, but that it will not begin the actual conversion of any more units until the required environmental standards are more favorable and certain and the cost-effectiveness of conversion can be more assured. The System's construc-tion program includes only funds for Mt. Tom Station and studies.

The first phase of converting Mt. Tom Station was completed in December, 1981, when coal burning began. Before coal could be burned, modi-fications to existing environmental protection and control equipment, waste water and ash disposal systems, and coal handling and coal burning facilities were necessary. The cost of these initial modifications was approximately

$15 million, exclusive of AFUDC. More extensive modifications needed to meet final envirormental requirements will be effected during a second phase, which could extend until February,1984. During the second phase the unit is operat-ing under a delayed compliance order (DCO) issued by the federal Environmental Protection Agency (EPA) under the Clean Air Act. The DCO permits state emis-sion standards to be exceeded temporarily while new air pollution control equipment is installed at the plant. The total cost of converting Mt. Tom Station is estimated at $40 million. The initial financing for conversion of Mt. Tom Station is being provided by a $12 million pollution control revenue bond issued by the City of Holyoke, Massachusetts, and a $28 million revolving credit loan agreement between HWP and a syndicate of banks. These borrowings are being repaid through the use of the OCA mechanism described in " Rates".

In addition to completing Millstone 3, the significant oil reduction energy supply actions other than conversion of Mt. Tom Station involve importing hydroelectric power from Canada, adding some hydroelectric capacity in the System's service area, and cooperating with cogenerators and small power producers.

In January, 1982, CL&P, WMECO and HWP entered into agreements with other New England utility companies which will finance, construct and own the United States portion of a 450 kV direct current transmiesion circuit between New England and Quebec, Canada. The project would initially provide approxi-mately 690 MW of capacity for importing electricity generated in Canadian hydroelectric plants. By the end of February, 1983, most of the material regulatory approvals necessary for construction to begin had been obtained.

The DPU approved WMECO's participation in the project in December 1982. The DPUC approved CL&P's participation in the project on March 1, 1983. HWP's participation does not require state regulatory approval. The line is expected

, to be completed by November, 1986. Under the agreements, the System companies will be responsible for their share (expected to be 23.6 percent) of the annual costs associated with the United States portion of the interconnection when the line is completed, and they will be entitled to use their proportional shares of the line's capacity to transfer power to and from Quebec. The System expects that, in' addition to reducing oil consumption, the project will make y cost savings available to custoners by enabling the System to purchase surplus, e lower cost Canadian power. Cost savings will also be achieved by permitting the " banking" of energy in Canada during off-peak hours in New England, while making equivalent amounts of energy available to New England during peak hours.

HWP is constructing Hadley Falls Unit No. 2, a 15 MW hydroelectric facility in Holyoke, Massachusetto. Through December 31, 1982, HWP had expended

$10.7 million on the unit. The project is scheduled for completion in November, 1983, at a total. cost of approximately $21.4 million.

CL&P also proposes to cooperate with a private developer in a project under which the private developer would construct a 6 MW hydrcelectric facility on the Housatonic River between Derby and Shelton, Connecticut. The facility is expected to cost approximately $12 millions financ~ing for the project is to be provided by the private developer. An application with respect to that project was filed with the FERC in February, 1983. An application for that site had previously been filed by a competing developer. Regulatory approval for the project in which CL&P is involved is not assured.

In its December, 1982 CL&P retail rate decision, the DPUC ordered CL&P to prepare an " aggressive" hydroelectric development program. Such a program would compel CL&P to reconsider its standards for evaluating the cost effectiveness of developing additional capacity sources. The economic justifi-cation for hydroelectric projects under such a program wil: require cost recovery over a significantly longer period than CL&P has previously used for economic studies.

CL&P is cooperating with the Connecticut Resource Recovery Authority (CkRA) in a study of the technical and financial feasibility of a refuse recovery and burning project at CL&P's South Meadow (Hartford) Station to usa solid wastes from a number of mid-Connecticut municipalities as a fuel source for generating electricity. If the project is found to be feasible, modifica-tion of the South Meadow facilities could be accomplished by approximately 1986. The CRRA would provide most of the financing for the project. It would build and own refuse receiving, processing and storage facilities on land leased to it by CL&P. It would also build and Own the boilers and ancillary equipment for production of steam at the generating plant. CL&P would rehabil-itate its existing steam turbine generators, operate the boiler and generation facilities, and purchase all or a portion of the steam when it is available.

The project, which might also burn coal as a supplemental fuel, would have l

capacity of approximately 65 MW. CL&P's participation in the project would be subject to DPUC approval.

t i ,

1 Financing Nuclear Fuel b The System's nuclear fuel requirements are for its two operating nuclear units, Millstone Unit Nos. 1 and 2 (Millstone 1 and 2) and for the o three nuclear units under construction in which the System has interests, Millstone 3 and the two Seabrook units. The requirements for the Millstone units are financed through a third party trust financing described below. All nuclear fuel for CL&P's share of the Seabrook units is owned and inanced directly by CL&P. For the period 1983-1987, CL&P's share of the cost of nuclear fuel for the Seabrook units is estimated at $12.5 million, including AFUDC.

In February, 1982, CL&P and WMECO entered into arrangements under which a trust (the Niantic Bay Fuel Trust, or "NBFT") will own and finance the nuclear fuel for Millstone 1 and 2 and the System's share of the nuclear fuel for Millstone 3. NBFT finances such fuel from the time uranium is acquired, during the offsite processing stages and through its use in the units' reactors.

NBFT obtains funds from bank loans, the sale of commercial paper backed by a bank letter of credit and the sale of intermediate term notes. The fuel will be leased to CL&P and WMECO by the trust while it is used in the reactors, and will be transferred to CL&P and WMECO when it is discharged from the reactors.

CL&P and WMECO are severally obligated to make quarterly lease payments, to pay all expenses incurred by NBFT in connection with the fuel and the financing arrangements, to purchase the fuel under certain circumstances and to indemnify all the parties to the transactions.

The trust arrangements presently allow up to $230 million to be financed by NBFT through January, 1987 with bank loans and letter-of-credit-backed commercial paper. After that date, the arrangements with the banks will continue in effect from year to year unless terminated voluntarily by CL&P and WMECO or unless terminated, in whole or in part, by the banks upon four years' prior notice. The arrangements with the banks also allow up to $300 million in aggregate principal amount of intermediate term notes to be sold by NBFT.

Through December 31, 1982, NBFT had issued $125 million of intermediate term notes. The amount of credit available to CL&P and WMECO through NBFT is increased by the amount of any intermediate term notes which are sold.

During 1982, NBFT acquired the fuel being prccessed for Millstone 1 and 2 and the System's share of the fuel being processed for Millstone 3.

Before it was acquired by NBFT, the fuel in process for Millstone 1 and 2 had been financed on behalf of CL&P and WMECO by another fuel trust which owned the j

fuel until it was placed in a reactor. Fuel in the Millstone 1 and 2 reactors i

had been financed by NNECO, a subsidiary of the Company, through bank borrowings, issuing secured notes and receiving capital contributions or advances from the company.

' On December 1, 1982, the fuel in the Millstone 1 and 2 reactors was

, acquired by NBFT. Proceeds of approximately $109 million were received by NNECO and were used primarily to retire S65 million of NNECO's secured notes and to make a $30 million dividend payment to the Company.

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As of December 31, 1982, NBFT's investment in nuclear fuel for all three Millstone units was approximately S267.0 million, which consists of ,

S96.4 million of fuel being processed for Millstone 1 and 2, $66.3 million of fuel being processed for Millstone 3 and $104.3 million of fuel in the Mill-stone 1 and 2 reactors.

e Nuclear fuel costs are being recovered through rates as the fuel is consumed in reactors.

Financing 1982 In 1982 the System companies realized aggregate gross proceeds, before underwriting commissions and costs of issuance, of approximately

$311 million by issuing and selling common shares, preferred stock and first mortgage bonds. In addition, the System companies entered into revolving credit and trust financing arrangements, described below, under which up to approximately $1.0 billion can be made available to the System companies.

These financings were undertaken to support the construction and nuclear fuel requirements described above and to meet approxinately $237 million of 1982 debt maturities and cash sinking fund requirements.

The Company issued and sold eight million common shares in a public offering in May, realizing net proceeds of approximately $82.8 million. The Company also realized approximately $25 million in 1982 through the sale of approximately 2.5 million shares under its dividend reinvestment and comnon share purchase plan. HELCO issued and sold $20 million principal amount of eight year first mortgage bonds in February at an interest rate of 17.6 percent per annum and $40 million principal amount of ten year first mortgage bonds in May at an interest rate of 15 5/8 percent per annum; CL&P assumed these bonds and all other outstanding HELCO bonds on June 30, 1982, in connection with its merger with HELCO. CL&P issued and sold $100 million principal amount of thirty year first mortgage bonds in October at an interest rate of 15 percent per annum and issued and sold, for S40 million, 800,000 shares of preferred stock in June at a dividend rate of 15.04 percent per annun. The Company made capital contributions of $110 million to CL&P, S10 million to WMECO and $3 million to HWP in 1982. The bulk of those funds were provided by the

$82.8 million proceeds of the Company's public offering of eight million shares in May, with the balance coming from the sale of shares under the Company's dividend reinvestment and common share purchase plan and a $30 million rividend from NNECO to the Company.

In February, 1982, CL&P and WMECO completed the new nuclear fuel financing arrangements described above under " Financing Nuclear Fuel". In October CL&P and WMECO revised a $140 million revolving credit and term loan agreement to reduce borrowing costs, extend maturities and increase the maximum amount that could be borrowed to S200 million. In November CL&P entered into a two-year $50 million floating rate Eurodollar loan agreement. ,

a i l In March, 1982 CL&P and WMECO entered into a construction trust

• arrangement to provide advance commitments to assist them to finance their i shares of the cost of constructing Millstone 3. The financing involved the establishment of a special purpose trust. The trust was given a lien, junior o to the liens of CL&P's, HELCO's and WMECO's first mortgage indentures, on the companies' interests in Millstone 3 in exchange for the construction trust's agreement to make loans to the companies and to reimburse the companies for a significant portion of their Millstone 3 expenditures as they are incurred.

The trust's obligations are initially limited to $400 million. The trust will meet its obligations by issuing up to $200 million of letter-of-creait-backed commercial paper and issuing up to an additional $200 million of term notes to participating banks. Once Millstone 3 is in service, but beginning no later than 1988, the trust obligations are to be repaid over a four-year period. The companies are also obligated to pay all expenses incurred by the trust in connection with the financing arrangements, to repay the borrowings before their normal maturity in certain circumstances, and to indemnify all parties to the transactions. As of December 31, 1982, the trust had provided $96 million and $39 million of financing for CL&P and WMECO, respectively.

Requirements In addition to financing the construction requirements described under " Construction", the System companies are obligated to meet $205 million of long-term debt maturities and cash sinking fund requirements in 1983 through 1987. In ISB3, long-term debt maturity and cash sinking fund requirements will be $18 million.

In 1983 the construction program expenditures of $652 million, the nuclear fuel requirements of $2 million for CL&P's share of fuel for the Seabrook station, and the long-term debt maturity and cash sinking fund re-quirements of $18 million are expected to produce aggregate capital require-ments of $672 million. The System companies propose to finance their 1963 requirements through a combination of internally generated and external funds, with external funds expected to provide approximately three-fourths.

1983 The Company expects to offer approximately six million additional common shares to the public in 1983. These shares would be in addition to those issued under its dividend reinvestment and common share purchase plan.

CL&P expects to issue and sell approximately $130 million principal amount of intermediate term or long-tern debt securities and approximately $45 million (900,000 shares) of its $50 par value per share preferred stock in 1963. WMECO expects to issue and sell approximately $50 million (500,000 shares) of its

$100 par value per share preferred stock in 1983. The Company expects to make additional open account advances or capital contributions in 1983 to System 3 companies in amounts up to $90 million in the aggregate, primarily to CL&P (up to $60 million) and WMECO (up to $30 million).

T l In lieu of one or more conventional first mortgage bond issues, CL&P might borrow up to $75 million in 1983 in a Eurobond financing that would be ,

effected through a special finance subsidiary. The subsidiary would issue its own debentures in the Eurobond market (i.e., outside the United States of America) and would relend the net proceeds of the debenture issue to CL&P.

CL&P would guarantee its subsidiary's obligations. CL&P is also considering entering into an floating rate Eurodollar intermediate term loan arrangement for up to $75 million coupled with an " interest rate swap" arrangement. The objective of such an arrangement is to convert the floating rate term loan obligation into a fixed rate obligation having a lower effective interest cost than a comparable first mortgage bond issue. Whether a Eurobond issue, a term loan and interest rate swap transaction or a conventional first mortgage bond issue will be effected by CL&P will be evaluated at the proposed time of issue in the light of prevailing interest rates and market conditions.

The amount and kind of each issue of securities, and the timing of the securities issues have not been definitively determined.

Financing Limitations The amounts of short-term borrowings which may be incurred by the Company, CL&P, WMECO, HWP cnd NNECO are subj ect to periodic approval by the Securitics and Lxchange Commission (SEC) under the Public Utility Holding Company Act of 1935. Short-term or other unsecured borrowings are also re-stricted, in the case of CL&P and WMECO, by the preferred stock provisions of their charters, and in the case of the Company, WMECO and HWP, by loan agree-ments. The amounts of such restrictions and the amounts of outstanding short-term borrowings are set forth below for the Company, CL&P, WMECO, HWP and NNECO as of December 31, 1982:

Restrictions outstanding at 12/31/82 Preferred Stcek Short- Total Short-SEC and Loan Commercial Term Bank Term Debt Authorization Limitations

• Paper Loans ** Outstanding (Thousands of Dollars) (Thousands of Dollars)

Company ..... $100,000 S298,000 $ 10,000 $ 10,000 CL&P ........ 410,000 571,000 $ 25,775. 8,800 34,575 WMECO ....... 85,000 89,000 11,950 1,000 12,950 HWP ......... 28,000 41,000 RNECO ....... 80,000 NONE TOTAL ....... $703,000 0999,000 $ 37,725 $ 19,8C0 $ 57,525 (see footnotes, next page] e e

• While not restricting the amount of short-term debt which CL&P or WMECO may incur, several other loan agreements under which CL&P and WMECO are borrowers provide that the lender is not required to make additional loans if the borrower does not meet specified financial ratios. Compliance with such ratios normally requires, in effect, that the borrower's debt (as defined in each agreement) not exceed specified percentages of total capitalization (as defined).

• • See note 5 to the consolidated financial statements for information about credit lines available to System companies.

The indentures securing the outstanding first mortgage bonds of CLnP and WMECO provide that additional bonds may not be issued, except for certain refunding purposes, unless earnings (as defined in each indenture, and before income taxes) are at least twice the pro forma annual interest charges on outstanding bonds and certain prior lien obligations (including outstanding HELCO bonds in the case of CL&P) and the bonds to be issued. CL&P's first mortgage indenture contains a second test that nust be met before additional bonds may be issued, namely that CL&P's earnings (as defined, and after deduct-ing income taxes) are at least 1 3/4 times the pro forma annual interest charges on outstanding bonds and certain prior lien obligations (including outstanding HELCO bonds) and the bonds to be issued. The preferred stock provisions of CL&P and WMECO also prohibit the issuance of additional preferred stock unless earnings (as defined) are at least one and (ne-half times the pro forma annual interest charges on indebtedness and the annual dividend require-ments on preferred stock that will be cutstanding after the additional stock is issued.

On the basis of the indenture and preferred stock formulas, the coverages for the years ended December 31, 1980, 1981, and 1982 were, based on the amounts outstanding as of the end of such periods, as follows:

CL&P WMECO Bond Coverage Preferred Preferred Stock Bond Stock 2.00 Test 1.75 Test Coverage Coverage Coverage December 31, 1980 2.20 1.77 1.31 2.23 1.25 December 31, 1981 2.38 1.90 1.46 2.46 1.56 December 31, 1982 2.83 2.19 1.73 2.66 1.63 c>

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As part of the merger of HELCO into CL&P, the outstanding preferred stock of HELCO became preferred stock of CL&P. The new CL&P preferred stock i,

has the same dividend rates, sinking funds, liquidation preferences and other relative rights and preferences as the HELCO shares for which they were sub-stituted. The outstanding HELCO bonds were assumed by CL&P, and the HELCO indenture was closed to the issuance of additional bonds. Any subsequent bond 8 issues, including any rcfunding of outstanding HELCO bond issues, will be effected under the CL&P indenture.

The System companies' ability to meet their financial requirements depends heavily on the adequacy of future earnings, and, therefore, on their ability to obtain adequate and timely rate relief. Since a substantial portion of the subsidiaries' earnings in the period before Millstone 3 and the seabrook units are placed in rate base is expected to consist of AFUDC, a noncach item, the extent to which the companies must issue senior securities to meet cash requirements is increased. Generally prevailing interest rates and other conditions in the capital markets, and the market appraisal of the System companies' securities, including the Conpany's common shares, also affect the System companies' ability to carry out their financing plans. If the system companies were to encounter difficulty in financing their present requirements, they would be forced to consider further deferrals or abandonments of projects in their respective construction programs and further reductions of their ownership interests in generating units, operating or under construction.

ELECTRIC OPERATIONS Distribution and Lo,a,d System operating companies own and operate a fully-integrated elec-tric utility business. System companies' retail electric service territories cover approximately 5,877 square miles and have an estimated total population of 2.74 million. The companies furnish retail electric service in 208 cities and towns in Connecticut and Massachusetts.

System operating companies furnish firm wholesale electric service to eight municipal electric systems and four investor-owned electric systems.

Three Connecticut municipal electric systems that had previously been firm wholesale customers of CL&P have teen served since late 1981 by the Connecticut Municipal Electric Energy Cooperative (CMEEC). CL&P has sold CMEEC life-of-unit rights to capacity from 24 of CL&P's own generating units, and from CL&P's interests in ten jcintly-owned generating units. These contracts involve capacity comparable to that previously used by CL&P to serve the municipal systems now served by CMEEC. The contracts do not affect CL&P's ownership interests in the generating units.

4 1 1 The City of Springfield, Massachusetts, is studying the possibility of forming a municipal electric department and acquiring WMECO's facilities in the city. Springfield is the largest city in WMECO's service territory.

• About 86 percent of the System's consolidated operating revenues for 1982 came from electric operations. Electric revenues for 1982 were derived 42 percent from recidential customers, 32 percent from commercial customers, 21 percent from industrial customers, 3 percent from wholesale customers and the balance from others. The components of electric revenues were not materially different in 1981.

Through March 1, 1983 the all-time maximum demand on the System was 4,126,600 kilowatts, which occurred on January 12, 1981. This figure includes slightly more than 100,000 kilowatts of demand from CMFCC's members. Since October 1, 1981, maximum demand has been computed without CMEEC's requirements.

The generating capacity of the System's generating plar.ts (ir.cluding the System companies' entitlements in rcgional nuclear generating companies) was 6,373,400 kilowatts at the time of the peak. The System was selling 388,900 kilowatts of capacity from its plants to other utilities at that time. Svstem capacity which is in excess of System needs is offered for sale to other utilities.

During 1982, Systen, energy requirements were met 57 percent by nuclear units, 32 percent by oil burning units, seven percent by coal burning units, and four percent by hydroelectric units. By comparison, during 1981, System energy requirements were met 54 percent by nuclear units, 42 percent by r

oil burning units, one percent by coal burning units, and three percent by hydroelectric units.

A goal of the System is to promote conservation measures that will help contain the growth in the demand for electricity. The System's March, 1983 load forecast estimates that total energy requirements over the next ten years will grow at an annual compound rate of 1.5 percent, which approximates the load growth target set forth in NU 80s/90s more than two years ago. The Company believes that the lack of significant load growth experienced in the past three years, and the decline of 1.9 percent in the System's kilowatthour sales from 1981 to 1982 (excluding sales to CMEEC for the first nine months of 1981) , result in large measure from poor econcmic conditions and unusually moderate weather in the region, and that these do not repro 7ent long-term trends that should be expected to continue. See " Construction and Financing Program -- Construction -- Oil Reduction Efforts" for information about the System's conservation and load growth plans.

The Company expects that the System will be able to meet currently projected customer electricity loads with its existing operating units reliably until at least the early 1990s. It expects that the addition of Millstone 3 and the two Seabrook units would provide the System with the additional capacity necessary to n.eet projected loads until the late 1990s. Decisions

, about capacity additions to meet needs for later periods are expected to be made in the mid-1980s.

f Generation and Transmission Systen operating companies and most other New England utilities with ,'

electric generating facilities are parties to the New England Power Pool (NEPOOL) Agreement. Under the NEPOOL Agreement the region's generation and 5

transmission facilities are planned and operated as part of a regional New England bulk power system. System transmission lines form part of a New Ergland transmission system linking System generating plants with one another and with the facilities of other utilities in the northeastern United States and Canada. The generating facilities of all participants are operated as a single system th rough the New England Power Exchange, a central dispatch facility. The NEPOOL 3greenent provides for a determination of the generating cv acity responsibilities of participants and certain transmission rights and recponsibilities. Pool dispatch results in substantial purchases and sales of electric energy by pool participants, including the Systen companies, at prices determined in accordance with the NEPOOL Agreement.

The System companies pool their electric production costs and the costs of their principal transmission facilities. This arrangement makes unit bulk power costs of the Systen companies substantially uniform.

Fossil Fuels Oil Oil-fired generation produced approximately 32 percent of the elec-tricity provided to the System's customers in 1982, compared with 42 percent in 1981. These figures represent the use of approximately 12.5 million barrels of oil in 1982, down frcm 16.6 million barrels in 1981. In 1982, approximately 10.5 million barrels of fuel oil were consumed by the System's own stations in the generation of electricity, down approximately 20 percent from the 13 million barzels used in 1981.

The System companies were able to obtain their full oil requirements in 1982. The average 1982 price paid for fuel oil was about 11 percent below the 1981 level. Currently, the prices for the System's fuel oil are running slightly below 1982 levels, reflecting a surplus of conventional fuel oil.

Very low su: fur fuel oils, such as the 0.5 percent sulfur content oil burned at CL&P's Middletown Station, command a price premium over other fuels and have limited availability in the market place.

The System *c fuel oil storage capacity is approximately three million barrels. The incontory is generally sufficient for 45 days of operation.

The bulk of the Systen's oil requirements is purchased under contracts from three large independent oil companies. The contracte expire annually but may be extended from year to year by mutual agreement.

4 Coal

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. The first major coal purchases for the System in ten years were begun

< in August, 1981 to meet the December oil-to-coal conversion date at the Mt. Tom

'* Station. See " Construction and Financing Program -- Construction -- Oil Reduction Efforts." The quality of coal currently being used at Mt. Tom Station is very high in heat value and low in ash content in order to minimize the particulate emissions during the interim period required for the Company to design and install a more efficient precipitator.

Mt. Tom Station consumed 404,000 tons of 1.5 percent sulfur content I coal in 1982 at an average delivered price of $63.50 per ton. On the basis of fuel cost per unit of heat energy delivered, the 1.5 percent sulfur content coal which is new burned at Mt. Tom Station currently costs about 50 percent less than the 2.2 percent sulfur content oil it is replacing. Coal of this sulfur grade is readily available; current prices' are running below those which were in effect in 1982. All of the coal purchased for the Mt. Tem Station is on a " spot" basis and nine vendors have supplied coal to date. Follcwing the installation of a more efficient precipitator at the station in the summer of 1983, HWP will re-examine its arrangements for coal supply for the station.

The Company believes that the availability of transportation and coal supplies is adequate to meet HWP's requirements for Mt. Tom Station.

Nuclear Generation General Together CL&P and WMECO own 100 percent of Millstone 1 and 2, as tenants in common. Their respective ownership interests are 81 percent and 19 percent.

CL&P and WMECO have agreements with other New England utilities i covering their joint ownership as tenants in common of Millstone 3. CL&P is a i j party to such an agreement with respect to its interest in the Seabrook units.

l The agreements all provide for pro rata sharing of the construction and operat-ing costs and the electrical output of each unit by che ownere, as well as associated trancmission costs.

CL&P and WMECO own stock in four regional nuclear generating com-panies (the tankee companies) whose other stockholders are all New England electric utilities. Each Yankee company owns and operates a single nuclear generating unit. The stockholder-sponsors of a Yankee company are responsible for proportionate shares of the operating costs of the Yankee company, and are entitled to proportionate shares of the electrical output. The relative rights and obligations with respect to the Yankee companies are approximately propor-I tionate to the stockholders' percentage stockholdings, but vary slightly to reflect arrangements under which non-stockholder electric utilities have contractual rights to some of the output of particular units. The Yankee a

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companies and CL&P's and WMECO's stock ownership percentages in each are set forth-below CL&P WMECO System Connecticut Yankee Atomic

• Power Company (CYAPC) ........... 34.5% 9.5% 44%

Maine Yankee Atomic Power Company (PYAPC) .......,....... . 12.0% 3.0% 15%

Vermont Yankee Nuclear Power Corporation (VYNPC) ....... 9.5% 2.5% 12%

Yankee Atomic Electric Company (YAEC) ................. 24.5% 7.0% 31.5%

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. The shareholders of VYNPC have guaranteed their pro rata shares of a $40 million nuclear fuel financing. CL&P's and WMECO's guaranties in this financing aggregate $4.8 million, plus indemnity obligations. Share-holders of CYAPC have guaranteed their pro rata shares of $50 million principal amount of 17 percent sinking fund debentures and up to $50 million of borrowings that may be made under a revolving credit agreement. CL&P's and WMECO's shares of the guaranties in these financings aggregate $44 million.

The Company believes that the Yankee companies will require additional external financing in the next several years to finance construction expenditures and nuclear fuel or for other purposes. Although the ways in which each Yankee company will attempt to finance these expenditures have not been finally determined, the Company expects that the System companies may be asked to provide additional equity capital and/or other types of direct or indirect financial support for one or more Yankee companies.

Operations The System companies have interests in six operating nuclear units, Millstone 1 and 2 and the four units owned and operated by the Yankee compa-nies. The System operates the Connecticut Yankee unit on behalf of the owners of CYAPC.

In 1982 Millstone 1 operated at a 70.7 percent capacity factor. (A capacity factor is a ratio which compares a unit's actual generating output for a period with the unit's maximum potential output if it had operated at its design limits for every hour in the period.) The unit was out of service for ten weeks.beginning in September, 1982 for scheduled refueling and maintenance.

During the shutdown, turbine modifications were made to permit the unit to return to full capability; it had been operating at reduced capability since the unit incurred turbine damage in mid-1981. Millstone 1 is not scheduled to shut down again for refueling and maintenance until 1984. .

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Millstone 2 operated at a 66.2 percent capacity factor in 1982 The unit was out of service for an extended refueling and maintenance outage which began in December, 1981 and was completed in March, 1982. A pitting corrosion problem affecting steam generator tubes was identified during the outage.

• Approximately 700 tubes with defects greater than 40 percent of wall thickness (out of more than 17,000 tubes in the unit) were plugged with removable mechanical plugs. The problem was determined to be an operational problem rather than a safety problem. The unit retutaed to service at 100 percent of its capacity. Detailed analyses to determine the specific causes of the pitting phenomena are underway. The cost and effectiveness of proposed corrective measures, including chemical cleaning, tube sleeving, and sludge lancing, are currently being evaluated. Millstone 2 is scheduled for a sixteen week refueling and maintenance outage beginning in May, 1983. A substantial amount of tube sleeving is scheduled to be performed during the outage.

The Connecticut Yankee, Maine Yankee, Vermont Yankee and Yankee Atomic units operated in 1982 at capacity factors of 89.0 percent, 62.0 per-cent, 90.3 percent and 57.3 percent, respectively. As of December 31, 1982, the Connecticut Yankee unit had, since it began operations in 1968, generated more than 62 billion kilowatthours of electricity, which the Company believes is more than any other nuclear generating unit in the world has produced.

The Maine Yankee and Yankee Atomic units completed scheduled refuel-ing and maintenance outages in 1982; the next scheduled outage for each unit is in 1984. During its 1982 refueling outage, the Yankee Atomic unit underwent extensive turbine repairs, which restored it to full capability after approxi-mately two years of redaced capacity operations. The Connecticut Yankee unit was shut down on January 22, 1983 for a planned seven-week refueling and maintenance period. The Vermont Yankee unit is scheduled to be taken out of

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service on March 5, 1983 for refueling and maintenance.

As holders of licenses to construct or operate nuclear reactors, CL&P, WMECO and NNECO are subject to the jurisdiction of the Nuclear Regulatory Commission (NRC). The NRC has broad jurisdiction over the design, construction and operation of nuclear generating stations, including matters of public health and safety, financial qualifications, antitrust considerations and environmental impact.

The NRC regularly conducts generic reviews of technical issues, a number of which may affect the nuclear plants in which System companies have interests. These issues include seismic design standards for nuclear plants located in the Eastern United States, a probabilistic risk assessment program to measure the likelihood and effects of severe accidents at operating nuclear plants, the possibility that neutron bombardment may adversely affect the reactor pressure vessels of operating pressurized water reactors, the ability i of safety related equipment to function properly under accident conditions, post-accident measures for controlling hydrogen, a program to evaluate the l , ability of operating plants to meet current licensing requirements and other l

issues. At the present time, the outcome of the NRC's reviews of these issues, and the ways in which the different nuclear plants in which System companies l

have interests may be affected, cannot be determined. The cost of complying with any new requirements which may result from these reviews cannot be es-

^

timated at this time, but such costs may be substantial.

It is anticipated that additional changes in nuclear plant construc-tion, including further .backfitting of existing plants, and in nuclear plant

• operations might be required by the NRC. The System companies' actions and changes in hRC requirements might also result in increases in the capital expenditures and operating costs associated with the nuclear plants in which they have entitlements. Some equipment modifications have required and may in the future require shutdowns or deratings of the plants which would not other-wise be necessary, which would result in additional costs for replacement power. The amounts of increased capital expenditures and operating costs, including costs of replacement power, may be substantial but cannot reasonably be estimated at this time.

Modifications of emergency response plan.ung and notification systems for nuclear plants, including those made to date, are expecte'd to result in total expenditures of $9.4 million for the Connecticut Yankee unit (of which the System's share is 44 percent) and $7.5 million for Millstone 1 and 2. In addition, recently proposed NRC supplemental guidelines relating to emergency response facilities could, if adopted, require additional expenditures of up to

$10 million for the Connecticut Yankee unit and up to S20 million for Mill-stone 1 and 2.

The NRC has evaluated nuclear power plant tire protection require-ments and has established regulations on the subject. The System companies joined with five other utilities in requesting judicial review of the validity of those regulations and certain of the specific requirements. A decision rendered by the United States Court of Appeals for the District of Columbia Circuit on March 16, 1982 upheld the validity of the NRC's regulations. The United States Supreme Court has declined to review the Court of Appeals' decision. The System companies have filed with the NRC exemption requests with respect tc certain requirements of the NRC's regulations. The Company esti-mates that the cost of meeting the new fire protection requirements, if all pending exemption requests are granted, will be approximately $20 million for the Connecticut Yankee, Millstone 1 and Millstone 2 plants, together, and, if all exemption requests are denied, approximately $220 million. These estimates assume that the work can be accomplished during normally scheduled refueling outages and therefore do not include any costs associated with replacement power. The NRC's action on pending exemption requests is expected in the first half of 1983.

Following the 1979 Three Mile Island accident, numerous class actions and several individual actions were filed in the U.S. District Court for the Middle District of Pennsylvania and elsewhere, seeking damages as a result of that accident. If the provisions of the Price-Anderson Act are held to apply to the accident, and if total third party damage awards resulting from the accident exceed the private insurance pool coverage of $160 million, then the .

System companies would be required to pay their share of the excess. The System companies' share would be a maximum of $5 million for each of the two

^

operating Millstone units, plus their pro rata share of a maximum of $5 million for each of the other operating nuclear units in which they have an ownership interest. See note 8 to the consolidated financial statements for information

- about the System's insurance arrangements relating to liability, property damage and the cost of replacement power resulting from nuclear incidents.

See " Regulatory and Environmental Requirements and Proceedings -- NRC Nuclear Plant Licensing" for information about licensing matters which affect the System's nuclear units.

Nuclear Fuel i

To the extent indicated below, there are outstanding contracts for i uranium concentrates and conversion, enrichment and fabrication for the System's existing and planned units, and the othe'r units in which System companies are participating, which cover the units' requirements through the following years:

Uranium Conversion to Concentrates Hexafluoride Enrichment Fabrication Connecticut Yankee 1986 1986 1995 1986

• Maine Yankee 1987 1995 2002 1991  ;

• Vermont Yankee 1990 1995 2001 1984 i

• Yankee Atomic 1983 1995 2001 1993 I

• Seabrook Unit No. 1 1984 1987 2009 1990

• Seabrook Unit No. 2 1984 1987 2011 1990 Millstone 1 1987 1988 2001 1992 Millstone 2 1986 1987 2001 1987 Millstone 3 1990 1988 2014 1993

• 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 periods not covered by existing contracts will be available, although their availability might require that suppliers develop additional capacity.

Waste Disposal and Decommissioning Costs associated with nuclear plant operations include amounts for disposal of naclear wastes, including spent fuel, and for the ultimate decom-missioning of the plants. The System companies reflect in their nuclear fuel expense the spent fuel disposal costs estimated by the U.S. Department of

, Energy (bOE). This provision for spent fuel disposal has been accepted by the 1

DPUC and the DPU in rate case or fuel adjustment decisions and is reflected in the wholesale fuel adjustment charges. Such provisions, which reflect in- ,

creases over previous levels, also include amortization and recovery in rates, over a ten-year period, of previously unrecovered estimated disposal costs of accumulated spent nuclear fuel. .

On January 7, 1983 the President of the United States signed into law the Nuclear Waste Policy Act of 1982. Under this Act the Federal govern-ment is required to design, license, construct and operate a permanent repos-itory for high level radioactive wastes and spent nuclear fuel. The Federal government will also establish a fee to be paid to the government by electric utilities owning or operating nuclear generating units. The fee has been initially set at 1.0 mil per kilowatthour for nuclear generation after April 7, 1983. The fee for previously burned fuel will be at a comparable rate for the electric utility industry as whole, but the charge for each utility has not yet been definitely determined. In return for the fee, the Federal government, beginning not later than January 31, 1998, will take title to and dispose of the utilities' high level wastes and spent nuclear fuel. Under the Act the NRC may not renew a license for any person to use a production facility unless that person, by June 30, 1983, enters into a contract with the Federal government for disposal of its high level wastes and spent nuclear fuel.

Until the Federal government begins receiving such materials in accordance with the Nuclear Waste Policy Act, operating nuclear generating plants will need to retain high level wastes and spent fuel on-site or make some other provisions for their storage until that time. The storage facil-ities for Connecticut Yankee and the Millstone units, including facilities currently under construction at Millstone 3, are expected to be adequate until the time when the Act requires a Federal repository facility to be available.

MYAPC and YAEC will require additional storage capacity on site by the mid-1980s; each is examining ways of increasing the density of fuel storage within its present facility. The Company has been advised by VYNPC that it expects that its storage capacity to be adequate until at least 1989; VYNPC's plans for storage beyond that date are not known.

Disposal costs for low level radioactive wastes that result from normal operation of the System's nuclear units have increased significantly in recent years despite reduced volumes of such wastes, and are expected to continue to rise. The cost increases are functions of increased packaging and transportation costs, and higher fees from the disposal facilities. Pursuant to the Low Level Radioactive Waste Policy Act of 1981, the states in which present disposal facilities are located (South Carolina, Nevada and Washington) will be allowed to prohibit shipments of low level wastes from states which have not entered into regional compacts by 1986. There is no assurance that wastes from nuclear units in which System companies have interests can be sent to the present facilities or that new sites will be available and willing to accept low level wastes from such nuclear units by that date.

9 1

If storage or waste repository facilities for spent fuel or low level wastes, or both, are not available when required, the System nay incur substan-tial additional costs in developing alternate arrangements.

• The System companies estimate decommissioning costs for their nuclear units on the basis of immediate and complete dismantlement of those units at their retirement. The estimated decommissioning costs on this basis for Millstone 1 and 2 and Connecticut Yankee are in the range of $80 to $100 mil-lion per unit, in current dollars. These estimates are reviewed and updated regularly to reflect inflation and changes in decommissioning requirements and technology. Changes in requirements or technology, or adoption of a decommis-sioning method other than immediate dismantlement, could increase these esti-mates further. CL&P and WMECO attempt to recover sufficient amounts through their allowed revenues to cover their expected decommissioning costs. Although allowances for decommissioning have increased significantly in recent years, full rate recovery of the projected costs of decommissioning will require

, ratepayers in future years to increase their payments in order to offset the effects of insufficient rate recoveries in previous years. Only the portion of presently estimated total decommissioning costs that has been accepted by regulatory agencies is reflected in the financial statements of the Company.

VYAPC is not currently collecting funds for decommissioning from its sponsors but is proposing to start such collections in 1983. YAEC, MYAPC and CYAPC have been collecting revenues for decommissioning, and each has increased the amount of their collections in 1982. The Company expects that all Yankee companies will be increasing their decommissioning charges in future years.

GAS OPERATIONS -

CL&P furnishes retail gas service in eleven separate service areas, not fully interconnected, that cover approximately 1,321 square miles in 51 cities and towns in Connecticut with an estimated population of 1.22 million.

About 13 percent of the System's consolidated operating revenues for 1982 came from gas operations. Gas revenues in 1982 were derived 42 percent from resi-dential customers, 26 percent from commercial customers, 31 percent from industrial customers and the balance from others. The components of gas revenues were not materfally different in 1981.

Pipeline gas provided 93.1 percent of CL&P's 1982 requirements.

Liquified natural gas (LNG) provided 4.8 percent and propane provided the remainder. System gas requirements for 1983 are expected to be met approxi-mately 92.8 percent by pipeline gas, 4.1 percent by LNG and the balance by propane. Pipeline gas is purchased under long-terr contracts with Algonquin Cas Transmission Company (approximately 60 percent) and Tennessee Gas Pipeline

, Company (approximately 40 percent) at rates subject to the jurisdiction of the FERC.

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The System's gas supplies have been adequate in recent years, and did not require any service interruptions, even during the unusually cold periods ,

in January, 1982. Through March 1, 1983, the System's peak day sendout was on January 18, 1982, when CL&P distributed 206,783 million British thermal units of gas. CL&P anticipates that gas supplies will be adequate through at least

• the 1986-87 heating season.

Suppliers of pipeline gas have periodically obtained rate increases for their gas deliveries and have additional requests for rate increases pending before the FERC. Increases in purchased gas costs are by far the most significant factors in increased operating costs for gas service. CL&P has an adjustment clause in its retail gas rate schedules under which billings to customers reflect changed gas costs.

The price of most natural gas produced in the United States is controlled pursuant to the Natural Gas Policy Act of 1978. The price controls are to expire under that Act with respect to an estimated 60 percent of domes-tically produced gas on January 1, 1985. Proposed changes to the Act to accelerate or defer further the effective date of the end of price controls, and to expand or restrict the nature of gas production subject to price con-trols, are being actively advocated by industry groups, consumer groups and others with substantial but often conflicting interests in the matter. The ultimate resolution of the price control issue is expected to have substantial implications for the price and supply of natural gas, but the effects cannot be known at present.

CL&P is undertaking a long-term program of improving its gas dis-tribution system. It installed 22,000 linear feet of gas main in Stamford, Connecticut, in-1982 as part of an extensive distribution rehabilitation program in that city. Approximately 20,000 linear feet of main were replaced in the towns of Shelton, Derby, Ansonia and Monroe, Connecticut. In addition, two separate service areas (Waterbury and Shelton) were connected in late 1981 to increase the system's reliability by allowing for exchange of gas purchased from two different gas pipeline companies.

CL&P, along with thirteen other gas companies in New England, New

• York, and New Jersey, has made arrangements to receive a ten-year supply of natural gas from TransCanada Pipelines Limited (TransCanada), a Canadian corporation. To facilitate their dealings with TransCanada, the participants have organized Boundary Gas, Inc. to purchase gas from TransCanada and to resell gas to the participants. CL&P has a 5.11 percent stock ownership .

interest in Boundary Gas, which entitles and obligates it to purchase a propor-tionate share of the natural gas that Boundary Gas is expected to purchase from TransCanada.

For TransCanada to deliver gas to the United States it must construct major pipeline facilities to connect with United States facilities in upper New York State. In addition to the pipeline facilities to be built by TransCanada, additional transportation facilities within the United States are necessary. -)

Some facilities are needed to connect TransCanada's facilities with those of 1

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Tennessee Gas Pipeline Company at the United States-Canadian border near Niagara Falls, New York. Other facilities are needed to augment the capacity of existing Tennessee facilities through which gas is transported to gas dis-tribution companies in the northeastern United States. All such facilities are

• expected to be completed in late 1984 if timely regulatory approvals are received and if Tennessee Gas Pipeline Company is able to arrange suitable financing for the projects.

The TransCanada arrangements require approval of Canada's National Energy Board, which began hearings in March, 1982. On January 27, 1983 the Canadian National Energy Board approved the sale of about 92 million cubic feet of gas per day for all Boundary Gas participants, of which CL&P's share would be about 4.8 million cubic feet per day. This is about half the amount requested and would represent about five percent of CL&P's total gas supplies during 1985, the anticipated first full year of purchases. The FERC and the Economic Regulatory Administration (ERA) of the DOE must also approve the project. In August, 1982 the ERA issued an order conditionally authorizing Boundary Gas' importation of gas from Canada. Hearings on the FERC application began in December, 1982; a decision is expected by the fall of 1983. Receipt of all necessary approvals for the Boundary Gas project is therefore not assured.

After a sale agreement under which CL&P would have sold its gas properties to another utility terminated in 1979, CL&P undertook studies to determine whether to retain or dispose of its gas properties. It has concluded that the gas properties should be retained. The SEC has opposed retention of both gas and electric properties by companies subject to the Public Utility Holding Company Act of 1935. See " Regulatory and Environmental Pequirements and Proceedings -- Public Utility Regulation" for information about possible amendment or repeal of that law.

REGULATORY AND ENVIRONMENTAL REQUIREMENTS AND PROCEEDINGS i

Public Utility Regulation i The Company is registered with the SEC as a holding company under the i

Public Utility Holding Company Act of 1935 (the 1935 Act). Under the 1935 Act, the SEC has jurisdiction over the Company and its subsidiaries with respect to, among other things, securities issues, sales and acquisitions of securities and l

utility assets, intercompany loans, services performed by and for associated

' companies, accounts and records, involvement in non-utility operations, and

dividends. The 1935 Act has been the subject of proposed legislation that would repeal or substantially modify the law. Whether the 1935 Act will be

( repealed or substantially amended, and whether $egulation of the System com-

, panies would be materially reduced or modified. is not known.

CL&P is subject to regulation by the DPUC, which has jurisdiction, among other things, over retail rates, accounting procedures, certain I

L

T dispositions of property and plant, mergers and consolidations, securities issues, standards of service, management efficiency, and construction and operation of generation, transmission and distribution facilities. WMECO is I also subject to the jurisdiction of the DPUC with respect to its activities in Connecticut and securities issues.

WMECO is subject to regulation by the DPU, which has jurisdiction over retail rates, accounting procedures, quality of service, contracts for the purchase of electricity, mergers, securities issues and other matters. HWP is subject to regulation by the DPU with respect to certain contracts and quality of service. The. Company and its subsidiaries are subject to the general super-vision of the DPU with respect to all dealings with WMECO and HWP.

6 CL&P is subject to the jurisdiction of the NHPUC for limited purposes in connection with its ownership interest in the Seabrook units.

"L&P, WMECO and HWP are public utilities under Part II of the Federal Power Act and are subject to regulation by the FERC with respect to, among other things, interconnection and coordination of facilities, wholesale rates and accounting procedures.

The System incurs substantial capital expenditures and operating expenses to comply with environmental, energy, licensing and other regulatory requirements, including those described in the following subsections, and it expects to incur additional costs to meet furtaer developments in these and other areas of regulation. Because of the continually changing nature of regulatione affecting the System, the total amount of these costs is not now determinable. Compliance with existing and proposed regulations also affects the time needed to ccmplete new facilities or to modify present facilities, and it affects System companies' rates, sales, revenues and net income, all in ways that may be substantial but are not readily calculable.

Environmental Impact Requirements The National Environmental Policy Act of 1969 (NEPA) requires that detailed statements of the environmental effects of major federal actions be prepared by federal agencies. Major federal actions can include licenses or permits issued to the System by the FERC, the NRC and other federal agencies for construction or operation of generation and transmission facilities. NEPA requires that federal licensing agencies make an independent environmental evaluation of the proposed action.

Massachusetts law requires all state agencies to determine the environmental impact of any construction proposed by private companies requir-ing state permits, funding or participation. Massachusetts state agencies are required to make "a finding that all feasible measures have been taken to avoid or minimize impact" of such construction. In certain instances Massachusetts law also requires the preparation and dissemination among various state agencies of environmental impact reports pertaining to the proposed con- .

struction.

J NRC Nuclear Plant Licensing e, .

Millstone 2 and the Yankee Atomic, Connecticut Yankee, Maine Yankee and Vermont Yankee units have full term (typically 40 years from the date a con-

' struction permit is issued for the unit) full power operating licenses. An application for a full term full power operating license for Millstone 1, which is operating under a provisional license, is pending before the NRC. A con-struction permit for Millstone 3 was issued by the NRC in August 1974 and expires December 30, 1985. An application for a full term full power operating license for Millstone 3 was filed with the NRC on October 29, 1982. It is expected that an operating license will be obtained or that the construction permit will be extended before the current expiration date.

4 NRC construction permits for Seabrook Units 1 and 2 were issued in

1976. An application for an operating license for the Seabrook plant was I docketed by the NRC in October, 1981. It is expected that evidentiary hearings on the operating license application, which will be contested, will not com-mence before the Spring of 1983. The construction and licensing of these units has been subjected to lengthy delays associated with administrative proceed-

! ings, numerous lawsuits, financial constraints, work stoppages and demon-strations at the construction site. See " Construction and Financing Program --

l Construction -- Seabrook" for further information about Seabrook.

In April, 1982, the U.S. Court of Appeals for the District of Columbia Circuit invalidated the NRC's generic rule on the environmental effects of the uranium fuel cycle in tl.e case of Natural Resources Defense Council v. NRC. This rule has been used by the NRC since 1974 in connection with the licensing of nuclear power plants in order to comply with the require-ments of NEPA. The U.S. Supreme Court has agreed to review this case; it is l'

expected that oral arguments will be heard in April, 1983. Although the decision has not yet become effective, it raises questions with respect to many construction permits and operating licenses issued by the NRC, including permits and licenses for plants in which the System companies have an interest.

l The time required to construct major generating facilities and to obtain required licenses and regulatory approvals compels electric utilities

(including System companies) to make substantial investments in facilities before final licenses and approvals are received. Completion of each of the three nuclear generating units now under construction in which the System companies are participating depends, among other things, on obtaining necessary j regulatory approvals, permits and sufficient financing. If any of the units i were canceled due to future developments, System companies would apply to appropriate regulatory authorities for approval to amortize their shares of I total costs over a future period and to recover the costs through their rates.

I Although they have been allowed to amortize and recover through rates part of the costs of previously cancelled nuclear units, the System companies cannot predict whether and to what extent such recovery would be permitted.

The effect of the licensing matters described in this section on operating nuclear units and on units under construction cannot accurately be l

a s

r a

predicted. In some circumstances, they could require modifications, reductions in authorized power levels or shutdowns of operating units. They could also require modification of units under construction, or they could delay or [,

prevent their construction. Any of these effects could have a substantial adverse effect on the System companies.

Water Quality Requirements The federal Clean Water Act-(CWA) provides that every " point source" discharger of pollutants into navigable waters must obtain a National Pollutant Discharge Elimination System (NPDES) permit specifying the allowable quantity and characteristics of its effluent. To obtain an NPDES permit, a discharger must meet technology-based effluent standards and must also demonstrate that its effluent will not cause a violation of established standards for the quality of the receiving waters.

The initial NPDES permits for System thermal generating plants expired in 1979. New permits were issued for System plants in Massachusetts in January, 1980 but expired October 1, 1980. Pending receipt of a new permit, for which an application has been submitted, WMECO's West Springfield station is being operated in accordance with the expired permit. A permit was issued in December, 1981 for HWP's Mt. Tom Station, in connection with its conversion to coal burning. New permits have been obtained for System plants in Connect-icut. These permits will expire in January, 1985, except for the permit for the Millstone units, which expires in July, 1985. The permits may be reopened to reflect more stringent requirements proposed by the EPA. Compliance with NPDES requirements has necessitated substantial expenditures and may require further expenditures in the future.

The applicability of NPDES permit requirements to hydroelectric facilities is unresolved and is the subject of litigation in which the System companies have intervened. The United States Court of Appeals for the District of Columbia Circuit has ruled in the case of National Wildlife Federation v.

Corsuch that the EPA has authority to determine that dams do not require NPDES permits. System companies have not obtained NPDES permits for their hydroelec-tric facilities.

The CWA requires the DEP in Connecticut and the EPA and the Depart-ment of Environmental Quality Engineering (DEQE) in Massachusetts to approve the intake structure design and thermal discharge of generating plants. All

, System plants have received these approvals.

I On November 19, 1982 the EPA published its final effluent guidelines f

for the steam electric generating industry. The major impact on System gen-erating units is expected to be from more stringent controls on the discharge l of chlorine. Augmented chemical waste treatment facilities for the System's generating plants may be required to comply with the guidelines.

t.

The CWA's ultimate cost impact on the System cannot be estimated

• because of uncertainties such as the impact of the newly promulgated effluent 4

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1 guidelines. Additional modifications, in some cases extensive and involving substantial cost, may ultimately be required for one or more of the System's generating facilities.

• Air Quality Requirements Under the federal Clean Air Act, the EPA has promulgated national ambient air quality standards for certain air pollutants, including sulfur oxides, particulate matter and nitrogen oxides. With some exceptions, the EPA has approved a Connecticut implementation plan proposed by the DEP, and a Massachusetts plan proposed by the DEQE, for the achievement, maintenance and enforcement of these standards.

In November 1981 the DEP revised its air quality regulations. The regulations now permit CL&P to burn 1.0 percent sulfur oil at all but one of its oil-fired generating stations in Connecticut. CL&P must continue to burn 0.5 percent sulfur oil at its Middletown Station. The revised regulations could also permit the burning of coal with a sulfur content of up to 0.7 percent at CL&P's plants, or up to 1.0 percent if a discretionary permit were obtained; however, see " Construction and Financing Program -- Construction --

Oil Reduction Efforts" for information about a recent DEP proceeding which could have adverse consequences for coal burning at CL&P's plants.

The Mast 2chusetts air quality regulations permit HWP to burn 1.5 per-cent sulfur coal at Mt. Tom Station. WMECO's West Springfield Station has burned 2.2 percent sulfur oil since 1977 'The results of recent air quality modeling tests indicated that a reduction of the sulfur content in the oil burned at that station would be necessary under certain weather conditions to satisfy air quality requirements in the Springfield area. The units are currently burning 1.0 percent sulfur oil as required by the DEQE while WMECO explores ways of meeting air quality standards with the use of the less expen-sive 2.2 percent sulfur oil.

EPA, Connecticut and Massachusetts regulations also include other air quality standards, emission standards and monitoring, and testing and reporting requirements which apply to the System's generating stations. They require that new or modified fossil fuel-fired electric generating units operate within stringent emission limits, and meet all applicable state and federal air quality standards and regulations. These regulations could hinder or possibly preclude coal conversion projects or the construction of new or modification of other existing fossil units in the System's service area.

Toxic Substances and Hazardous Waste Regulations Under the federal Toxic Substances Control Act of 1976 (TSCA), the EPA has issued regulations which control the use and disposal of polychlorinated biphenyls (PCBs). PCBs had been widely used as insulating

, fluids in many electric utility transformers and capacitors manufactured before TSCA prohibited any further manufacture of such PCB equipment. The System companies have taken numerous stepa to comply with these regulations and have r

incurred increaced costs for disposal of used fluids and equipment that are subject to the regulations, one disposal measure involves the System's burning ,

of some waste oil with a low level of PCB contamination (between 50 and 500 parts per million) as supplemental fuel at CL&P's Middletown Station Unit No. 3. The EPA and DEP have approved this disposal method. In several related legal actions in 1981, the City of Middletown, Connecticut, challenged the System's method of disposing of low level PCB contaminated oil; one such action is currently on appeal before the Connecticut Supreme Court. In response to these local concerns, independent studies were conducted which concluded that there was no evidence that burning this waste oil would present a hazard to human health or.the environment.

Fluids with a concentration of PCBs higher than 500 parts per ril-lion, and materials (such as electrical capacitors) that contain such fluids, must be disposed of through burning in high temperature incinerators approved by the EPA. Three such incinerators owned and operated by unaffiliated compa-nies, located outside the System's service territories, have been approved.

Solid wastes containing PCBs must be disposed of in secured chemical waste landfills.

EPA regulations issued in 1982 require utilities to phase out the use of certain PCB capacitors by 1986. The System expects to incur additional costs in connection with PCB disposal, but costs other than for phasing out

' capacitors are not expected to be material.

Under the federal Resource Conservation and Recovery Act of 1976 (RCRA), the generation, transportation, storage, treatment and disposal of hazardous wastes are subject to EPA regulations. Massachusetts and Connecticut have issued state regulations that parallel RCRA regulativns but are more stringent. The notifications and applications required by the present regula-tions have been made. The procedures by which System companies handle, store, treat and dispose of hazardous waste products have been revised, where neces-sary, to comply with these regulations.

l l

FERC Hydro Project Licensing System operating companies hold licenses granted under Part I of the Federal Power Act for the operation and maintenance of seven existing hydro-electric projects, the Northfield, Turners Falls, Gardners Falls, Hadley Falls, Scotland, Housatonic and Falls Village projects. The FERC has held that no license is required for four other existing projects, the Chicopee River, Taftville, Robertsville and Tunnel projects. A license application for the Derby-Shelton project described under " Construction and Financing Program --

Construction -- Oil Reduction Efforts", is pending before the FERC. The l

licensing of two other projects, involving units which had previously been retired but which have recently been restored and reactivated, is under review.

i Federal Power Act licenses may be issued for terms of fifty years or l less as determined by the FERC. Any hydroelectric project so licensed is .

subject to recapture by the United States or licensing to others, after b

o 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 are customarily conditioned on the licensee's development of recre-

' ational and other nonpower uses at each licensed plant. Conditions may be imposed with respect to low flow augmentation of streams and fish passage facilities.

On December 28, 1982 the FERC ruled that the Holyoke (Mass.) Gas and Plectric Department (the Department) will not be issued a preliminary. permit to study the feasibility of installing additional hydroelectric capacity at the Hadley Falls project on the Connecticut River because HWP has a license to the potential power at the site. In its decision, however, the FERC ordered HWP to study the economic feasibility of installing capacity at the project in addition to the capacity to be provided by the unit described under

" Construction and Financing Program -- Construction -- Oil Reduction Efforts".

The Department has asked the FERC to reconsider its order.

4 SEGMENTS OF BUSINESS l

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Information about the Company's business segments is given in note 9 to the consolidated financial statements, which are included in Appendix A to l

i this report.

4 I EMPLOYEES 4

The officers of the company receive their remuneration from the Service Company or other System companies, not from the Comp'any. The Company has no employees. As of December 31, 1982, the Company's subsidiaries had-

approximately 8,700 regular employees on their payrolls. CL&P, WHECO and HWP have union agreements covering approximately 2,500 employees. All the union agreements expire in 1984.

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- ~ . . _ . ,_ , - , . , _ . . _ _ , _ - . _ _ _ , _ _ _ . . _ . , _ _ _ _ _ . _ _ , _ - _ , , , , . _ _ _ _ _ _ _ _ _ , _ , , _ . . . . _ _ _ . , _ _ - , _ _ _ . . . . . , , _ . _ _ . . . _.,_..__,_.--._.,.._.4_,__.

r-Item 2. Properties The physical properties of the System are owned or leased by sub- '

sidiaries of the Company.

CL&P's properties are subject to the liens of CL&P's first mortgage indentures and with respect to properties formerly owned by HELCO, to -

the lien of HELCO's first mortgage indenture. WMEC0's and HWP's physical properties are subject to the liens of their respective first mortgage indentures. In addition, CL&P's and WMECO's interest in Millstone 3 and Millstone 1 are subject to second liens in favor of the trustee of the Millstone Construction Trust (in the case of Millstone 3) and lenders under term loan agreements (in the case of Millstone 1).

From January 1, 1978 through December 31, 1982, the System companies r.ade gross property additions and betterments to utility plant, excluding nuclear fuel, aggregating $1,565,958,000 and retired or sold properties having an aggregate cost of $201,792,000, resulting in net additions during that period of $1,364,166,000.

Electric Properties As of December 31, 1982, the System operating companies had 50 transmission substations with an aggregate capacity of 17,663,375 kVA and 366 distribution substations with an aggregate capacity of 8,288,757 kVA. Their transmission systems included 450 circuit miles of overhead 345 kV lines, 1,463 circuit miles of overhead 115 kV lines, 40 cable miles of 138 kV submarine cable, 113 cable miles of underground 115 kV cable and 152 circuit miles of 69 kV overhead lines. The distribution systems included 20,677 pole miles of overhead lines and 842 conduit bank miles of underground lines. The System operating companies had in service 233,215 line transformers with an aggregate capacity of 9,818,565 KVA.

As of December 31, 1982, the electric generating plants of the System operating companies and the System companies' entitlements from the generating plants of the four Yankee regional nuclear generating companies were as follows:

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J Total Generatina Plant v . Northeast (a)

Name Plate Claimed Utilities' Year Rating Capability Entitlements Name Owner, Town, Location 1]gte Installed (Kilowatta) (Kilowatts) (Kilowatts)

(Winter Ratings)

System Cenerating Plants Millstone Plant (CL&P & WMECO) Nuclear 1970 661,500 660,000 637,064 (Waterford-Long Island Sound) 1975 909,900 868,500 838,319 1.571,400 1,528,500 1,475.383 Northfield Plant (CL&P & WMECO) Pumped 1972-1973 846,000 1,000,000 988.256 (Northfield and Erving - Connecticut Storage River)

Steam 1954-1973 836,896 833,000 800,745 Middletown Plant (CL&P)

(Middletown - Connecticut River) Cas Turbine 1966 18,594 -

(c) -

(c) (

855.490 833,000 800,745 1 Montville Plant (CL&P) Steau 1954-1971 489,900 492.000 472.949 2 Diesels 1967 5,500 5,500 5.288 (Montville - Thames River) 495,400 497.500 478.237 Stena 1942-1958 429,000 463.000 454,558 Devon Plant (CL&P)

Cas Turbine 1966 16,320 18,700 17,976 (Milford - Housatonic River) 481,700 472,534 445,320 Steam 1960-1963 326,400 338,000 324,913 Norwalk Harbor Plant (CL&P) 16,342 (Norwalk - Long Island Sound) Gas Turbine 1966 16,320 17,000 342,720 355,000 341,255 West Springfield Plant (WMECO) Steam 1949-1957 209,636 211,300 211,300 (West Springfield - Connecticut River) Gas Turbine 1968 18.594 22,000 22,000 228,230 233,300 233,300 4 Cas Turbines 1970 167,400 196,000 196,000 South Meadow Plant (CL&P)

(Hartford - Connecticut River)

Steam 1960 136,000 148,000 92.000 Mt. Tom Plant (HWP)

(Holyoke - Connecticut River)

Hydro 1905-1917 55,520 58,000 58,000 Turners Falls Plant (WMECO)

(Montague - Ccanecticut River) -

Bydro 1955 37,200 47,000 44,255 Shepaus Plant (CL&P)

(Southbury - Housatonic River)

Pumped 1928-1952 31,000 29,000 29,000 Rocky River Plant (CL&P)

(New Milford - Housatonic River) Storage Hydro 1930 33,000 32,500 32,500 Cobble Mountain Plant (WMECO) (b)

(Granville - Westfield Little River) _

8 e

r-a Total Cenerating Plant Northeast (a)

Name Plate Clamied, Utilities' '

Year Rating Capability Entitlements Name, Owner, Town Location Tyge Installed (Kilowatts) (Kilowatts) (Kilowatts)

(Winter Ratings)

Stevenson Plant (CL4P) Hydro 1919-1936 30,500 28,700 28,700 (Monroe - Housatonic River) 18 Small Hydro Plants 66,256 69,100 65,020 9 Cas Turbine Plants 211,908 242,200 242,200 Total System Generating Plants 5,553,344 5,779.500 5.577,385 Regional Nuclear Generating Plants (d)

Connecticut Yankee Atomic Power Company Nuclear 1968 264.132 247,181 247,181 (Haddam, Connecticut)

Maine Yankee Atomic Power Company Nuclear 1972 109,111 207.907 107,907 (Wiseasset, Maine)

Vermont Yankee Nuclear Power Corporation Nuclear 1972 60,796 54,996 54,996 (Vernon Vermont)

Yankee Atomic Electric Company Nuclear 1961 58,275 53,453 53,453 (Rowe, Massachusetts)

Total Regional Nuclear Generating Plants 492,314 463,537 463.537 Total Generating Plants 6.045,658 6,243,037 6,040,922 (a) Northeast Utilities' Entitlements (Kilowatts) ratings are shown net of the following life-of-unit contracts:

- The Connecticut Municipal Electric Energy Cooperative (CKEEC) Agreement under which CMIEC has rights to specific percentages of the total claimed capability of various generating units within the NU system.

- HWP sells approximately 56,000 KW of the capacity (37.8% of the output) of its Mt. Tom plant to the New England Power Company (NEPCO) under a contract that terminates in 1990, unless NEPCO exercises its right to extend the contract for an additional ten years.

(b) The Cobble Mountain plant is leased from the City of Springfield.

(c) Middletown Cas Turbine unit is expected back in service by aid 1983. The unit's vinter capability l st that time is expected to be 22,000 KW with an NU Entitlement of 21.100 KW.

(d) Represents Northeast Utilities' entitlements in the generating plants of the four Yankee regional nuclear generating companies.

b I

e L

t Gas Properties

" As of December 31, 1982, CL&P, the only operating subsidiary of the

' Company supplying retail gas service, had nine propane plants, three permanent LNG plants and leased space in two other large LNG storage

. facilities, nine gas storage holders with a total capacity of approximately 8,197 Mcf, 2,265 miles of gas distribution mains and approximately 6 miles of gas transmission mains. See " Operations - Gas" under " Item 1. Business".

Franchises The Company's operating subsidiaries hol,d numerous franchises in the territories served by them.

CL&P 1

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, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to sell electricity and gas in the respective 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 CL&P include, among others, rights and powers to manufacture, generate, purchase, transmit and distribute electricity and gas, to sell electricity and gas at wholesale to other utility companics and municipalities and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law.

The franchises of CL&P include the power of eminent domain.

NNECO 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, NNECO has a valid franchise free from burdensome restrictions-to sell electricity to utility companies doing an electric business in Connecticut and other states.

In addition to the right to sell electricity as set forth above, the franchise of NNECO includes, among others, rights and powers to manufacture, generate and transmit electricity, and to erect and maintain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law.

4 WMECO WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works e

of Massachusetts or local municipal < authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only, and for extensions of lines in public ,

highways further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities.

In addition, WMEC0 has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority.

• HWP and Holyoke Power and Electric Company (HP&E)

HWP and its vnolly owned subsidiary HP&E are authorized by their charters to conduct their businesses in the territories served by them.

HWP's electric business is subject to the restriction that sales be made by written contract in amounts of not less than 100 horsepower except for municipal customers in the counties of Hampden or Hampshire, Massachusetts and except for customers who occupy property in which HWP has a financial interest, by ownership or purchase money mortgage. HWP also has certain dam and canal and related rights, all subject to such consents and approvals of public authorities and others as may be required by law.

The two companies have locations in the public highways for their trans-mission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and for extensions of lines in public highways further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. The companies have no other utility franchises.

9 Item 3. Legal Proceedings The United States District Court for the District of Connecticut has before it an antitrust action involving two price-squeeze claims brought

• against the Company, CL&P and Northeast Utilities Service Company by three municipal customers of CL&P (Wallingford, East Norwalk and South Norwalk).

The price-squeeze claims were remanded to the District Court in an Octo-ber 13, 1981 decision by the United States Court of Appeals for the Second Circuit. The Court of Appeals denied the remaining antitrust claims of the municipal customers.

On August 24, 1982 WMECO filed an appeal with the Massachusetts Supreme Judicial Court challenging a May 28, 1982 order of the DPU to file an amendment of the System's generation and transmission agreement (the NUG&T) with the FERC and to prepare and file with the DPU a report on alternative allocation methodologies for the NUG&T. The NUG&T is the contract among the system companies that provides the basis for planning their bulk power supply system on a one-system basis. A decision by the Court with respect to the DPU's jurisdiction is not expected until late 1983.

4 Although the appeal of the DPU decision is still being pursued, WMECO filed the ordered allocation study with the DPU on October 15, 1982 and filed an amendment of the NUG&T with the FERC on November 9, 1982. The FERC amendment proposes, as ordered by the DPU, a change in the return on common equity portion of the NUG&T. In the FERC filing, WMECO preserved its arguments that the DPU does not have jurisdiction over the NUG&T.

While the proposed amendment of the NUG&T may, if approved by the FERC, shift expenses among the operating companies, there would be no revenue change for the System as a whole. Whether a shift of expenses between companies would affect decisions on a state regulatory level in the future is presently unknown.

The following sections of " Item 1. Business" discuss additional legal proceedings: " Construction and Financing Program -- Construction --

Seabrook" for information about proceedings relating to the Seabrook nuclear electric generating units in which CL&P has an ownership interest; " Rates" for information about rato and fuel adjustment clause proceedings;

" Regulatory and Environmental Requirements and Proceedings" for information about litigation over NRC licensing regulation, litigation over the System's plans for PCB disposal, and litigation over NPDES permit requirements, and

" Electric Operations -- Nuclear Generation -- Operations" for information about possible contingent liabilities of CL&P and WMECO for damages resulting from the TMI accident and litigation concerning NRC fire protection regulations.

s l

Item 4. Submission of Matters to a Vote of Security Holders (Fourth Quarter 1982)

NONE PART II

• Item 5. Market for the Registrant's Common Stock and Related Shareholder Matters The Company declared and paid quarterly dividends of $0.295 in 1981 and $0.32 in 1982. On January 25, 1983, the Board of Trustees declared a dividend of $0.345 per share, payable on March 31, 1983 to holders of record on March 1, 1983. The declaration of future dividends may vary dep.nding on capital requirements and income as well as financial and other conditions existing at the time.

Information with respect to dividend restrictions is contained in Note (b) of the " Notes to the Consolidated Statements of Capitalization" on page 37 and additional information with respect to common shares is contained under the caption " Common Share Information" on page 54 of the Company's Annual Report to Shareholders, portions of which are attached to this report as Appendix A.

Item 6. Selected Consolidated Financial Date This information is contained on page 50 of the Company's Annual Report to Shareholders, portions of which are attached to this report as Appendix A.

Iten 7. Management's Discussion and Analysis of Financial., Condition and Results of Operations This information is contained on pages 15 through 25 of the Company's Annual Report to Shareholders, pcrtions of which are attached to this report as Appendix A.

O Item 8. Financial Statements and Supplementary Data The following consolidated financial statements of the Company and its subsidiaries are included on pages 30 through 49 and page 54 in the Company's Annual Report to Shareholders, portions of which are attached 18 to this report as Appendix A.

Company Report Auditors' Report Consolidated Statements of Income for the years ended December 31, 1982, 1981 and 1980 Consolidated Statements of Sources of Funds for Gross Property Additions for the years ended December 31, 1982, 1981 and 1980 Consolidated Balance Sheets at December 31, 1982 and 1981 Consolidated Statements of Capitalization at December 31, 1982 and 1981 Consolidnred Statements of Common Shareholders' Equity for the years ended December 31, 1982, 1981 and 1980 Notes to Consolidated Financial Statements Consolidated Statements of Quarterly Financial Data Item 9. Disagreements on Accounting and Financial Disclosure NONE PART III Item 10. Directors and Executive Officers of the Registrant Incorporated herein by reference is the definitive proxy statement for solicitation of proxies by the Company's Board of Trustees, which will be dated March 26, 1983 and filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934 (the Act).

Item 11. Management Remuneration and Transactions 4 Incorporated herein by reference is the definitive proxy statement l for solicitation of proxies by the Company's Board of Trustees, which will be dated March 26, 1983 and filed with the Commission pursuant to g Rule 14a-6 under the Act.

i 1

1 t

Item 12. Security dwnership of Certain Beneficial Owners and Management Incorporated herein by reference is the definitive proxy statement for solicitation of proxies by the Company's Board of Trustees, which will be dated March 26, 1983 and filed with the Commission pursuant to Rule 14a-6 under the Act.

w Item 13. Certain Relationships and Related Transactions Incorporated herein by reference is the definitive proxy statement for solicitation of proxies by the Company's Board of Trustees, which will be dated March 26, 1983 and filed with the Commission pursuant to Rule 14a-6 under the Act.

PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Forn 8-K (a) 1. Financial Statements:

The Auditors' Report and consolidated financial statements of the Company and its subsidiaries included in the Annual Report to Shareholders are listed in Item 8.

The following additional financial information is filed herewith:

Report of Independent Public Accountants on Schedules Consent of Independent Public Accountants

2. Schedules:

V. Utility Plant (including Intangibles and excluding Nuclear Fuel), Consolidated - years ended December 31, 1982, 1981 and 1980 V. Nuclear Fuel, Consolidated - years ended December 31, 1982, 1981 and 1980 VI. Accumulated Provision for Depreciation of Utility Plant, Consolidated - years ended December 31, 1982, 1981 and 1980 VIII. Reserves, Consolidated - years ended December 31, 1982, 1981 and 1980 IX. Short-Term Borrowings, Consolidated - years ended December 31, 1982, 1981 and 1980 X. Supplementary Income Statement Information - years ,

ended December 31, 1982, 1981 and 1980 All other schedules of the Company for which provision is made in '

the applicable regulations of the Securities and Exchange Commission are not required under the related instructions or are not applicable, and therefore have been omitted.

EXHIBITS Each document described below is incorporated by reference to the files of the Securities and Exchange Commission, unless the reference to the document is indicated by an asterisk.

Exhibit Number Description 2 Certificate of Merger 2.1 Certificate of Merger dated June 30, 1982 setting forth the plan of merger between CL&P and HELCO. (Exhibit 2.1, September 30, 1982 Form 10-Q File No. 1-5324) 2.2 Certificate of Merger dated June 30, 1982, setting forth the plan of merger between CL&P and Conn, Gas. (Exhibit 2.2, September 30, 1982 Form 10-Q, File No. 1-5324) 3 Declaration of Trust 3.1 Declaration of Trust of Northeast Utilities as amended through April 25, 1978. (Exhibit 3.1, File No. 2-72538) 4 Instruments defining the rights of security holders, including indentures 4.1 Northeast Utilities 4.1.1 Loan Agreement dated as of June 1, 1976 between Northeast Utilities and the Equitable Life Assurance Society of the United States. (Exhibit 4.1, File No. 2-72538) 4.2 The Connecticut Light and Power Company 4.2.1 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, Trustee, dated as of May 1, 1921. (Exhibit B-2, File No. 2-2477) 4.2.2 Collateral Indenture and Supplemental Indenture thereto, dated as of May 1, 1921. (Exhibits B-3 and B-4, File No. 2-2477) 4.2.3 September 1, 1936. (Exhibit B-12, File No. 2-2477) 4.2.4 October 20, 1936. (Exhibit B-13, File No. 2-2477)

O 4

4.2.5 August 31, 1944. (Exhibit B-18, File No. 2-5460) 4.2.6 September 1, 1944. (Exhibit B-19, File No. 2-5460) ,

4.2.7 May 1, 1945. (Exhibit B-20, File No. 2-5907) 4.2.8 October 1, 1945. (Exhibit B-21, File No. 2-5907) 4.2.9 November 1, 1949. (Exhibit B-22, File No. 2-8171) 4.2.10 December 1, 1952. (Exhibit B-23, File No. 2-10949) 4.2.11 December 1, 1955. (Exhibit B-24, File No. 2-13032) 4.2.12 January 1, 1958. (Exhibit B-25, File No. 2-14688) 4.2.13 February 1, 1960. (Exhibit B-26, File No. 2-16004) 4.2.14 April 1, 1961. (Exhibit 4.14, File No. 2-60806) 4.2.15 September 1, 1963. (Exhibit 4.15, File No. 2-60806) 4.2.16 April 1, 1967 (Exhibit 4.16, File No. 2-60806) 4.2.17 May 1, 1967. (Exhibit 4.17, File No. 2-60806) 4.2.18 January 1, 1968. (Exhibit 4.18, File No. 2-60806) 4.2.19 October 1, 1968. (Exhibit 4.19, File No. 2-60806) 4.2.20 December 1, 1969. (Exhibit 4.20, File No. 2-60806) 4.2.21 January 1, 1970. (Exhibit 4.21, File No. 2-60806) 4.2.22 October 1, 1970. (Exhibit 4.22, File No. 2-60806) 4.2.23 December 1, 1971. (Exhibit 4.23, File No. 2-60806) 4.2.24 August 1, 1972. (Exhibit 4.24, File No. 2-60806) 4.2.25 April 1, 1973. (Exhibit 4.25, File No. 2-60806) 4.2.26 March 1, 1974. (Exhibit 4.26, File No. 2-60806) 4.2.27 February 1, 1975. (Exhibit 4.27, File No. 2-60806) 4.2.28 September 1, 1975. (Exhibit 4.28, File No. 2-60806) 4.2.29 May 1,19 77 (Exhibit 4.29, File No. 2-60806) r 9

4.2.30 March 1, 1978 (Exhibit 2.30, File No. 2-68807) 4.2.31 September 1, 1980. (Exhibit 4.31, File No. 2-73795) 4.2.32 October 1, 1981. (Exhibit 4.32, File No. 2-79235) 4.2.33 June 30, 1982. (Exhibit 4.33, File No. 2-79235) 4.2.34 October 1, 1982. (Exhibit 4, September 30, 1982, Form 10-Q, File No. 1-5324) 4.3 The Hartford Electric Light Company 4.3.1 Trust Indenture dated as of July 1,1947 between HELCO and Old Colony Trust Company, Trustee.

(Exhibit B-1, File No. 2-8085)

Supplemental Indentures thereto dated as of:

4.3.2 March 15, 1952. (Exhibit B-4, File No. 2-10496) 4.3.3 September 1, 1952. (Exhibit B-5, File No. 2-10496) 4.3.4 April 2, 1956. (Exhibit C-4, File No. 2-13660) 4.3.5 July 1, 1957. (Exhibit C- 5, File No. 2-13660) 4.3.6 January 1, 1958. (Exhibit B-3-a, File No. 2-14429) 4.3.7 October 1, 1958. (Exhibit A-3-a, File No. 2-21154) 4.3.8 October 1, 1959. (Exhibit A-3-b, File No. 2-21154) 4.3.9 April 1, 1963. (Exhibit 3.9, File No. 2-6G876) 4.3.10 December 1, 1964. (Exhibit 3.10, File No. 2-60876) 4.3.11 February 1, 1967. (Exhibit 4.19, File No. 2-26021) 4.3.12 FirsL Mortgage Indenture and Deed of Trust dated as of January 1, 1958 between HELCO and Old Colony Trust Company, Trustee. (Exhibit B-4, File No. 2-14429)

Supplemental Indentures thereto dated as of:

4.3.13 October 1, 1958. (Exhibit A-4-a, File No. 2-21154)

. 4.3.14 April 1, 1963. (Exhibit 3.14, File No. 2-60876) s l

4.3.15 December 1, 1964. (Exhibit 3.15, File No. 2-60876)

I (Exhibit 4.24, File No. 2-26021) 4.3.16 February-1, 1967. ,

4.3.17 April 1, 1967. (Exhibit 3.17, File No. 2-60876)

, 4.3.18 February 1, 1968. (Exhibit 3.18, File No. 2-60876) l 4.3.19 November 1, 1968. (Exhibit 3.19, File No. 2-60876) 4.3.20 December 1, 1969. (Exhibit 3.20, File No. 2-60876) j 4.3.21 May 1, 1970. (Exhibit 3.21, File No. 2-60876) 4.3.22 December 1, 1971. (Exhibit 3.22, File No. 2-60876) 4.3.23 June 1, 1972. (Exhibit 3.23, File No. 2-60876) 4.3.24 May 1, 1973. (Exhibit 3.24, File No. 2-60876) i 4.3.25 April 1, 1974. (Exhibit 3.25, File No. 2-60876) t 4.3.26 January 1, 1975. (Exhibit 3.26, File No. 2-60876) 4.3.27 October 1, 1975. (Exhibit 3.27, File No. 2-60876) 4.3.28 April 1, 1978. (Exhibit 3.3.28, 1980 Form 10-K, File No. 1-5324) 4.3.29 March 1, 1980. (Exhibit 3.3.29, 1980 Form 10-K, File No. 1-5324)

4.3.30 December 1, 1981. (Exhibit 3.3.30, 1981 Forn 10-K File No. 1-5324)

• 4.3.31 May 1, 1982.

• 4.3.32 June 30, 1982 (Twentieth and Twenty-first

Supplemental Indentures) 4 4.4 Western Massachusetts Electric Company

^

! 4.4.1 First Mortgage Indenture and Deed of Trust between WMECO and Old Colony Trust Company, Trustee, dated 4

as of August 1,1954. (Exhibit 4(b) , File I

No. 2-11114)

Supplemental Indentures dated as of:

i,*

- --,-w, .r-- r-- rw, ,,,---,m------cr-er--er----,r.-."rw-- **+ ---- v -e----eee. -~w- -

---+----,a w--~~+- ' ' ' - -w -'+ "'

4.4.2 October 1, 1954. (Exhibit 4(b) 1.2, File No. 2-11114) o 4.4.3 April 1, 1957. (Exhibit 2.7, File No. 2-13136)

~~ 4.4.4 May 1, 1962. (Exhibit 2.8, File No. 2-20196) 4.4.5 March 1, 1967. (Exhibit 2.5, File No. 2-68808) 4.4.6 March 1, 1968. (Exhibit 2.6, File No. 2-68808) 4.4.7 December 1, 1968. (Exhibit 2.7, File No. 2-68808) 4.4.8 June 1, 1970. (Exhibit 2.8, File No. 2-63808) 4.4.9 July 1, 1972. (Exhibit 2.9, File No. 2-68808) 4.4.10 July 1, 1973. (Exhibit 2.10, File No. 2-68808) 4.4.11 April 1, 1974. (Exhibit 2.11, File No, 2-68808) 4.4.12 January 1,1975. '(Exhibit 2.12, File No. 2-68808) 4.4.13 November 1, 1976. (Exhibit 2.13, File No. 2-68808) 4.4.14 September 1, 1980. (Exhibit 4.14, File No. 2-71694) 4.4.15 May 1, 1981. (Exhibit 3.3.30, 1981 Form 10-K File No. 1-5324) 4.5 Holyoke Water Power Company--First Mortgage Indenture and Deed of Trust between ifWP and Old Colony Trust Company, Trustee, dated as of June 1, 1958. (Exhibit 3.5, 1980 Form 10-K, File No. 1-5324) 10 Material Contracts 10.1 stockholder Agreement dated as of July 1, 1964 among the stockholders of Connecticut Yankee Atomic Power Company.

(Exhibit 13.1, File No. 2-22958) 10.2 Power Contract dated as of July 1, 1964 between Connecti-cut Yankee Atomic Power Company and CL&P, HELCO and '

WMECO. (Exhibit 13.2, File No. ?-22958) 10.2.1 Form of supplementary Power Contract dated as of March 1, 1978 between Connecticut Yankee Atomic Power Company and each of CL&P, HELCO and WMECO. (Exhibit 10.2.1, 1980

. Form 10-K, File No. 1-5324) 10.2.2 Form of amendment to Supplementary Power Contract dated as of August 1, 1980 between Connecticut Yankee Atomic Power Company and each of CL&P, HELCO and WMECO. ,

(Exhibit 10.2. 2, 1980 Form 10-K, File No. 1-5324) 10.3 Capital Funas Agreement dated as of September 1, 1964 between Connecticut Yankee Atomic Power Company and CL&P,

• HELCO and WMECO. (Exhibit 13.3, File No. 2-22958) 10.3.1 Five Year Capital Contribution Agreement dated as Novem-ber 1, 1980 among the stockholders of Connecticut Yankee Atomic Power Company. (Exhibit 10.3.l', 1980 Form 10-K, File No. 1-5224) 10.4 Stockholder Agreement dated December 10, 1958 between Yankee Atomic Electric Company and CL&P, HELCO and WMECO.

(Exhibit 10.4, 1980 Form 10-K, File No. 1-5324) 10.5 Power Contract as amended through April 30, 1975 between Yankee Atomic Electric Company and CL&P, HELCO and WMFCO.

(Exhibit 5.8, File No. 2-57327) 10.6 Millstone Plant Agreement dated as of June 30, 1966 among CL&P, HELCO, WMECO and The Millstone Point Company.

(Exhibit 13.6, File No. 2-26021) 10.6.1 Supplement to Millstone Plant Agreement dated as of December 1, 1967 by and among CL&P, HELCO, WMECO and The Millstone Point Company. (Exhibit 7.10, File No.

2-60806) 10.6.2 Supplement to Millstone Plant Agreement dated as of December 1, 1972 by and emong CL&P, HELCO, WMECO and The Millstone Point Company. (Exhibit 7.11, File No. 2-60806) 10.7 Capital Funds Agreement dated as of May 20, 1968 between Maine Yankee Atomic Power Company and CL&P, HELCO and WMECO. (Exhibit 4.13, File No. 2-30018) 10.8 Power Contract dated as of May 20, 1968 between Maine Yankee Atomic Power Company and CL&P, HELCO and WMECO.

(Exhibit 4.14, File No. 2-30018) 10.9 Stockholder Agreement dated as of May 20, 1968 among stockholders of Maine Yankee Atomic Power Company.

l (Exhibit 4.15, File No. 2-30018) 0 E

10.10 Capital Funds Agreement dated as of February 1, 1968 between Vermont Yankee Nuclear Power Corporation and CL&P, HELCO and WMECO. (Exhibit 4.16, File No. 2-30018) 10.10.1 Amendment to Capital Funds Agreement dated as of

- March 12, 1968 between Vermont Yankee Nuclear Pcwer Corporation and CL&P, HELCO and WMECO. (Exhibit 4.17, File No. 2-30018) 10.11 Power Contract dated as of February 1, 1968 between Vermont Yankee Nuclear Power Corporation and CL&P,llELCO and WMECO. (Exhibit 4.18, File No. 2-30018) 10.11.1 Amendnent to Power Contract dated as of June 1,1972 between Vermont Yankee Nuclear Power Corporation and CL&P, HELCO and WMECO. (Exhibit 5.22, File No. 2-47038) 10.12 Sponsor Agreement dated as of July 1,1968 among the sponsors of Vermont Yankee Nuclear Power Corporation.

(Exhibit 4.16, File No. 2-30285) 10.13 Form of Service Contract dated as of July 1, 1966 between each affiliated company of the System and the Service Company. (Exhibit 10.15, 1980 Form 10-K, File No. 1-5324) 10.13.1 Form of Renewal of Service Contract dated as of January 1 in each year. (Exhibit 10.15.1, 1980 Form 10-K, File No. 1-5324) 10.14 Agreement for joint ownership, construction and operation of New Hampshire nuclear generating units dated as of May 1, 1973. (Exhibit 13-57, File No. 2-48966) 10.14.1 Amendments to Exhibit 10.14 dated May 24, 1974, June 21, 1974 and September 25, 1974. (Exhibit 5.15, File No.

2-51999)

I 10.14.2 Amendments to Exhibit 10.14 dated October 25, 1974 and January 31, 1975. (Exhibit 5.23, File No. 2-54646) 10.14.3 Sixth Amendment to Exhibit 10.14 dated as of April 18, 1979. (Exhibit 5.4.3, File No. 2-64294) 10.14.4 Seventh Amendment to Exhibit 10.14 dated as of April 18, 1979. (Exhibit 5.4.4, File No. 2-64294) 10.14.5 Eighth Amendment to Exhibit 10.14 dated as of April 25,

. 1979. (Exhibit 5.4.5, File No. 2-64815)

10.14.6 Ninth Amendment to Exhibit 10.14 dated as of June 8, 1979. (Exhibit 5.4.6, File No. 2-64815) 10.14.7 Tenth Amendment to Exhibit 10.14 dated as of October 10, 1979. (Exhibit 5.4.2, File No. 2-66334)

I 10.14.8 Eleventh Amerdment to Exhibit 10.14 dated as of December 15, 1979. (Exhibit 5.4.8, File No. 2-66492) 10.14.9 Twelfth Amendment to Exhibit 10.14 dated as of June 16, 1980. (Exhibit 5.4.9, File No. 2-68168) 10.14.10 Thirteenth Amendment to Exhibit 10.14 dated as of December 31, 1980. (Exhibit 10.6, File No. 2-70579) 10.15 Memorandum of Understanding between CL6P, HELCO, Holyoke Power and Electric Company, HWP and WMECO dated as of June 1, 1970 with respect to pooling of generation and transmission. (Exhibit 13.32, File No. 2-38177)

• 10.15.1 Amendment to Memorandum of Understanding between CL&P, HELCO, Holyoke Power and Electric Company, HWP and WMECO dated as of February 2, 1982 with respect to pooling of generation and transmission.

10.16 New England Power Pool Agreement effective as of Novembcr 1, 1971 as amended. (Exhibit 7.44, File No.

260806) 10.17 Participation Agreement dated June 20, 1969 between Maine Electric Power Company, Inc., CL&P, WMECO, HELCO and HWP.

(Exhibit 10.22, 1980 Form 10-K, File No. 1-5324) 10.l7.1 Supplement amending Participation Agreement dated as of June 24, 1970. (Exhibit 10.22.1, 1980 Form 10-K, File No. 1-5324) 10.17.2 Second Supplement to Participation Agreement dated as of December 1, 1971. (Exhibit 10.22.2, 1980 Form 10-K, File No. 1-5324) 10.17.3 Amendment to Unit Participation Agreement dated as of December 11, 1980. (Exhibit 10.22, 1981 Form 10-K, File No. 1-5324) 10.18 Sharing Agreement dated as of September 1, 1973 with respect to 1979 Connecticut nuclear generating unit.

(Exhibit 6.43, File No. 2-50142) m

10.18.1 Amendment dated August 1, 1974 to Sharing Agreement--1979 Connecticut Nuclear Unit. (Exhibit 5.45, File No. 2-52392) 10.18.2 Amendment dated December, 1975 to Sharing Agreement--1979

• Connecticut Nuclear Unit. (Exhibit 7.47, File No. 2-60806) 10.19 Agreement Among Participants in Nuclear Units for Temporary Reallocation of Capacity in Event of Delay in Units. (Exhibit 6.45, File No. 2-50142) 10.19.1 Agreement Among Participants in Nuclear Units for Sharing of Additional Capacity Made Necessary by Delay in Units.

(Exhibit 6.46, File No. 2-50142) 10.20 Lease dated as of July 1, 1970 between CL&P and The Rocky River Realty Company. (Exhibit 13.34, File No. 2-38177) 10.21 Agreement dated October 14, 1957 by and among WMECO, Holyoke Power and Electric Company, HWP and Old Colony Trust Company. (Exhibit 13.11, File No. 2-14830) 10.22 Gas Sales Contract applicable to CD-6 rates between Conn.

Gas and Tennessee Gas Pipeline Company, dated December 13, 1978. (Exhibit 10.32, 1980 Form 10-K, File No. 1-5324) 10.23 Service Agreement dated January 9, 1979 applicable to rate schedule F-1 between Algonquin Gas Transmission Company and Conn. Gas. (Exhibit 10.36, 1980 Form 10-K, File No. 1-5324) 10.24 Service Agreement dated January 9, 1979 applicable to rate schedule W-S-1 between Algonquin Gas Transmission Company and Conn. Gas. (Exhibit 10.37, 1980 Form 10-K, File No. 1-5324) l 10.25 Service Agreement dated January 9, 1979 applicable to rate schedule SNG-1 between Conn. Gas and Algonquin f

' Transmission Company. (Exhibit 10.38, 1980 Form 10-K, File No. 1-5324) 10.26 Storage Service Transportation contract dated May 26, 1981 between Tennessee Gas Pipeline Company and Conn Gas.

(Exhibit 10.39, 1981 Form 10-K, File No. 1-5324) 10.27 Service Agreement between Algonquin LNG, Inc. and Conn Gas dated February 29, 1980 which provides for storage of l

l 120,000 bbis. of LNG in Algonquin's Providence, Rhode Island LNG storage tar.k. (Exhibit 10.40, 1981 Form 10-K, File No. 1-5324) .

10.27.1 Underground Storage Agreement (Rate Schedule SS-1) dated as of May 21, 1981 between Penn-York Storage Corporation and Conn Gas which provides for underground storage of

• gas owned by Conn Gas. (Exhibit 10.40.1, 1981 Form 10-K, File No. 1-5324) 10.28 Memorandum of Agreement among Boundary Gas, Inc., Conn.

. Gas and other utilities, dated October 6, 1980. (Exhibit 10.42, 1980 Form 10-K, File No. 1-5324) 10.29 Precedent Agreement between TransCanada Pipelines Limited and Boundary Gas, Inc., dated October 14, 1980 (Exhibit 10.43, 1980 Form 10-K, File No. 1-5324) 10.30 Service Contract dated as of March 1, 1977 between CL&P and IIELCO. (Exhibit 10.45, 1980 Form 10-K, File No. 1-5324) 10.30.1 Form of Annual Renewal of Service Contract. (Exhibit 10.45.1, 1980 Form 10-K, File No. 1-5324) 10.31 Extra Expense Insurance Policy issued by Nuclear Electric Insurance Limited.with respect to the Millstone nuclear generating units, commencing September 15, 1981.

(Exhibit 10.46, 1981 Form 10-K, File No. 1-5324) 10.31.1 Excess Property insurance Policy issued by Nuclear Electric Insurance Limited with respect to the Millstone l nuclear generating units. (Exhibit 10.46.1, 1981 Form i 10-K, File No. 1-5324) 1 10.32 Extra Expense Insurance Policy issued by Nuclear Electric Insurance Limited with respect to the Connecticut Yankee nuclear generating plant, commencing September 15, 1981.

(Exhibit 10.47, 1981 Form 10-K, File No. 1-5324) 10.32.1 Excess Property Insurance Policy issued by Nuclear Electric Insurance Limited with respect to the Connecticut Yankee nuclear generating unit. (Exhibit 10.47.1, 1981 Form 10-K, File No. 1-5324) l l 10.33 Fuel oil purchase agreement between Amerada Hess Corporation and the Service Company dated December 24, 1970. (Exhibit 10.48, 1980 Form 10-K, File No. 1-5324) 9 10.34 Supplement to fuel oil purchase agreement between Amerada Hess Corporation and the Service Company dated February 22, 1977 (Exhibit 10.49, 1980 Form 10-K, File No. 1-5324) 10.35 Trust Agreement dated January 4,1982, between The Connecticut Bank and Trust Company, as Trustor, and Bankers Trust Company, as Trustee, and CL&P, HELCO and WMECO, (Exhibit 10.54, 1981 Form 10-K, File No. 1-5324) 10.35.1 Nuclear Fuel Lease Agreement dated as of January 4,.1982, between Bankers Trust Company, Trustee, as Lessor, and CL&P, HELCO and WMECO, as Lessees. (Exhibit 10.54.1, 1981 Form 10-K, File No. 1-5324) 10.36 Phase I New Hampshire Transmission Line Support Agreement,. dated as of December l', 1981. (Exhibit 10.55, 1981 Forn 10-K, File No. 1-5324) 10.36.1 Phase I Vermont Transmission Line Support Agreement, dated as of December 1, 1981. (Exhibit 10.55.1, 1981 Form 10-K, File No. 1-5324) 10.36.2 Phase I Terminal Facility Support Agreement, dated as of December 1, 1981. (Exhibit 10.55.2, 1981 Form 10-K, File No. 1-5324) 10.36.3 Agreement with respect to Use of Quebec interconnection, dated as of December 1, 1981. (Exhibit 10.55.3, 1981 Form 10-K, File No. 1-5324) 10.36.4 Millstone Construction Trust - $200,000,000 Credit Agreement dated as of March 15, 1982. (Exhibit 10.1, March 31, 1982, Form 10-Q, File No. 1-5324) 10.36.5 Millstone Construction Trust - S200,000,000 Revolving Credit Agreement dated as of March 15, 1982 (Exhibit 10.2, March 31, 1982, Form 10-Q, File No. 1-5324)

The registrant undertakes to file with the Commission upon request any instrument with respect to long-term debt of the regis-trant and its subsidiaries, not filed herewith, as to which the total amount of securities authorized thereunder does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis.

• 13 Annual Report to Shareholders

• *22 Subsidiaries of the Registrant

(b) Reports on Form 8-K - The Company filed a report on Form 8-K as of December 29, 1982 regarding the decision by the DPUC to grant CL&P annual retail electric and gas rate increases of ,

approximately $101.1 million.

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l SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

NORTHEAST UTILITIES (Registrant)

Date March 8, 1983 By /s/ Lelan F. Sillin, Jr.

Lelan F. Sillin, Jr.

Chairmat. and Chief Executive Officer l

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I

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated, s

Date March 8, 1983 By /s/ Lelan F. Sillin, Jr.

Lelan F. Sillin, Jr. -

Trustee, Chairman and Chief Executive Officer Date March 8, 1983 By /s/ William B. Ellis William B. Ellis Trustee, President and Chief Operating Officer Date March 8, 1983 By /s/ E. James Ferland E. James Ferland Vice President and Chief Financial Officer Date March 8, 1983 By_ /s/ George D. Uhl George D. Uhl Controller and Chief Accounting Officer Date March 8, 1983 By /s/ William O. Bailey Willicm O. Bailey Trustee Date March 8, 1983 By /s/ Edward B. Bates Edward B. Bates Trustee Date March 8, 1983 By /s/ John McP. Collins John McP. Collins I

Trustee i

Date March 8, 1983 By /s/ Donald W. Davis Donald W. Davis

! Trustee i

O t

Date By Richard B. Haskell Trustee l 4 Date March 8, 1983 By /s/ Eugene D. Jones Eugene D. Jones Trustee Date March 8, 1983 By /s/ Elizabeth T. Kennan Elizabeth T. Kennan Trustee ,

Date March 8, 1983 By /s/ Chester W. Kitchings Chester W. Kitchings Trustee Date March 8, 1983 By /s/ Denham C. Lunt, Jr.

) Denham C. Lunt, Jr.

Trustee Date March 8, 1983 By /s/ Burke Marshn]l Burke Marshall Trustee Date March 8, 1983 By /s/ William J. Pape, II l

William J. Pape, Il Trustee Date March 8, 1983 By /s/ Norman C. Rasmussen i Norman C. Rasmussen Trustee Date March 8, 1983 By /s/ Albert E. Steiger, Jr.

Albert E. Steiger, Jr.

Trustee l

Date By l Donald C. Switzer l Trustee o

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NORTHEAST UTILITIES AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS The Company Report and Auditors' Report are located on pagea 30 and 31, respectively, of the Company's Annual Report to Shareholders, portions of which are attached to this report as Appendix A.

e Consolidated Financial Statements are located on pages 32 to 49 of the Company's Annual Report to Shareholders, portions of which are attached to this report as Appendix A.

Consolidated Statements of Income for the years ended December 31, 1982, 1981 and 1980 Consolidated Statements of Sources of Funds for Gross Property Additions for the years ended December 31, 1982, 1981 and 1980 C[nsolidatedBalanceSheetsatDecember 31, 1982 and 1981 Consolidated Statements of Capitalization at December 31, 1982 and 1981 Consolidated Statements of Common Shareholders' Equity for the years ended December 31, 1982, 1981 and 1980 Notes to Consolidated Financial Statements Page Report of Independent Public Accountants on Schedules S-1 Consent of Independent Public Accountants S-1 Schedules Supporting Consolidated Financial Statements:

Schedule l

Number V. Utility Plant (including Intangibles and excluding Nuclear Fuel), Consolidated - years ended December 31, 1982, 1981 and 1980 S-2--S-4 V. Nuclear Fuel, Consolidated - years ended December 31, i 1982, 1981 and 1980 S-5--S-7 VI. Accumulated Provision for Depreciation of Utility Plant, Consolidated - years ended December 31, 1982, 1981 and 1980 S-8--S-10 l

l VIII. Reserves, Consolidated - years ended December 31, 1982, l

1981 and 1980 S-ll--S-13 IX. Short-Term Borrowings, Consolidated - years ended December 31, 1982, 1981 and 1980 S-14 X. Supplementary Income Stctement Information, Consolidated-years ended December 31, 1982, 1981 and 1980 S-15 F-1

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES e

4 In connection with our examinations of the financial statements included in Northeast Utilities' Annual Report to Shareholders and incorporated by reference in this Form 10-K, we have also examined the supplemental schedules listed in the accompanying index. Our examinations were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplemental schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and regulations under the Securities Exchange Act of 1934 and are not otherwise a required part of the basic financial statements. The supplemental schedules have been subjected to the auditing procedures applied in the examinations of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

ARTHUR ANDERSEU & CO.

Hartford, Connecticut.

February 18, 1983.

CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our reports dated February 18, 1983 appearing, or incorporated by reference, in Northeast Utilities' annual report on Form 10-K for the year ended December 31, 1982, into Post-effective Amendment No. I to the Company's Form S-16 on Form S-3 Registration Statement No. 2-74611.

ARTHUR ANDERSEN & CO.

Hartford, Connecticut, March 8, 1983 S-1

9 NORTHEAST UTILITIES AND SUBSIDIARIES

UTILITY PLANT (INCLUDING INTANGIBLES AND EXCLUDING WUCLEAR FUEL)

} YEAR ENDED DECEMBER 31, 1982 (Thousands of Dollars) X' COL. A COL B COL. C COL. D COL. E COL. F @

Balance at Other Changes- Balance y beginning Additions Add (Deduct)- at close <

Classification of period at cost Retirements Describe of period Utility Plant in Service

Electric $2,913,820 $132,379 $15,519 $ (98)(f) $3,031,055 11 (c) 167 (b) 295 (d)

Gas 198,197 25,665 1,418 (9)(f) 222,435 j Other 32,925 821 1,845 (295)(d) 31,492 i (114)(f) l l Construction Work in Progress j Electric 878,087 338,057 (a) -

(103)(f) 1,207,511 j u, (8.530)(e) 3 i Cas 6,995 (3,577)(a) - -

3,418 Other 8,996 4,006 (a) -

(353)(f) 12,649 Utility Plant Held for Future Use i Electric 8,984 13 3 (2,000)(f) 6,827 j (167)(b)

Gas 25 - - -

25 Other 3,034 18 20 (598)(f) 2,434 TOTAL $4,051,063 $497,382 $18,805 $(11,794) $4,517,846 i

] (a) Net increase (decrease) during the year.

(b) Transfer between Utility Plant in Service and Utility Plant Held for Future Use.

(c) Adjustment of prior year retirement.

(d) Transfer between Utility Plant in Service Electric and Utility Plant in Service Other.

(e) Transfer between Construction Work in Progress and Nuclear Fuel.

(f) Transfer between Utility Plant Accounts and Non-Utility Plant Accounts.

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NORTHEAST UTILITIES AND SUBSIDIARIES UTILITY PLANT (INCLUDING INTANGIBLES AND EXCLUDING NUCLEAR FUEL)

YEAR ENDED DECEMBER 31, 1981 (Thousands of Dollars)

COL. B COL C COL. D COL. E COL. F COL. A Other Changes- Balance Balance at beginning Additions Add (Deduct)- at close of period at cost Retirements Describe of period Classification Utility Plant in Service Electric $2,756,140 $181,637 $23,678 $ (429) (b) $2,913,820 119 (d)

(37)(e) 68 (c) 1,137 - 198,197 Gas 180,251 19.083 31,547 1,365 24 37 (e) 32,925 Other Construccion Work in Progress 878,087 v3 Electric 712,646 172,662 (a) - (5,215)(f) d, (2,006) (g) 1,986 (a) - - 6,995 cas 5,009 (911)(h) 8,996 Other 10,270 (363)(a) -

Utility Plant Held for Future Use 2,001 (68)(c) 8,984 Electric 7,051 -

- - 25 Cas 25 -

218 2,816 - - 3.034 Other

$381,187 $24,839 $(8,442) $4,051,063 TOTAL $3,703,157 (a) Net increase (decrease) during the year. E (b) Transfer between Utility Plant in Service and Nonutility Property. E' (c) Transfer between Utility Plant in Service and Utility Plant Held for Future Use. $"

(d) Adjustment of prior year retirement. E (e) Transfer between Utility Plant in Service Electric and Other. <

i (f) Sale of a portion of CL&P's interest in the Seabrook nuclear project.

(g) Canceled Nuclear Project.

(h) Transfer between Construction Work in Progress and Nonutility Property.

NORTilEAST UTILITIES AND SUBSIDIARIES UTILITY PLANT (INCLUDING INTANGIBLES AND EXCLUDING NUCLEAR FUEL)

YEAR ENDED DECEMBER 31, 1980 (Thousands of Dollars) m 5

m COL. A COL. B COL. C COL. D COL. E COL. F Balance at Other Changes- Balance ha beginning Additions Add (Deduct)- at close Classification of period at cost Retirements Describe of period Utility Plant in Service Electric $2,682,232 $ 87,055 $13,170 $ -(123)(b) $2,756,140 147 (c)

(1)(f)

Gas 163,933 18,305 1,983 (7)(f) 180,251 3 (b)

Other 32,045 525 231 (792)(d) 31,547 Construction Work in Progress Electric 568,460 170,152(a) -

(22)(e) 712,646 (25,944)(h)

Gas 3,411 1,598(a) - - 5,009 792 (d)

{ Other Utility Plant Held for Future Use 5,570 3,908(a) - 10,270 Electric 6,072 860 -

(4)(g) 7,051 123 (b) cas 28 - -

(3)(b) 25 Other 218 - - - 218 TOTAL $3,461,969 $282,403 $15,384 $(25,831) $3,703,157 (a) Net increase during the year.

(b) Transfer between Utility Plant in Service and Utility Plant Held for Future Use.

(c) Adjustment of prior year retirement.

(d) Transfer between Utility Plant in Service to Construction Work in Progress in order to comply with the Securities and Exchange Commission Regulations.

(e) Sale of substation.

(f) Transfer between Utility Plant in Service and Nonutility Property.

(g) Transfer between Nonutility Plant and Utility Plant Held for Future Use.

(h) Canceled Nuclear Project.

• *

• o NORTHEAST UTILITIES AND SUBSIDIARIES NUCLEAR FUEL YEAR ENDED DECEMBER 31, 1982 (Thousands of Dollars)

COL. B COL. C COL. D COL. E COL. F COL. A Balance at Other Changes- Balance beginning Additions Add (Deduct)- at close of period at cost Retirements Describe of period Classification Nuclear fuel in process of refinement, S 98,544 $36,450 $- $ (65,629)(e) $ -

conversion, enrichment and fabrication (79,026)(b) 9,661 (g)

Nuclear fuel materials and assemblies -

stock account 56,213 70 -

814 (b) -

(55,877)(e)

(1,220)(g) 140,823 - 40,235 (b) -

v3 Nuclear fuel assemblies in reactor -

(181,058)(e) 85,350 37,977 (b) -

Spent nuclear fuel - -

(123,327)(e)

Accumulated provision for amortization (48,509)(a) of nuclear fuel assemblies (191,005) - -

(2,291) (c) 204 (d) 195,491 (e) 46,021 (f) 89 (g)

$ 189,925 $36,520 $- S(226,445) S -

TOTAL NUCLEAR FUEL (a) Amortization of nuclear fuel assemblies and nuclear fuel disposal costs charged to expense.

y, (b) Transfers between nuclear fuel accounts. g.

(c) Combustion Engineering transfer credits.

(d) End of cycle adjustment. 1 (e) Sale of nuclear fuel to a third party trust. 5 o

(f) Transfer of nuclear fuel disposal costs and related credits to accumulated provision for <

depreciation.

(g) Transfer of nuclear fuel and related credits to Construction Work in Progress.

NORTHEAST UTILITIES AND SUBSIDIARIES X' NUCLEAR FUEL [

YEAR ENDED DECEMBER 31, 1981 7 (Thousands of Dollars) g' 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 $ 70,925 $31,991 $- $ (420)(e) $ 98,544 (3,952)(b)

Nuclear fuel materials and assemblies -

stock account 31,644 45,031 - (20,462)(b) 56,213 Nuclear fuel assemblies in reactor 130,409 - - 10,414 (b) 140,823 vi 5 14,000 (b) 85,350 Spent nuclear fuel 71,350 - -

Accumulated provision for amortization of nuclear fuel assemblies (150,767) - - (39,465)(a) (191,005)

(991)(c) 238 (d)

TOTAL NUCLEAR FUEL S153,541 $77,022 $- $(40,638) $189,925 (a) Amortization of nuclear fuel assemblies and nuclear fuel disposal costs charged to expense. Excludes $163,000 which represents a portion of the net positive salvage authorized by the State Regulatory Commission to be recovered through rates over a four-year period.

(b) Transfers between nuclear fuel accounts.

(c) Combustion Engineering transfer credits.

(d) End of cycle adjustment.

(e) During 1981, CL&P sold a portion of its ownership in the Seabrook plant and the related nuclear fuel in process.

• ' ,, o NORTHEAST UTILITIES AND SUBSIDIARIES NUCLEAR FUEL YEAR ENDED DECEMBER 31, 1980 (Thousands of Dollars)

COL. B COL, C COL. D COL. E COL. F COL. A Other Changes- Balance Balance at beginning Additions Add (Deduct)- at close of period at cost Retirements Describe of period Classification Nuclear fuel in process of refinement, $(40,350)(b) $ 70,925 conversion, enrichment and fabrication S 54,186 $57,289 $-

Nuclear fuel naterials and assemblies - 10,002 - 8,621 (b) 31,644 13,021 stock account 108,928 - - 21,481 (b) 130,409 Nuclear fuel assemblies in reactor 10,448 (b) 71,350 60,902 - -

[ Spent nuclear fuel Accumulated provision for amortization (30,413)(a) (150,787) of nuclear fuel assemblies (119,881) - -

(619)(c) 126 (d)

$- $(30,906) $153,541 TOTAL NUCLEAR FUEL $117,156 $67,291 Excludes $435,000 (a) Amortization of nuclear fuel assemblics and nu: lear fuel disposal costs charged to expense.

which represents a portion of the net positive salvage authorized by the State Regulatory Commission to be recovered through rates over a four-year period.

(b) Transfers between nuclear fuel accounts. v3 (c) Combustion Engineering transfer credits. Q.

(d) End of cycle adjustment.

E.

I 4

NORTHEAST UTILITIES AND SUBSIDIARIES -

ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT E.

YEAR ENDED DECEMBER 31, 1982 E.

(Thousands of Dollars) d COL A COL, B PT. . C COL. D COL. E COL. F Additions Balance at Charged to Other Changes- Balance beginning Costs and Add (Deduct)- at close Description of period Expenses Retirements Describe of period ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT Electric $861,258 $ 99,879 $17,988 $ 105 (a) $ 989,275 46,021 (b)

Gas 38,258 5,803 1,999 494 (a) 42,556 Other 13,435 735 1,705 247 (a) 12,712 Total $912,951 $106,417 $21,692 $46,867 $1,044,543 (a) Depreciation charged to Transportation Clearing, Fuel Stock and Other Accounts.

(b) Transfer between accumulated provision for depreciation and nuclear fuel.

k 8 kb h

1. D D c NORTHEAST UTILITIES AND SUBSIDIARIES ACCUMULATED PROVISION FOR DEPRECIATIOI; 0F UTILITY PLANT YEAR ENDED DECEMBER 31, 1981 (Thousands of Dollars)

COL. A COL. B COL. C COL. D COL. E COL. F Additions Balance at Charged to Other Changes- Balance beginning Costs and Add (Deduct)- at close Description of period Expenses Retirements Describe of period, ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY FLANT Electric $788,433 $ 96,547 $24,071 $ 349 (a) $861,258 m Gas 34,253 5,400 1,463 68 (a) 38,258 E

Other 11,784 854 62 859 (a) 13,435

$834,470 $102,801 $25,596 $1,276 $912,951 Total (a) Depreciation charged to Transportation Clearing, Fuel Stock and Other Accounts.

N if r

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N NORTHEAST UTILITIES AND SUBSIDIARIES l ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT g-YEAR ENDED DECEMBER 31, 1980 g' (Thousands of Dollars) <

s COL. A COL. B COL. C COL. D COL. E COL. F Additions Balance at Charged to other Changes- Balance beginning Costs and Add (Deduct)- at close Description of period Expenses Retirements Describe of period ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT Electric $712,106 $90,626 S14,875 S 576 (a) $788,433 y, Gas 31,118 5,011 2,004 128 (a) 34,253

,L C Other 10,697 629 88 546 (b) 11,784 Total $753,921 $96,266 $16,967 $1,250 S834,470 (a) Depreciation charged to Transportation and Fuel Stock Clearing Accounts.

(b) Depreciation charged to other accounts.

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• e NORTHEAST UTILITIES AND SUBSIDIARIES RESERVES YEAR ENDED DECEMBER 31, 1982 (Thousands of Dollars)

COL. B COL. C COL. D COL. E COL. A 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:

$13,899 $ - $10,765 (a) $8,054 Reserves for uncollectible accounts $4,920 Y

Z RESERVES NOT APPLIED AGAINST ASSETS:

$ 2,242 $- $ 2,010 (c) $2,552 Injuries and damages (b) $2,320 14,695 - 13,961 (d) 2,615 Medical insurance (e) 1,881

$16,937 $- $15,971 $5,167 TOTAL $4,201 (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. v3 (c) Principally payments f r various injuries and damages and expenses in connection therewith, 9 (d) Principally payments for various employee medical expenses and expenses in connection therewith. g, (c) Provided to cover claims for employee medical insurance,

5

N iii NORTHEAST UTILITIES AND SUBSIDIARIES 5' RESERVES <

YEAR ENDED DECEMBER 31, 1981 [

(Thousands of Dollars) "*

COL. A COL. B COL. C COL. D COL. E Additions (1) (2)

Charged to Balance at Charged to Other Balance Beginning Costs and Accounts- Deductions- at End Description of Period Expenses Describe Describe of Period RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY:

m Reserves for uncollectible accoupts $3,772 $ 8,677 $- $ 7,529 (a) $4,920 1

RESERVES NOT APPLIED ACAINST ASSETS:

Injuries and damages (b) $2,125 $ 1,981 $- $ 1,786 (c) $2,320-Medical insurance (e) 'l,883 12,145 - 12,147 (d) 1,881 TOTAL $4,003 $14,126 $- $13,933 $4,201 (a) Amounts charged off as uncolic'ctible after deducting customers' deposits and recoveries of accounts previously charged off.

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

(c) Principally payments for various injuries and damages and expenses in connection therewith.

(d) Principally payments for various employee medical expenses and expenses in connection therewith.

(e) Provided to cover claims for employee medical insurance.

s . , .

__ _. __ _ _ _ _ _ _ _. _ _ _ ._ _ __ . _ = _ _ _ _ _ _ - _ _ ___ _

. . - . - _ - . - - - _ - - ~.. .-.- _- - . - _ . _ . - . . ..

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i NORTHEAST UTILITIES AND SUBSIDIARIES RESERVES YEAR ENDED DECEMBER 31, 1980 ,

i (Thousands of Dollars) i COL. B COL. C COL. D COL. E i

COL. A Additions (1) (2)

Charged to

' Balance at Charged to Other Balance Beginning Costs and Accounts- Deductions- at End of Period Expenses Describe Describe of Period i Description

} RESERVES DEDUCTED FROM ASSETS j, TO WHICH THEY APPLY:

$ 5,938 $- $ 5,617 (a) $3,772 I u) Reserves for uncollectible accounts $3,451 s

RESERVES NOT APPLIED AGalNST ASSETS:

$ 1,993 $- $ 1,890 (c) $2,125

) Injuries and damages (b) $2,022 9,624 (d) 1,883 j Medical insurance (e) 1,636 9,871 -

$3,658 $11,864 $- $11,514 $4,008 TOTAL i

i (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 v2

and property damage, S-j (c) Principally payments for various injuries and damages and expenses in connection therewith.

E.

2 (d) Principally payments for various employee medical expenses and expenses in connection therewith.

5 (e) Provided to cover claims for employee medical insurance. m i 0

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NORTHEAST UTILITIES' AND'6UBSIDIARIES SHORT-TERM BORROWINGS (Dollar Amounts in Thousands) m E

a.

F_.

Column A Column B Column C(a) Column D Column E (b) Column F(c)

Category of Balance Weighted Maximum Average Weighted y aggregate at end of average cmount amount average short-term period interest outstanding outstanding interest rate borrowings rate at end during the during tha during the of period period period period December 31, 1982 Notes Payable to Banks S 19,800 9.2% $155,350 $ 73,620 16.8%

Commercial Paper 37,725 9.3 290,400 117,065 14.0 December 31, 1981 Notes Payable to Banks $ 79,500 13.3% $240,850 $107.956 20.0%

Commercial Paper 146,135 13.0 258,375 182,205 17.2 December 31, 1980 Notes Payable to Banks $168,850 21.2% $193,350 $ 64,540 16.6%

Commercial Paper 168,476 19.6 202,956- 151,084 14.6 (a) Includes commitment fees and excludes the effect of compensating balances.

(b) Average daily balance during the period.

(c) Based on the daily amounts outstanding including commitment fees and excluding the effect of compensating balances.

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NORTHEAST UTILITIES AND SUBSIDIARIES SUPPLEMENTARY INCOME STATEMENT INFORMATION YEARS ENDED DECEMBER 31, 1982, 1981, and 1980 (Thousands of Dollars) i Column A Column B Charged To Costs Item And Expenses l.

i 1981 1980

~

1982 l

Taxes, other than income taxes charged to expense:

en State gross receipts S 73,484 $ 65,229 $ 52,537 53,276

.L Real and personal property 54,631 55,976

• 12,179 10,750 8,496 Payroll and other Total $140,294 $131,955 $114,309 j

l i ~

i Items other than those disclosed above have been omitted because either they are not applicable, j the required information has been presented in the consolidated financial statements or notes thereto, or such amovats are less than 1 percent of total revenues. E'

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4

?

Northeast Utihties and Subsidiaries MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESUI l'S OF OPERATIONS This section is management's assessment of the company's financial condition and the principal factors which have an impact on the results of operations. This discussion should be read in conjunction with the company's consolidated financial statements and footnotes.

FINANCIAL CONDITION More responsible rate regulation in Connecticut and at the federal level has allowed the company to improve its financial condition. Company earnings per common share rose from $1.29 in 1981 to $1.76 in 1982, a 36 percent increase. The company's capital structure has improved with the equity ratio increasing from 31.8 percent of total capitalization at the end of 1981 to 33.5 percent at the end of 1982. The ratio between market price and book value per common share rose from 71 percent on December 31.1981 to 94 percent on December 31,1982. Dividends paid in 1982 were increased to $1.28 per share, reflecting an 8 percent increase from the 1981 level of $1.18 per share. These accomplishments were made during a year when the company had the highest cash requirements in its history -

for debt maturities and construction expenditures.

Because Connecticut revenues amount to approximately 85 percent of the company's total revenues, continuation of an improved regulatory environment in Connecticut is the key to the company eventually regaining financial strength. In light of the significant construction expenditure requirements in the near future, responsib!e regulation wi'l be required if the company is to be able to balance the interests of both ratepayers and shareholders.

Construction Program The construction of the Millstone 3 nuclear unit is the most significant item in the company's construction

, program, representing approximately 64 percent of the system's total planned capital expenditures for the period 1983 through 1986, the planned in-service date of the 4

15

unit. These expenditures include a 1982 revision to the Millstone 3 construction cost estimate, which increased the estimated cost of The Connecticut Light and Power Company's (CL&P) and Western Massachusetts Electric Company's (WMECO) current 65 percent ownership interest (representing 747.5 MW) from $1.7 billion to $2.3 billion. The construction of the unit is now approximately ,

60 percent complete. In a December 1982 rate case decision, the Connecticut Department of Public Utility Control (DPUC) found that "it is in the public interest and in the best interest of the customers and shareholders of

- CL&P that this project [ Millstone 3] be continued."

The construction program also includes CL&P's 4.1 percent interest in two nuclear units under construction in Seabrook, New Hampshire. Based upon a 1982 revised cost estirute and construction schedule, the estimated final cost of CL&P's ownership interest in the Seabrook

, units was increased from Si34 million to $212 million and I the sch'edulea in-service dates for units 1 and 2 were i

Construction Expenditures l

I 700--

-650 - $644 l ..

. 6n- u,,

E50- ,

-500-- M m 4g..

M

" $451 J4&- $381 f b w l g350--

m p..

y gas

' $259 CfT SSION I

l

'2 209 i h .

'"-. ELECTRIC DISTRIBUTION ELECTRIC

$158 PRODUCTION F

100- . .

J' .

D. ,

1978 1979 id90 1981 19R 1983 1984 1985 1986 1987

l. .. . .. . ..... ... ACTU AL ---- ---- - - ---- V ---- ------ - PRoJ ECT ED--- ----------l 16

w ,-

, s ,

p -

i delayeo'from February 1984 and May 1986 to December

? 1984 and July 1987, respectively.

Construction expenditures, including an allowance

s. for funds used during construction (AFUDC) but t

excluding'noclear fuel, for, the period 1978 to 1982 and

. projected construc' ion expenditures through 1987, are l illustrated in the preceding chart. Annual construction expenditures will peak in 1983 and 1984 and will decline during the period through !986 when Millstone 3 is schedcled to be placed in service.

Fin:ncing , Ine system companies finance their requirements in s excess of internally generated funds through short-term and intermediate-term borrowings, construction and nuclear fuel financing trusts, the sale of first mortgage l bonds and preferred stock, leasing agreements and receipt of capital contributions or advances from the parent company. In addition to construction and nuclear fuel requirements. the system companies are obligated to i

spend $205 million in 1983 through 1987 to meet debt maturities and cash sinking-fund requirements.

Internal cash generation has not been sufficient to fund the system companies' entire construction program.

Therefore, external financing has supplied a major porton of the program's requirements and will continue to do so until Millstone 3 is paced in service. The following chart illustrates the relative percentages of all sources of l

f unds f or the five-year period from 1978 to 1982.

I Sources Of Funds

. 100--

99-- '.

@- e oTHER 70" LoNG-TERM DEBT E 80--

PREFERRED STOCK g.

m y couuoN stock O 30-- INTERNAL s 20--

10--

0-1978 1979 1980 1981 1982 4

17 l

i l , ._

During 1982, the company was able to meet its financing requirements through various financing y vehicles. The company sold eight million common shares in a public offering and approximately two and one-half million shares through its Dividend Reinvestment and -

Common Share Purchase Plan. These sales resulted in net proceeds to the company of $83 million and $25 million, respectively, in addition, the system companies realized net proceeds of $197 million from the issue and sale of first mortgage bonds and preferred stock during 1982.

In March 1982, CL&P and WMECO entered into a construction trust agreement to finance a portion of the Millstone 3 construction expenditures. The primary purpose of the construction trust is to allow CL&P and WMECO to defer the issuance of large amounts of debt and equity securities until Millstone 3 is in service and the companies begin to receive increased cash flow benefits as a result of its inclusion in rate base. As of December 31, 1982, the companies had $135 million outstanding, including interest, under this agreement.

CL&P and WMECO entered into a nuclear fuel trust agreement, the Niantic Bay Fuel Trust (NBFT),in February 1982. The trust owns and finances the nuclear fuel for Millstone 1 and 2 and the companies' ownership share of the nuclear fuel for Millstone 3, and leases it to CL&P and WMECO while it is used in the reactors. As of December 31,1982, the trust's investment in nuclear fuel was $267 million. It is anticipated that NBFT will provide the necessary financing for CL&P's and WMECO's nuclear fuel requirements for the Millstone units.

g in November 1982, CL&P and WMECO increased d4 tne limit on a revolving credit / term loan agreement entered into during 1980 by $60 million to a new level of

$200 million, and CL&P entered into a two-year $50 mil! ion floating-rate Eurodollar revolving credit agreement. There were no borrowings under either of tnese agreements during 1982. In addition, the system companies have $48 million of credit lines with various banks. These agreements provide the system companies another source of extemal financing.

To assist in raising required capital in a cost-effective manner, CL&P is prepared to use, when appropriate, additional financing vehicles. CL&P is '

considering the issuance of bonds in the Eurobond market for up to $75 million. It is also considering 18

entering 'into a floating-rate Eurodollar interniediate-term loan arrangement for up to $75 million, coupled with an

" interest rate swap" arrangement. The objective of such an arrangement is to convert the floating-rate term loan obligation into a fixed-rate obligation having a lower effective interest cost than a comparable first mortgage bond issue. Whether a Eurobond issue, a term loan and interest rate swap transaction or a conventional first mortgage bond issue will be effected by CL&P will be evaluated in light of prevailing interest rates and market conditions.

In 1983, the company expects to self additional common shares to the general public and through the Dividend Reinvestment and Common Share Purchase Plan, primarily to finance the company's equity contributions to its subsidiaries. The company's subsidiaries also intend to issue additional long-term debt and preferred stock and to utilize further the present construction and nuclear fuel trust agreements.

The company has a targeted capital structure of 40 percent common equity,12 percent preferred stock and 48 percent long-term debt. Management believes that such a capital structure will improve bond ratings and financing flexibility. The company's common equity ratio of 33.5 percent at December 31,1982 is low by utility industry standards and has been a factor in the downgradings of CL&P's and WMECO's bond ratings.

Some improvement in the capital structure occurred as a result of the common stock sale in 1982.

l Rate Matters Adequate and timely rate relief remains the key to improving the system's operating results, increasing internal cash generation and assuring the ability to enter the capital markets at a reasonable cost. Therefore, the system companies will continue to file applications, when appropriate, for needed rate relief in both their wholesale and retail jurisdictions.

4 The company is encouraged by improvements made in Connecticut regulatory treatment, including the recognition of the effects of inflation on operating costs.

19

During 1982, the DPUC granted CL&P $101.1 million in additional annual revenues, or 79.5 percent of the e amount requested. A December 1981 Connecticut rate case decision allowed CL&P to adopt a change in its fuel recovery procedures to provide for the collection of ~

substantially all fuel costs from retail customers, thereby, rectifying an inequity that previously existed. The following chart presents a comparison of Connecticut retail rate increases requested versus allowed. The decisions since 1979 are of major significance because they have provided a signal to the financial community

, that the regulatory climate in Connecticut is improving its response to prevailing economic conditions.

Connecticut Retail Rata increases Requested versus Allowed 300-

' ~

$261 250-200 -

$188 3,7, 3 REoUESTEo

~

8 M ^ttowEo

$131

$127 g ,

1 hI125 7

i 1979 i

1980 i

1981 h i 1982 Effective May 1982, the Federal Energy Regulatory Commission (FERC), approved a settlement between CL&P and its wholesale customers allowihg $5.7 million ,

in additional annual revenues. CL&P has also received approval from FERC of a settlement with its wholesale customers to iricrease its wholesale rates by an y additional $2.3 million annually, effective July 1,1983.

20

The company, however, is becoming increasingly concerned about the lack of responsiveness on the part of the Massachusetts Department of Public Utilities (DPU). Recent DPU ratemaking policies have not provided WMECO an opportunity to earn allowed returns.

During 1982, the DPU granted only $4.4 millien in additional annual revenues, or 18 percent of the amount sought. The following chart illustrates a comparison of 1 Massachusetts retail rate increases requested versus  !

allowed. l l

Massachusetts Retall Rate increases Requested versus Allowed 60-m 42 40-8 O

E REOUESTED O

$28 g ALLOWED 9

d20-2

$14 4

0- g l 1980 1981 1982 Note There were no Massachusetts retad rate deosions issued to WMECO dunng 1979 l

In October 1982, WMECO filed an application with the DPU for an increase in electric retail rates, requesting j immediate interim rate reliet of $5.3 million and

!

• permanent rate relief of $24.1 million. Decisions on both requests are pending at this time.

9 21

_ _ _ . , . . _ ~ . . . . _ . _ . _ . __ _

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4 D

i RESULTS OF The principal factors affecting the company's results OPERATIONS of operations can be put into perspective by presenting a the major components included in the results of operations. The following charts, indicating where the company's 1982 revenue dollar came from and went.

illustrate both the respective size of our electric and gas operations and the magnitude of the various expenses the company incurs.

1982 Revenue Dollar (cents per dollar of revenues)

Where it Came From Where 11 Went 1.04 Other 8.1c 12.7C Gas 4.3% l N3 ic;- 14 3g L17)' '

y.

- - ~

6 Oc

$5 86 3C Electrc 1634 114e O ENERGY costs

^ ^

Residential 35 9c 5 3c 3 3c M oTHER OPERATION AND Commercial 272C " "^

( Industriat 178C 4 OC M DEPRECIATION l Wholesale 2.7c -

streettighting and W TAXES Miscellaneous 2 7$ O lt INTEREST CHARGES AND Total 86 34 127c oTHER INCOME. NET Q COMMON AND i PREFERRED DIVIDENDS

! O EARNINGS RETAINED

, FOR REINVESTMFNT 22

l Operating Revenues Operating revenues increased $108.2 million from 1981 to 1982 and $330.5 million in 1981 compared to 1980. The components of the change in operating ' I revenues for the past two years were as follows:

Increase /(Decrease) ~ I 1982 vs.1981 1981 vs.1980 (Thousands of Dollars)

Rate increases $199.226 $128.430 Fuel cost recovenes (63.282) 186.498 sales increases (decreases) (20.649) 14.879 Other (7.132) 705 Total revenue increase $108.163 $330.512 The retail rate increases granted were the major causes of revenue increases in 1982 and provided a substantial portion of the total 1981 increaso.

Fuel cost recovery revenues decreased in 1982 because of the decline in oil prices during the year. By comparison, oil prices increased rapidly in early 1931 so that fuel cost recovery revenues in 1981 contributed more than half of the overall revenue increase from 1980.

The average cost of oil to the system companies was approximately $30 per barrel in 1982, compared to $33 in 1981 and $27 in 1980.

A decrease of 1.9 percent in electric sales and less than 1 percent in gas sales during 1982 can be attributed to the effects of weak economic conditions, continued customer conservation efforts, together with more moderate weather conditions. Electric sales increased less than 1 percent and gua sales increased 5.4 percent I during 1981. l l

l l

l Electric and Gas Electric energy expenses decreased $99.0 million in j Enirgy Expenses 1982 as compared to 1981 as a result of several l

contributing factors. Fossil fuel prices drifted downward during most of 1982 and, at the same time, the system companies' sales decreased by 1.9 percent. In addition,  !

1982 includes a full year of generation from the Mt. Tom station, which began burning coalin December 1981. .

Electric energy expenses increased $171.2 million during 1981 as compared to 1980 primarily because of increased fossil fuel prices. -

l l

23

Gas energy expenses increased $36.0 million in 1982 as compared to 1981 and $22.3 million in 1981 as

, compared to 1980. These increases are primarily a result of increased gas prices.

Other Operation and Other operation and maintenance expenses Maintenance Expenses increased $83.0 million in 1982 compared to 1981 and increased $57.8 million in 1981 as compared to 1980.

Inflation contributed to these increased expenses because of its impact on payroll, materials and supplies, and employee benefits. In addition, Nuclear Regulatory Commission directives and higher nuclear outage costs increased other operation and maintenance expenses during 1982 and 1981.

Despite increased nuclear operation and maintenance expenses, nuclear units continue to offer substantial savings over oil-fired units. During 1982, nuclear energy spared the use of approximately 22.2 million barrels of oil and resulted in a savings of $316.7 million to our customers through a reduction in other fuel costs. In addition, the capacity factors of the nuclear units the system companies own and operate, or in which they have entitlements, continue to be above average as compared to the total United States nuclear power industry.

income Taxes Federal and state income taxes increased $45.7

million in 1982 as compared to 1981. The current income tax increase of $12.3 million can be attributed to an increase in taxable income. Deferred income taxes increased $33.4 million in 1982 primarily as a result of an

! increase in investment tax credit normalization. Federal and state income taxes increased $18.7 million in 1981 as compared to 1980. This increase was primarily caused by higher current income taxes of $14.0 million resulting from an increase in taxable income.

24 i

All;wance for Funds Allowance for funds used during construction, which Used During represents the estimated cost of capitalinvested in Construction - construction work in progress (CWIP), increased $14.4 million in 1982 and $22.8 million in 1981 These '

increases were caused by higher average CWIP balances, attributed primarily to the Millstone 3 _

construction project. The increase in AFUDC during 1982 was partially reduced as a result of nuclear fuel being financed by the nuclear fuel trust. A 1986 in-service date is planned for Millstone 3 and at that time, under current regulatory practice, the unit investment would be transferred from CWIP to plant in-service and AFUDC would be significantly reduced.

Intsrest Charges interest charges decreased $13.2 million during 1982 as compared to 1981 as a result of several contributing factors. The system companies reduced their short-term debt balance significantly by issuing long-term debt and equity securities, and using trust financing agreements. In addition, the system companies benefited from a reduction in short-term interest rates.

Interest charges were also reduced in 1982 because

financing costs for most nuclear fuel requirements are now incurred by the nuclear fuel trust and recorded in 4

fuel expense by the company when the nuclear fuel is burned. In contrast, during 1981 an increase in short-term borrowings, new long-term and intermediate-term debt issues, and higher interest rates contributed to a

$62.8 million increase in interest expense.

Imp;ct of inflation As previously indicated, the company is impacted by the effects of inflation and has attempted to quantify this impact as prescribed by the Financial Accounting Standards Board in Statement of Financial Accounting Standards No. 33," Financial Reporting and Changing

• Prices." See Note 10," Impact of Changing Prices," of -

Notes to Consolidated Financial Statements for a discussion on the impact of inflation on the company.

[

25 l

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FINANCIAI. ANDfiTATI!iTICAI.SECTIIN

. Contents Page Company Report. 30 Auditors

• Report. 31 Consolidated Statements of Income. 32 Consolidated Statements of Sources of Funds for Gross Property Additions. 33 Consolidated Balance Sheets. 34-3',

Consolidated Statements of Capitalization. 36-37 Consolidated Statements of Common Shareholders' Equity . 38 Notes to Consolidated Financial Statements . 39-49 Selected Consolidated Financial Data . 50 Consolidated Operating Statistics:

General 51 Electric . 52 Gas. 53 Consolidated Statements of Quarterly Financial Data . 54 Common Share Information 54 l

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NORTHEAST UTILITIES ANNUAI. REPORT 198:t 29

Northeast Ut6ttes and Subsidianes COMIMNY REIMMtT f

The consolidated financial statements of Northeast Utilities and subsidiaries and other sections of this Annual Report were prepared by the company. These financial statements, which were examined by Arthur Andersen & Co., were prepared in accordance with generally accepted accounting principles using estimates and judgment, where required, giving consideration to materiality.

The company maintains a system of internal accounting controls that is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits. The company has endeavored to establish an environment which encourages the maintenance of high standards of conduct in all of its business activities Written procedures manuals and established training programs communicate to the company's employees their intemal control responsibilities as well as the company's policies and procedures prohibiting conflicts of interest. All supervisors are required to review internal control procedures under their jurisdiction and annually to make written representations as to the adequacy of the system of internal controls and its implementation. The company requires annual written representations from all management employees on possible conflicts of interest Management reviews and acts upon all questions of the adequacy of the internal control process and possible conflicts of interest.

The Audit Committee of the Board of Trustees is composed entirely of outside trustees. This committee meets periodically with management, the internal auditors, and the independent auditors to review the activities of each and to discuss auditing, financial reporting, and the adequacy of internal accounting controls.

Because of inherent limitations in any system of internal accounting controls, errors or irregularities may occur and not be detected The company concludes, however, that it has established an internal control environment which meets high standards and believes that its system of internal accounting controls provides reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable.

1 T

30

Northeast Utikties and Subsidiaries AUINTORS' REPORT To the Board of Trustees and Shareholders of Northeast Utilities:

We have examined the consolidated balance sheets and consolidated statements of capita!ization of Northeast Utilities (a Massachusetts trust) and subsidiaries as of December 31, 1982, and 1981. and the related consolidated statements of income, common shareholders' equity and sources of funds for gross property additions for each of the three years in the period ended December 31,1982. Our examinations were made in accordance with generally accepted auditing standards and, accordingly, included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.

In our opinion, the financial statements referred to above present f airly the financial position of Northeast Utilities and subsidiaries as of December 31,1982, and 1981, and the results of their operations and the sources of funds for gross property additions for each of the three years in the period ended December 31,1982, in conformity with generally accepted accounting principles applied on a consistent basis subsequent to the change (with which we concur) in accounting for the allowance for funds used during construction as described in Note 1 of Notes to Consolidated Financial Statements.

ARTHUR ANDERSEN & CO.

Hartford, Connecticut, February 18,1983.

31

- Northeast Utihties and Subsidianes e umTED N OF N t

For the Years Ended December 31 1982 1981 1980 iThousands of Doilars.exces snarer iritarrnan #n, Operating Revenues . .

$1.763,220 $1,655.057 $1.324.545 Operating Expenses:

Operation -

Fuel. 464,654 511,776 420,138 Purchased and interchange power, net . 46,022 97,915 18.385 Gas purchased for resale . 147,637 111.651 89.366 Other . . .

378,358 322,973 267.853 Maintenance . 109,721 82.152 79.476 Depreciation. , 106,417 102.801 96.266 Federal and state income taxes (Note 4) . 113,712 67.552 46.835 Taxes other than income taxes.. 140,031 131.458 113.959 Total operating expenses. ,

1,506,552 1,428.278 1 132.278 Operating income. 256,668 226.779 192.267 Other income:

Allowance for equity funds used dunng construction . 52,096 32.658 26,070 Equity in camings of regional nuclear generating companies . 8,570 6,148 3.692 Other, net . (1,994) (2,999) 1.667 Income taxes applicabic to other income - credit.. 37,898 37,705 22.433 Net other income. 96,570 73.512 53.862 Income before interest charges . .. 353,238 300.291 246.129 Interest Charges:

Interest on long-term debt . , 175,866 158.883 120,588 Other interest. .

31,679 61,824 37.302 Allowance for borrowed funds used dunng construction, net of the income tax effect of $35.139.000 in 1982,

$35,361,000 in 1981 and $22,144.000 in 1980. (37,081) (42,146) (25.960)

Totalinterest charges. 170,464 178.561 131.930 Income af ter interest charges . 182,774 121,730 114,199 Preferred Dividends of Subsidiaries . .

31,532 26.612 25.447

- Net income., . ,,

$ 151,242 $ 95.118 $ 88.752 Earnings Per Common Share. . $ 1,76 $ 1 29 $ 1 31 Common Shares Outstanding (average) . .

85,777.230 73,783,201 67.555.006 9

T he .h ctoip.sorinj ruites are an iriitgral part (A these hnanaal staternents 32

Northeast Utilities and Subsidiaries i COMe;Ot.IDATED STATEIWlENTS OF SOURCES OF FUNDS  !

FOR GROSS PROPERTY ADDITIONS For the Years Ended December 31 1982 1981 1980

< rnousands or oona,s>

Funds Generated From Operations:

Net income. $151,242 $ 95,118 $ 88,752 Pnncipal noncash items:

Depreciation and nuclear fuel amortization . 154,722 142,191 126.988 Deferred income taxes, net . 50,989 17.329 25.842 Amortization of deferred charges and other noncash items.. 8,995 1,327 4.441 Amortization of energy adjustment clauses . 47,808 33.876 7.584 Allowance for equity funds used during construction. (52.096) (32.658) (26.070)

Total funds from operations. 361,660 257,183 227.537 Less~ Cash dividends paid on common shares. 110,650 87.064 74.311 Net funds generated from operations. 251,010 170,119 153.226 Funds Obtained From Financing:

Proceeds from issuance of:

Common shares . 107,843 88.257 14.047 Preferred stock . 39,054 14.453 24.680 Long-term debt . .

362,198 262.489 98.035 Proceeds from the sale of nuclear fuel to a third party trust (Note 6) . 230,400 - -

Increase (decrease) in short-term debt . (168,110) (111.691) 169.436 increase (decrease) in nuclear fuel payable . (26.900) 4.600 175 Total. 543,485 258,108 306.373 Less: Reacquisitions and retirements of long-term debt and preferred stock. 274.641 7.778 30.147 Net funds from financing . 268.844 250.330 276.226 Other Sources (Uses) of Funds:

Decrease t i ncrease) in net current assets (excluding short-term debt. long-term debt due within one year, preferred stock to be redeemed within one year and nuclear fuel payable)-

Cash and special deposits., 19,823 (6.471) (15.014)

Receivables and accrued utility revenues . (14,345) 3.890 (101,417)

Fuel, materials and supplies . (3,961) (20,948) (4.110)

Accounts payable . (53,984) 18.130 85.232 Accrued taxes. 17,503 21.371 (26)

Other net. (2,930) 7,745 1.949 Net change . (37,894) 23.717 (33.386)

Safe of utihty plant. -

5.636 -

Deferred unusual operating expense . -

(10.949) (4.034)

Energy adjustment clauses. net . 2,886 (11,700) (70.294)

Other. net . (3,040) (1,602) 1.886 Net other sources (uses) of funds . (38.048) 5.102 (105.828)

Total Funds For Construction From Above Sources. 481,806 425.551 323.624 Allowance For Equity Funds Used During Construction . 52,096 32.658 26.070 GROSS PROPERTY ADDITIONS. $533.902 $458.209 $349.694 0

Composition of Gross Property Additions:

Electric and other utihty plant. $475.294 $360.118 $262.500 Gas utility plant. 22,088 21.069 19.903 Nuclear fuel . 36,520 77.022 67.291 Total. $533,902 $458.209 $349.694 ine accornnangno noies are an intemaman e inese nnanciai statements 33

Northeast Utilities and Subsidiaries CONSOLENLTED BALANCE SWETS

(

At December 31, 1982 1981 i% sam or ouias Assets Utility Plant, at original cost:

Electric. . $3,037,882 $2,922,804 Gas. 222.460 198.222 O!her. , 33,926 35.959 3,294,268 3.156.985 Less: Accumulated provision for depreciation. 1,044,543 912.951 2,249,725 2.244,034 Construction work in progress (Note 8) . 1,223,578 894.078 Nuclear fuel, net of amortization (Note 6) . -

189.925 Total net utility plant . . 3.473,303 3.328.037 Other Property and Investments:

Investments in regional nuclear generating companies, at equity . 55,504 49.639 Other, at cost . 15,996 21.296 71.500 70.935 Current Assets:

Cash and special deposits. 4,177 24.000 Receivables, less accumulated provision for uncollectible accounts of $8.054,000 in 1982 and $4.920.000 in 1981. 196,127 184,715 Accrued utility revenues . 78,495 75,562 Fuel, materials and supplies, at averago cost. 130,021 126.060 Recoverable energy costs . - 35,768 Current portion of accumt.tated deferred income taxes . 6.168 -

Prepayments and other . 7,689 7.813 422,677 453.918 Deferred Charges:

Unamortized debt expense . 5,317 3,864 Energy adjustment clauses, net . 6,295 14,164 Canceled nuclear project (Note 3) . . . 14.397 21,468

, Deferred unusual operating expense (Note 3) . 10,089 14,301

! Other. 25,061 18.894 61,159 72.691 i Total Assets . , $4,028,639 $3.925.581 f

i

, The accompanying notes are an integrat part of these finanaal statements

, 34 4

Northeast Utilities and Subsidiaries i CONSOBJONTIID BALANCE SIMETS

~* l 1

At December 31 1982 1981 (Thousands of Dollafs)

Capitalization and Liabilities Capitalization:(See consolidated statements of capitalization)

Common shareholders' equity. $1,159,698 $1.013.205 Preferred stock not subject to mandatory redemption. 291,195 291,200 Preferred stock subject to mandatory redemption . 103.893 65,401 Long-term debt . . 1.894,542 1.608.272 Total capitalization . 3,449.328 2.978.078 Current Liabilities:

Notes payable to banks (Note 5) . .. . 19,800 79,500 Commercial paper (Note 5). 37,725 146.135 Long-term debt due within one year. 15,499 210.215 Preferred stock to be redeemed within one year . 568 1.200 Nuclear fuel payable . -

26.900 Accounts payabte . . 123,859 177.843 Accrued taxes . . 90,181 72,678 Refundable energy costs . 10,783 -

Current portion of accumulated deferred income taxes . -

13.824 Accrued interest. . . . 40,790 44.962 Other. 12,834 14.514 352,039 787,771 Deferred Credits:

Accumulated deferred income taxes. . 81,935 78,807 Accumulated deferred investment tax credits . 128,845 66.798 Other. .

16.492 14,127 227,272 159,732 Commitments and Contingencies (Note 8)

Total Capitallration and Liabilities . $4,028,639 $3.925.581 4

Ih9 3CCOfWany'UQ 00105 afe an integf al part Of these finanaai statements 35 I

Northeast Utihties and Subsidiaries CONSOI.IDATED STATEIMENTS OF CAPITAIJ2ATION At Decemta:t 31 1982 1981 Common Shareholders' Equity: Ghowands of Dui*5i Common shares. $5 00 par value-authorized 130.000.000 shares in 1982 and 100.000.000 shares in 1981; outstanding 89 497.740 shares in 1982 and 70.001.844 shares in 1981 (a) . $ 447,489 $ 395.009 Capital surplus. paid in 307,586 254,165 (

Retained earnings (b) . . 404.623 364.031 Total Common Shareholders' Equity. 1,159,698 1.013.205 Cumulative Preferred Stock of Subsidiaries: _

$50 par value-authonzed 9.000.000 shares, outstanding 6.910.495 shares in 1982 and 6,154.712 shares in 1981

$100 par value-authorized 550.000 shares; outstanding 500.000 shares in 1982 and 1981 Current Redemption Shares Dmdend flates Prices (c) Outstanding Not Subject to Mandatory Redemption: (d)

$50 par value-

$190 to $2 64 $ 50 50 to $ 54 00 1,824.000. 91.200 91.200

$3 24 to $3 80 $ 52 26 to S 53 05 1.099.925, 54,996 55.000

$4 48 to $4 80 $ 53 21 to $ 54 66 2.199,970, 109.999 110.000

$100 par value-

$7 72 to $9 60 $105 44 to $106 39 350.000. 35.000 35.000 Total Preterred Stock Not Subject to Mandatory Redemption. 291,195 291 200 Subject to Mandatory Redemption: (e)

$50 par va!ue-

$524 $ 55 24 500.000. 25.000 25.000 SS 52 $ 5414 320.355. 16.140 17.695

$5 76 5 5432 166.245. 8,321 8.906

$ 7.52 $ 57 52 800.000.. 40,000 -

$100 par value-

$16 00 $116 00 150.000. 15.000 15.000 104,461 66.601 Less preferred stock to be redeemed within one year . 568 1.200 Total Preferred Stock Subject to Mandatory Redemption . 103.893 65.401 Long-Term Debt:

First Mortgage Bonds-Maturity Interest Rates

. 1982 2-5/8% to 13-1/8% . -

154.810 1983 3 3/4% . 225 235 l . .

1984 2-3/4% to 3-1/8% . . 23.076 23.186 1985 3-1/4% . 20,000 20.000 l 1986 4-1/2% . .

9,600 9.600 4-3/8% to 5  %. 27,000 27,000

! 1987 1988-1992 3-7/8% to 17-3/4% . 243,040 183.920 1993 1997 4-1/4% to 11 -1/2% . 141.355 142.895 1998-2002 6-1/2% to 11  %. 469,512 472.500 2003-2007 7-1/2% to 91/4% . 285.000 285.000 2008-2012 9-1/4% to 15  %. 270.000 170.000 Total First Mortgage Bonds . . 1.488.808 1.489.146 Other Long. Term Debt-Mdistone 3 Construction Trust-variable interest rate (f) . 135,334 -

Pollution Control Notes-1984 1988 8% to 10% . 12,000 12.000 1998-2007 590%1o650%.. 27.650 27.650 l

l Notes-1982 8125% to 1125% .

40.000 1985 102% of the pnme rate . 30,000 30.000 40,000 50,000 1982-1986 1050%..

1988 1991 Prime rato 150,000 150.000 Miscellaneous . 30.328 23.726 Total Other Long-Term Debt. 425.312 333.376 ,

Unamortized premrum and discount, net . (4.079) (4.035)

Total Long-Term Debt (g) . 1,910.041 1.818.487 Less amounts due within one year . 15,499 210.215 Long-Term Debt. Net . , 1.894,542 1.608 272 Total Capitalization . $3.449,328 $2.978 0711 ine accompanytng notes are an integral part of these finanaat statements 36

Northeast Utilities and Subsidiaries CONSOE IDATED STATEMENTS OF CAPrIRIJZATION NOTES TO THE CONSOLIDATED STATEMENTS OF CAPITALIZATION i

(a) At December 31.1982 a total of 7,378.128 Changes in Preferred Stock Subject to common shares authonzed for issuance pursuant Mandatory Redemption to the Dividend Reinvestment and Common 8 "*S ad$ o' Do"am

~

Share Purchase Plan were unissued. Balance January 1 1980 $ '30,000 issues 25.000 (b) Northeast Utilities (NU) is restricted in the amount Reacquisitions and of dividends it may declare bv its long-term debt retirements (1.791) agreement At December 31 1982, approximately Ca!ance December 31 1980 53.209

$146.3 million of consolidated retained eamings 'ssues 15.000 was available for dividends. In addition, many of Reacquisitions and the consolidated subsidiaries of NU have retirements (1.608) dividend restrictions imposed by their long-term Balance December 31 1981 66.601 debt agreements. At December 31,1982, under issues 40.000 the respective agreements. there would be an Reai quisitior"- and aggregate total of approximately $161.8 million of reprements (2.140) consohdated retained eamings available for Balance December 31 1982 $104.461 dividends Ic) Dunng their respective initial five-year redemption af in March 1982 CL&P and WMECO entered into ion s Hnanang agensts to assist penods, each of these series is subject to certain refunding limitations Redemption prices reduce in n n ng of stme 3 wmu@on.

In future years W s ge a kn.pm to N Ws d the respective indentures, on CL&P s and (d) In 1982, $5.000 of preferred stock not subject to s inwests in Wsmm1 h Wsw 3 mandatory redemption was retired. There were no s M SMe, M Mgeng m law man N, N trust obkgations are to be repaid over a four-year changes during IS31 and 1980 in preferred stock not subject to mandatory reaemption. #"0 The trust, whose obligations are initially (e) The minirnum sinking-fund provisions of the

,w s h issWng up to $200 million of letter-of-credit (LOC)-backed series subject to mandatory redemption mmmercial paper and issuing up to $200 million agg egate $1.500.000 in each of the years 1983 through 1985. and $3,250.000 in 1986 and 1987.

of tenn notn Nnng M82 an Wst oNigams in case of default on sinking-fund payments, no w oug ssuan of WMaM commercial paper. Interest costs of $8 million payments may be made on any junior stock by

'" ""9 '" "

way of dividends or otherwise (other than in arrangement and were capitalized by CL&P and shares of junior stock) so long as the default contirtues. If a subsidiary is in arrears in the g a i ed W payment of dividends on any outstand:ng shares a was W W W of preferred stock, the subsidiary would be (g) Long-term debt maturities and cash sinking-fund prohibited from redempt;on or purchase of less requirements on debt outstanding at December than all of the preferred stock outstanding.

31 1982 are, for the years 1983 through 1987, as f nilows $15.499.000, $39.696.000, $70.257,000,

$29.896.000 and $37.306.000, respectively. In addition there are annual 1 percent sinking- and improvement-f und requirements, currently anuunting ta $ 12.854.000. $12.750.000.

Si2 706.000, $12.663.000 and $12.499.000 tor

, the years 1983 through 1987, respectively. Such sinking- and improvement-fund requirements may be satisfied by the deposit of cash or bonds, or by certification of property additions.

Essentially all of CL&P's and WMECO's utility plant is subject to the liens nf their respective first mortgage bond indentures 37

e Northeast Utilities and Subsidianes CONSOLIDATE]STiTEMENTS OF COMMON SHAREHOLDERS' EQUITY

(

Capital -

Common Surplus, Retained Shares Paid in Earnings Total (Thousands of collars)

Balance at January 1,1980. $332.970 $214.466 $341.553 $ 888.989 Net income for 1980. 88.752 88.752 Cash dividends on common shares - $1 10 per share. (74,311) (74.311)

Issuance of 1.618,356 common shares. $5 par value . 8.092 8 092 Excess proceeds over the par value from the issuance of 1.618,356 common shares. 5.955 5,955 Loss on the retirement of subsidiaries' preferred stock (17) (17)

Preferred stock issuance and retirement expenses (216) (216)

Balance at December 31,1980 341.062 220.205 355.977 917.244 Net income for 1981 95.118 95.118 Cash dividends on common shares - $118 per share. (87.064) (87.064)

Issuance of 10.789.528 common shares $5 par value. 53.947 53.947 Excess proceeds over the par value from the issuance of 10.789.528 common shares . 40,110 40.110 Common share and preferred stock issuance and retirement expenses (6,150) (6.150)

Balance at December 31,1981 395.009 254,165 364.031 1.013.205 Net income for 1982 151.242 151.242 Cash dividends on common shares - $1.28 per share (110.650) (110.650)

Issuance of 10.495.896 common shares. $5 par value 52.480 52.480 Excess proceeds over the par value from the issuance of 10.495.896 common shares 58.796 58.796 Common share and preferred stock issuance and retirement expenses (5.375) (5.375) l Balance at December 31,1982 $447.489 $307.586 $404.623 $1.159.698 l

[

l l

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1 r'e 3CCompanying no'es arc an antegral part Of these finanClal staternents 38

Northeast Utilities and Subsidiaries NOTES TO CONSOI.IDATED F8MANCIAL STATEMENTS

)

. 1. Summary of Significant Accounting Policies Revenues: Utility revenues are based on authorized rates applied to each customer's use of electricity or gas.

Principles of Consolidation: Northeast Utilities (NU. or ams can be measd ony Wwgh a fonnal proceedmg the company)is the parent company of the Northeast before the appropriate regulatory commission At the end Utilities system (the system). The consolidated financial ead accMng pM N aN Q amue an statements of the company include the accounts of all estimate for the amount of energy delivered but unbilled-wholly owned subsidiaries. Significant intercompany transactions have been eliminated in censolidation.

Nuclear Fuel: The cost of nuclear fuelis amortized to pcration expense on a unit-of-production method at Merger: Effective at the close of business on June 30, rates based on estimated kilowatt hours (kWh) of energy 1982, HELCO, a wholly owned subsidiary of UU, and The pr vided. The amortizat;on was $48,305.000 in 1982.

Corinecticut Gas Company, a wholly owned subsidiary of $39,390,000 in 1981 and $30.722,000 in 1980. (For details CL&P. were merged into CL&P The mergers were a cost d near W used ahr Deceme L accounted for as poofings of interests-1982. see Note 6.)

CL&P and WMECO recover through rates, with appropriate regulatory approval, an estimate for spent fuel Investments: CL&P and WMECO own common stock of disposal costs pertaining to nuclear fuel consumed.

four regional nuclear generating companies. These On January 7,1983, the Nuclear Waste Policy Act was companies with the system's ownership interest, are: .

signed into law. This act established procedures for the 44 0%

disposal by the United States Department of Energy connectirtit Yankee Atomic Power Company (CY) s,ww  ? ic, 9 , w rans y so, (DOEL of high level radioactive waste Funding of the faune unkee Atomic Power Company b 0% program Wili be provided by a 10 mit per kWh fee levied Vermont Yankee Nuclear Power Corporation 12.0% on electricity generated by nuclear power reactors after April 7 1983. In addition, for nuclear fuel used to generate The system s investments in these companies are electricity prior to April 7,1983. a fee is expected to be accounted for on the equity basis The electricity collected by the DOE no later than the time the spent fuel produced from these f acilities is committed to the .

is delivered to the disposal site. The present on-site participants based on their ownership interests and is nuclear waste storage facilities for the Millstone units, bitted pursuant to contractual agreements- ncluding facilities currently under construction at Millstone 3, are expected to be adequate until the time when the act requires a federal repository facility to be Public Utility Regulation: NU is registered with the available.

i Securities and Exchange Commission (SEC) as a holding The procedures for calculation, collection and payment company under the Public Utility Holding Company Act of of these fees have not been determined at this time.

1935, and it and its subsidiaries are subject to the Based on past regulatory practices, management expects provisions of the act Arrangements among the system that future recoveries of spent fuel disposal costs will be companies, outside agencies and other utilities covering adequate to satisfy any obligations under this act interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC The operating subsidiaries are subject to further regulation for rates and other matters by the FERC and/or their applicable state regulatory commissions, and follow

the accounting poliCles prescribed by the respective commissions.

e 9

39

Northeast Utilities and Subsidiaries NOTES TO CONSDLIDATED FINANCAL STATEMENTS

(

Depreciation: The provision for depreciation is commissions Beginning in 1981, substantiarly all of the calculated using the straight-line method based on timing differences were normalized. It is expected that, for ,

estimated remaining usefullives of depreciable utility years prior to the cdoption of normalization, the deferred plant in service, adjusted for net salvage value and taxes not provided for currently will be collected in removal costs as approved by the appropriate regulatory customers' rates when such taxes become payable (See agency Except for major facilities, depreciation rates are Note 4 for the detail of income tax expense )

applied to the average plant in service during the period Investment tax credits, which reduce federal income Major facihties are depreciated from the time they are taxes currently payable, are deferred and amortized over placed in service When plant is retired from service, the the usefullife of the related utihty plar t. An additional original cost of plant, including costs of removal, less investment tax credit of 1 percent is related to the Tax salvage, is charged to the accumulated provision for Reduction Act Employees Stock Ownership Plan depreciation. (TRAESOP) for the system's employees. Contnbutions to The depreciation rates for the several classes of TRAESOP do not affect net income, but are recorded as a electnc and gas plant in service are equivalent to the liabihty until the payment to the plan is made.

following composite rates:

ear Ele M c @ Allowance for Funds Used During Construction 28% (AFUDC): AFUDC represents the estimated cost of l9f 9 h5% 9 capital funds used to finance the system's construction 1980 34 30 program. These costs, which are one component of the total capitalized cost of construction, are not recognized Nuclear Decommissioning: A 1981 decommissioning as part of the rate base for ratemak:ng purposes until study indicates that immediate dismantlement of the facihties are placed in service. AFUDC is recovered over nuclear units at their retirement, with an estimated cost of the service life of plant in the form of increased revenue

$200 milkon in 1982 dollars,is the most viable and collected as a result of higher depreciation expense The effective AFUDC rates for 1982,1981 and 1980 economic method of decommissioning two nuclear units wholly owned by CL&P and WMECO. This estimate is were 91 percent,8 6 percent, and 7.9 percent, reviewed and updated periodically to reflect changes in respectively. These rates are calculated under the net-of-decommissioning requirements, technology and inflation. income tax method, following FERC guidelines, and Although a substantial portion of the estimated total include semiannual compounding.

decommissioning costs has been approved by regulatory Effective January 1,1980, the method of accounting for agencies and is reflected in the depreciation expense of AFUDC was changed from the gross-rate metnod to the CL&P and WMECO, the companies believe additional net-of-income tax method. The Connecticut Department revenues will be required to pay the full projected costs of of Public Utility Control (DPUC) granted CL&P approval decommissioning for the use of the net-of-income tax method in October 1980. Early adoption of this method for financial reporting purposes resulted in a reduction of net income of $11.9 income Taxes: The tax effect of timing differences million ($0.18 per share) for the period from January 1 (differences between the periods in which transactions 1980 to the approval date.

The net result of an AFUDC rate increase in 1980, affect income in the financial statements and the periods in which they affect the determination of income subject semiannual compounding and the early adoption of the net-of-income tax method had no material effect on net to tax)is accounted for in accordance with the ratemaking treatment of the applicable regulatory income for the year ended December 31,1980.

40

Northeast Utilities and Subsidiaries DIOTES TO CODISOI.NRATED IIIDIADICIAI. STATEWW.DITS

)

Retirement Plan: The company's subsidiaries participate For the 12-month period ended July 31,1982, the y

in a uniform noncontributory retirement plan covering all composite nuclear generation capacity factor was 74.1 regular system employees. It is the policy of the percent, resulting in tower fossil fuel costs of $20.6 million.

subsidiaries to fund annually the actuarially determined That amount is being refunded to customers on a monthly contribution, which includes that year's normal cost, the basis, throughout the period ending Jufy 31,1983, and, amortization of prior years' actuarial gains or losses over accordingly the balance is included in current liabilities.

WMECO's retail electric rates include a fuel adjustment 15 years, and the amortization of prior service cost over a clause under which forecasted fossil fuel, purchased period of 40 years. Total pension cost. part of which was charged to utility plant, approximated $25.942,000 in power and nuclear fuel costs are billed to customers currently. As permitted by the Massachusetts Department 1982. $24.200.000 in 1981 and $23.400.000 in 1980.

The actuarial present value of accumulated plan of Public Utilities (DPU), WMECO defers fuel costs until benefits and plan net assets available for benefits for the they are recovered quarterly under the adjustment clause.

In 1981. the Massachusetts legislature passed legislation system's plan are:

which established an annual performance program January 1. 1982 1981 related to fuel procurement and use. The current pcrformance program goals for WMECO cover the period Benefits June 1982 to May 1983. All of the revenues currently Vested . $264,185 $243.964 27.776 collected under the WMECO retail fuel clauso are subject Nonvested. 33.513

$271.740 to potential refund pending the DPU's review of WMECO's

$297.696 actual performance dunng the performance program Net assets ava:lable year. While WMECO quections the DPU's authonty to set for benefits.. $308,929 $300.704 erformance standards for plants not wholly owned or operated by WMECO, the company is essentially The assumed rate of return used to determine the operating within the present performance standards and actuarial present value of accumulated p!an benefits vos management believes that the likelihood of a significant 6.5 percent for 1982 and 1981, refund. as a result of this program,is remote.

Energy Adjustment Clauses: CL&P's retail electric and 2. Rate Matters-gas rates include adjustment clauses under which fossil in December 1982, the DPUC granted CL&P annual fuel and purchased power costs and purchased gas reWI && W p @ imeases d apieh costs above or below base rate levels are charged or $1011 million The totalincrease granted was 79.5 credited to customers As prescribed by the DPUC, most ercent of CL&P's amended request. The new rates went differences between CL&P s actual fossil fuel and. into effect on December 22,1982.

purchased gas costs and the current cost recovenes are During 1982, the DPU granted WMECO an annual rate deferred until future recovery is permitted. increase of $4.4 million. The level granted was 18 percent CL&P's retait base electric rates include a 70 percent of the $24 million WMECO sought in amended rate composite nuclear generation component. The DPUC has schedules The new rates went into etfect in June 1982.

approved the use of a ger'eration utilization adjustment WMECO filed new amended rate schedules with the clause which levels the effect on fuel costs caused by DPU in October 1982, requesting an annual revenue variations from a 70 percent composite nuclear increase of $24.1 mit! ion. WMECO a!so filed a petitien for generation capacity factor. When actual nuclear nterim rate relief of $5.3 million. If approved, the performance is above 70 percent, fossil fuel costs are ermanent rates are expected to become effective in May lower than expected, and when nuclear performance is 1983. Hearings on the permanent rate application ended below 70 percent fossil fuel costs are higher than in early March 1983. A decision on the intenm request expected. At the end of a 12-month period ending July 31 also is pending.

of each year, these net variations from the expected cost levels are refunded to or collected from customers over

~

the subsequent 11-month period.

41 I

i

r Northeast Utilities and Subsidianes NOTIIS TO CONSOI.It3ATIII) I:INANCIAL STATIIMIENTS -

(

3. Deferred Expenses Deferred income taxes are compnsed of the tax effects g mces as Mm g in December 1980, the system canceled the Montague nuclear project CL&P and V/MECO had a combined 1982 1981 1980 interest of 75 percent in the project The companies have gne sanas or oon,ys, received approval from applicable stata and federal Investment tax credits . $67,265 $ 19.098 $(8 489) regulatory authooties to recover project costs of Liberalized depreciation . 12.521 10.034 4 170

'U" 0 approximately $21.7 milkon through rates over a three- to '

four year period Project costs of $5.2 million not on s[ 9 settlement credits -

recoverable through rates were expensed dunng 1981. nuclear fuel . (1,668) (5 175) (917) in Apol 1981, Mdistone 1 concluded an extended Energy adjustment clauses., (21,733) (10.528) 25.186 refueling and inspection outage. Certain operation and unbilled revenues . (530) (1.659) (1.062) maintenance expenses totaling approximately $15 0 Spent nu ear fuel storage ac milhon were considered abnormal CL&P and WMECO Canceled nuclear project . (1,534) 6 838 (1.899) received permission from the appropnate state arid Deferred unusual operating federal regulatory authorities to recover the expenses expense. (2.965) 5 231 1 769 through rates over a three-year penod beg:nning in 1981. Other . (651) 483 (494)

Deferred income taxes, net . $50.989 $17.329 $25.842 The pnncipal reasons for the difference between total tax expense and the amount calculated by applying the

4. Int ome Tax Expense federalincome tax rate to pretax income are:

The detail of the federal and state income tax 1982 1981 1980 provisions is: (inoosanos at Duitarsi Expected tax at 46% of pr tax incona . $135,114 $8M $ 73 942 1982 1981 1980 Tax effect of differences:

Gnousands of DoNars) Add,tional depreciation for Currer.t income taxes tax purposes. (6,280) (6 314) (10266)

Federal . $ 4.634 5 6.401 $ (1.575) Allowance for equity funds State. 20,191 6.117 135 used during constroction Total current . 24.825 12.518 (1.440) -not recognized as Deferred income taxes. net income for tax purposes. (23,964) (15.022) (11 992)

Investment tax credits . 19098 Overhead costs of

! 67.265 (8.489) l federal . (11,715) 28.891 construction-expensed (2.661)

State. 892 5 440 f r tau purposes . - -

(4876) l (4.561) investment tax crec'.ts . (6.143) (4.664) (5.908)

Total deferred. 50.989 17.329 25.842 State tax. net of federal Taxes on debt portiun benefit . 8,440 3.785 3 011 of AFUDC. 35,139 35.361 22.144 Other,not. 3,786 *432

. 2.655 Total income tax Totalincome tax expense $110,953 $65.208 $46 546 expense. 110.953 65 208 46.546 Effective income tax rate . 38% 35% 29%

Less Income taxes (credits) included in other income. . (2.759) (2.344) _ (289) At December 31,1982, the system had unused and Total income taxes unrecorded investment tax credits of approximately $24 Charged to operating milhon, which are available to offset federal income tax expenses. $113,712 $67.552 $46 835 rovisions through 1997.

9

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42

Northeast Utilities and Subsidiaries NOTES TO CON 500.IDATED FINANCIAL STATEMENTS

)

6. Nuclear Fuel Financing w 5, Short-Term Debt in February 1982, CLd P and WMECO entered into The system companies use bank loans and commercial paper to finance the system's continuing arrangements with a :hiro party under which the Niantic construction program on a short term basis and to meet Bay Fuel Trust (NBFT) will own and finance up to $530 general working capital needs. The system companies million of nuclear fuel for Millstone 1 and 2 and the have bank credit lines totaling $48 million. Terms call for system's share of nuclear fuel for Millstone 3. The interest rates equal to the prime rate at the time of arrangements provide for CL&P and WMECO to make borrowing, and compensation for the lines is on the basis quarterly lease payments to NBFT for the cost of nuclear of commitment fees, compensating balances, or both At fuel consumed in the reactors plus financing costs December 31,1982 the average annual compensating associated with the fuelin the reactors. Upon discharge from the reactors, the nuclear fuel will be transferred to balance requirements totaled $2.3 million and annual comm:tment fees totaled $80,000. The credit lines expire CL&P ano WMECO.

at various times in 1983. Although these lines are During 1982. NBFT acquired the fuel for Mi!! stone 1 and 2 and the system's share of the fuel for Milfstone 3.

generally renewable, the continuing availability of the unused lines of credit is subject to review by the banks Bef ore it was acquired by NBFT, the nuclear fuel for involved. At December 31.1982, the amount of unused Millstone 1 and 2 had been financed by Northeast available borrowing capacity under the credit lines Nuclear Energy Company (NNECO) with bank loans, available to the system companies was $32.2 million. secured notes. capital contributions or advances from the in addition to their customary short-term borrowings company and the Waterford Fuel Supply Trust (WFST) from banks and from the sale of commercial paper, CL&P which owned the fuel until it was placed in the reactors.

Interest costs of $2,025,000 in 1982. $8.227,000 in 1981, and WMECO also have a joint credit line of $200 million, and $4,126,000 in 1980 were incurred in connection with pursuant to a revolving credit / term loan agreement, with financing the nuclear fuel and were capitalized by a group of banks. The maximum individual borrowing limits of CL&P and WMECO under the agreement are NNECO. The weighted average interest rate charged by

$200 million and $60 million, respectively. The companies the trust was 15.1 percent in 1982.17,8 percent in 1981 and 141 percent in 1980.

are obbgated to pay a commitment fee of three-eighths of On December 1,1982, the WFST was terminated and 1 percent per annum on their proportionate shares of the the nuclear fuel in Millstone 1 and 2 held by NNECO with daily average of the unborrowed portion of the aggregate commitment. At December 31,1982, CL&P and WMECO a book value of $1089 million was acquired by NBFT.

Pursuant to the transition rules for leases specified in had no borrowings under this agreement.

Statement of Financial Accounting Standards No. 71, CL&P also entered into a $50 million floating-rate Eurodollar revolving credit agreement with a group of " Accounting for the Effects of Certain Types of foreign banks in November 1982. CL&P is obligated to Regulation"(SFAS 71), this nuclear fuel feasing pay a commitment fee of one-quarter of 1 percent per arrangement is currently accounted for as an operatirg lease. Had it been accounted for as a capital fease, annum on the daily average of the unborrowed portion of the commitment At December 31,1982, CL&P had no assets and liabilities as of December 31,1982 would have increased by $267 million. On December 1,1982, borrowings outstanding under this agreement s

O 43

Nertheast Utikties and Subsidiaries NOTES TO CONSOIJINtTED I:INANCIAL STATEINENTS f

CL&P and WMECO began accruing rent expense under 8. Commitments and Contingencies this obligation to NOFT. This rent expense for the period December 1,1982, through December 31,1982 was $5.9 Construction Program: The system companies are L million, consisting of $4.7 milliori of nuclear fuel engaged in a continuous construction program and amortization and $1.2 m:lhon of interest expense. currently' forecast construction expenditures (including AFUDC but excluding nuclear fuel which will be leased) of $2 2 billion for the years 1983-1987, including $652 7 g million for 1983.

The construction program is subject to period:c review in addition to the nuclear fuel lease descnbed in Note 6, and revision, and actual construction expenditures m,1y the system companies have entered into lease vary from such estimates due to factors such as revised agreemerts for the use of substation equipment, data load estimates, inflation, revised nuclear safety processing and office equipment, vehicles, and office regulations, the availabikty and cost of capital, and the space. These leases are currently accounted for as granting of timely and adequate rate relief by regulatory operating leases pursuant to the transition rules specihed commissions, as well as actions by other regulatory in SFAS 71. Had the system companies capitahzed such bodies.

leases at the beginning of the lease terms, the effect on At December 31,1982, construction work in progress assets, liabilities, expenses, or net income would not be (CWIP) included an investment of $1.1 bilhon in jointly matenal. owned nuclear generating facihties, consisting of CL&P's Rental payments charged to operating expense and WMECO's combined 65 percent interest in Millstone 3 amounted to $16299.000 for 1982, $10.612,000 for 1981, of $1.0 bil' ion and CL&P's 4.1 percent interest in the and $10,923,000 for 1980. Seabrook nuclear project of $95.1 million. All the Future minimum rental payments under long-term companies owning undivided interests in these jointly noncancelable leases as of December 31,1982, owned facihties are required to provide financing to excluding executory costs such as real estate taxes, state support their own portion of construction costs.

!, use taxes, insurance, and maintenance, a'e A 1986 in-service date is planned for Millstone 3. The approximately: anticipated cost to CL&P and WMECO for inoir 65 anovsanos percent ownership share of the unit is $2.3 bilhon. This Period of oonarsi

' estimate is based on a review that was completed in t $ 0 September 1982.

, 1985 1S[600 CL&P and WMECO were parties to contracts expiring 1986 14,100 on December 31,1982, for the sale of interests 1987 10,200 representing an aggregate of 49.6 megawatts (MW) of After 1987 47.900 Millstone 3 to four other utility systems. On the basis of

$128.800 their recent reviews of the estimated cost of constructing Millstone 3 and their power supply needs, three of the utility systems permitted their contracts to lapse. These utilities had been committed to purchase an aggregate of 42.7 MW. The fourth utihty system has extended its contract through June 30,1983, but has reduced its commitment from 6.9 MW to 1.73 MW. CL&P and WMECO intend to continue their efforts to reduce their ownership interests in Millstone 3.

h 7

44

u ,

6 #g N ,

Northeast Utilities and Subsidiaries NOTES TO CONSOI.IDATED FINAMI:IAL STATEIWlENTS s

1

^ Nuclear insurance: The Price-Anderson Act current:y retroactive assessments if losses exceed tFe limits public liability from a single accident at a nuclea" accumulated funds available to NEIL. CL&P and WMECO power plant to $560 million. If the total damages resciting could be assessed an addqicnai $4.8 million based on from the accident exceed the private pool insurance their ownersh2p interests in these units.

coverage of $160 million, then CL&P and WMECO jointly would be required to pay a maximum of $15.1 million per accident, limited to a maximum of $30.2 million in any Financial Arrangements for the Region'al Nuclear calendar year, based on their ownership interest in those Generating Companies: The owners of CY, including nuclear reactors presently in service (i e. Millstone 1 and 2. CL&P and WMECO, have agreed to purchase their pro and the four regional r!uclear generating companies rata share of up to $40 million of CY's subordinated notes.

cesenbed in Note 1) CL&P's and WMECO's share of tne notes could CL&P and WMECO have purchased insuranca from aggregate $176 mi!! ion. As of December 31,1982, there Nuclear Electric insurance Limited (NEIL) to cover: (a) were no notes outstanding. The owners of CY, however, the extra costs incurred in obtaining replacement power could be called upcn to purchase notes in the futt're.

during a prolonged accidental outage with respect to their in December 1981. CY entered into two financing ownership interests in Mi!! stone 1 and 2 and CY; ar-1,(b) arrangements through which it could obtain $100 million the cost of repair or replacement of property and the cost of new debt, of which the owners o' CY have guaranteed of decontamination resulting from specified damages with their pro rata shares. The guarantees of CL&P and respect to their insurable interests at Millstone 1,2 and 3J WMECO under this arrangement could aggregate $44 Under each policy. CL&P and WMECO are subject to million.

retroactive assessments if losses exceed the The owners of Vermont Yankee Nuclear Power accumulated funds available to NEIL. The present Corporation, including CL&P and WMECO, have maximum assessments for CL&P and WMECO would be guaranteed their pro rata shares of a $40 million nuclear approximately $18 4 million under the replacement power fuel financing' The guarantees of CL&P and WMECO policy and $10 8 million under the property damage and aggregate $4 8 million.

decontamination liability policy. . The company expects that CL&P and WMECO may be '

CY, Maine Yankee Atomic Power Company and asked to provide additional capital and/or other types of Vermont Yankee Nuclear Power Corporation have also direct or indirect financial support for one or more of the purchased from NEll property damage and regional nociear generating compar..cs.

decontamination liability insurance, and are subject to M

e

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. _.. _ , . _ . . . _ _ - . . _ - - .__.- ~ _

2

' j Nortncast Uhl: ties and Subsidiaries 4

NOTES TO CONEOI.lDNFHD I:INANCIAL STATEWN3ns 4

.s 1, s 1

E

9. Segments of Business '

~

The followint) summan2es information relating to NU's eiectric snd gas operations: g, For the Years Ended December 31 1982 1981 1980 tThousands of Doilars) i Operating informatiord Operahng Revenues ~. '

Electric . . , ... . . .. $1,538.773 $1,473,789 $1.179.161 Gas . . ., . ... . . . .

224,447 181.268 145.384

^

Total - -

$1.763.220 $1.655.057 $1.324.545 Operating expenses exclu1ng provisions for income f ases-Electnc . .

', s . . '

. $1,194,841 $1.204.896 $ 958,340 197,999 127,103

~

Gas . . . 155.830 Total .. .. . . . .- .

$1,392.840 $1.360.726 $1.085.443

'  : Pretax operating income- _ '_

Electnc . . .. . . . .. . $ 343,932 $ 268.893 $ 220.821 xGas. . . < .n 26,449 25.438 18281

, Tctal . ... . ,

s . . ,' .. $ 370,380 $ 294.331 $ 239.102 f

Provissor) for inccme taxes--

- Ele.ctnc i . ~..~. . $ 106,290 $ 61,522 $ 43.477 Gas . . . . .. . .. ,, 7,422 6.030 3.358

$ 113,712 $ 67.552 $ 46.835

' ~

Total . . . . . .. .

Operabng incott es b Elecido , . . .e. ' .o . , $ 237,642 $ 207,371 $ 177,344 i ' '

Gas . '. . 3. 19.026 19.408 14.923 ,

i

. Total . . . . $ 256.668 $ 226.779 $ 192.267

. Depreciation expense-Electric . . .m. , .?.. . $ 100,623 $ 97.401 $ 91.255 5,794 5.400 5.011

, Gas . .

Tota! . .\ . . $ 106.417 $ 102.801 $ 96.266 b ,

- Capital et#pnditures-Elecing . . .. . . $ 511,814 $ 437,140 $ 329.791 Gac' 22,088 21.069 19.903

, Total . . . .

$ ,533,902 $ 458.209 $ 349694

- . 3 Investnlent ir.forrnation at December 31:

Ident. fable assets (.i)

Electocs . .- . . .. . . . $3.325,950 $3.192.206 $2.899.412

'186.483 169.792 154.057

' Gas . . .. . . . ... . .

P . Nin!hlocWe assets,. .. . .. . . . ,, 518,206 563.583 574.273 Total Assets. . . ,. .

$4,C28,639 $3.925.581 $3 627.742

~ -

. s-i  ! ,

.x l 4 ;

i i "

s

't

(@ includes construction work in progress. malenals and supplies. and a locatto common utility plant p.

46, .

g.

i f

---,e--, -s--,n-.- ~,-,,..,,-.,..,,.,.,,.,,v-.~ a w n .n- . , , , , , . . . . . . . , , , .---=---.---n - ---- , -- -- . . ,

.t ,

Northeast Utilhes and Subsidiaries NOTES TO C0005012NWED FINANCIAI. STK!TIWIEDITS i

10. Impact of Changing Prices (Unaudited) of nuclear fuel under both methods was adjusted based g on the system's present refueling cycle.

Introduction Fossil fuel inventories and the cost of fossil fuel used in generation have nut been restated from their historical The following stpplementary data presents certain o s ce mWa% a@mWs pd N m@g of information about the est. mated effect of inflation en the costs hgh N mrapn of a@stmmt dauses.

company's operations. Such data was prepared in ason, M Mmes am ansih metay accordance with the reqwrements of Statement of s Financial Accounting Standards No 33 (SFAS 33), her items included in the Statement of income were Financial Reporting and Changing Prices not adjusted because they were considered to be at The methodology prescnbed by SFAS 33 involves average pnce ievels for the year or were specifical!y numerous assumptians and estimates and, therefore, the excluded from adjustment by SFAS 33.

resulting informatico should be viewed as an r,pproximation of the ef'ects of inflation ratner than a preCfse 'ticasure Discussion The results of operations under both current cost and Constant Dollar and Current Cost constant dollar restattments show a not loss at a result of easM @mahm egnse m inkm-a@usW SFAS 33 established two methods for measuring the assets. M addition, the company will eventually have tu impacts oi i.Wation: constant dollar end current cost. rept ce :ts assets at a price many times greater than the Constant dottar amounts represent historical costs or gina' cost without having the opportunity to recover the stated in dollars of caual purchasing power, as measured m#aa met value of its assets through historical cost by the avera7,e level of the Consumer Price Index for a!! depreciation expense.

Urban Cor sumers (CPI-U) during the year. With the An adjustment to income taxes wou:d also be exception of CWIP, the data for plant was determined by n Ssay b mW N M mnoms ded of inHaMn.

applying the appropnate CPI U to the historical cost of n in me xad s nd abw N mwss plant. Constant Gollar restatement, therefore,is a measure depreciation and amortization expenses under constant of the effect of generalinflation at and cm cod acoWng as Whs in The current cost method adjusts for changes in determining federalincome taxes. As a result, the specific prices of plant from the date plant was placed in ehe tax Ws a@sW fu damn unN N cmdaN service to the present. Current cost does not necessarily ar and ment cost mms am W pmunt aN W represent the replacement cost of existing plant because percent respectively.These percentages substantially r

such plant is not axpected to be replaced precisely in exceed the statutory rate of 46 percent and the kind Current cost amounts differ from constant dollar company's 1982 effective tax rate of 38 percent.

amounts to the extent that specific prices have increased s of Mahn, Ws d nd meday more or less rapidly than the general rate of inflation. The assds se a bss of Wassg pown wm Ws d current cost was determined by indexing historical plant nel m netary liabilities experience a gain because debt using the Handy. Whitman Index of Public Utility will be repaid in dollars having less purcha%g power Construction Costs. Bcth the constant dollar and current The company's gain from the decline in purchasing cost amounts of land have been estimated by using the power of net amounts owed is attnbuted to the substantial CPIU ammnt d M wM was used to finance property, plant The current year's depreciatien expense for both and eWM Ms lain, is not maWah h N constant dollar and current cost methods was determined company and, therefore, cannot be considered additional by applying the company's operating subsidiaries, funds for reinvestment or dividend distnbution.

depreciation rates to adjusted piant amounts. Amortization O

e 47 7

Northeast utdities anti flohmtliane*,

NOTES TO CONSOt.IDATED FINANCIAL fil'ATEIWIENTS S

Statement of income Adjusted For Changing Prices For the Year Ended December 31,1982 i Conventional Constant Dollar Current Cost Historical Average Average Cost 1982 Dollars 1982 Dollars (b) tu.muns at Dani Operahng revenues . $1.763 $ 1,763 $1763 Operating espenses excluding depreciation and nuclear fuel amortitation. . 1.352 1,352 1.352 Depreciation and r'uclear fuel amortaation. 155 308 337 Interest expense . 170 170 170 Other n.come . 97 97 97 Preferred divniends of subs diaries . 32 32 32 Net income (loss) (a). $_15_t $ (2) $ (31)

Excese of increase in speofic prices ($300 milhon) over :ncrease in

he general price level ($234 milhon) after adrastment to net recoverable cost $102 Gain from acc'ine in purchasing power et net amourits owed. ,$_91 (a) Net inconie in 1982 would have been $70 5 m:ibon on a constant doriar t' asis and

$4 3 milhori en a current cost basis it the adjustment to net recoverable cost were included (b) At Decertber 31 1982 the current cost of fiwd assets. net of accumulated deprec6ation, was $6 3 b+on while historical cost. or net cost recoverable t augh depreciation *as $3 5 bill.un a

9 48

Nor'heast Utilities and Subsidiaries IllOTES TO N MAL N

)

-A Five-Year Comparison of Selected Supplementary Financial Data Adjusted for Effects of Changing Prices (in Average 1982 Dollars. Except Historical Amounts)

Years Ended December 31, 1982 1981 1980 19'I9 1978 Operating revenues:

Histoncal . . .. .. .. . ... ... ... . .. . . . $1,763 $1.655 $1.325 $1.074 $ 934 Constant dottar.. . .... ... .... ........... ....... .. .. . . 1.763 1.756 1.552 1.42S t.382 Net income (loss) (excluding adjustment to net recoverable cost):

Iti toncal.. .. .. . .... . . . . $ 151 $ 95 5 89 $ 81 Constant dollar. . .... . .. .... .. . .. ,. . .. . (2) (32) (31) (14)

Current Ccst . . . . ... . .... . ..... .. (31) (73) (49) (79)

Income (foss) per common share (after divide:1d requirements on preferred stock and excla.sdi.19 adjW. ment to net recoverable cost):

Histoncal . . .. .. ... .. .... . .. ... ... $ 1.76 $ 129 $ 1.3? $ 122 -

Constant dollar.. . .. .. . ..... .. .. ..... .. .. . . (.03) ( 43) (.46) (.21) ,

Current Cost . . . . . . . ..... ...... ....... .... ......... . (.37) (.98) (12) (1.19) i Net assets at year-end:

Historical . . . . .. .. ... .. .. . $1.160 $1,013 $ 917 $ 889 Constant dollar and current cost.. .. ..... . . 1,147 1.040 1.026 1.118 Amount by which the increase in general price level is greater than (or less than) the increase in specific prices af ter adjustment to net recoverable cost: '

Current cost . .. . . . . . . . ... .. $(102) $ 75 $219 $266 Gain from decline in purchasing power of net amounts owed.. . .. $ 91 $206 $286 $328 Cash dividends declared per common share:

Historical . . . .. ... . ... . $1.28 $1.18 $1.10 $1.06 $1.02 Constant dollar.. . ... ... . . . .. . . 1.28 1.26 1.31 1.43 1.51 Market price per common share at year-end:

H:sfoncal . ... . .... . .. .. . . .. . $12.13 $913 $8.00 $913 $900 Constant dollar. . . .. ..,,... . .... . ..., .. 11.99 9 37 8 95 11.47 12.83 Average consumer price inden. .. .. .... .. . . 289.1 272.4 246.8 217.4 1954 s

9 r 49

i Northeast Utilities and Subsidiarms SEIRCTE3 CONSOLIDATEJ PH8ANCIAL INLTA

(

1982 1981 1980 1979 1978 dhouwes of Duna

Net Generation. 20.339 20.118 20.872 19.716 20.736 Purchased And Net interchange . 883 1.999tb) 1.551 2.374 971 Company Use And Unaccounted For. (1.631) (1.560) (1 856) (1.605) I t .743)

Net Energy Sold. 19.591 20 557(b) 20.567 20485 19 964 Revenues: (thousands)

Resident .al. . $ 633.124 $ 584,322 $ 46R543 $ 3 M 864 5 343.824 Commerpa; 479.976 433 276 -336.?19 279.535 242.872 indatnal . 314.418 319.531 244.132 202.457 170 250 Othe' L.ikhes , 47.863 75.477 71.365 56.550 46.524 Streehy ting. . 23,726 22.118 18.503 15.679 14 414 Miscellaneous . 23.114 24.848 17.004 15 661

_ 21.971 1 ctat tilectnc. 1.522.223 1.456.695 1.164.110 958.089 833.545 Cthct 16.550 17.094 15.051 10.330 7.827 Totai . $1.538.773 $ 1.4 73.789 $1.179.161 $ 968.419 $ 841.372 Sales: (kWh - milhons)

Residential. 7.342 7.447 7,492 7.436 7.315 Commercial . 6.166 6 006 5.855 5.728 5.585 incastrial . 4.871 5.287 5.233 5.328 5.097 O!ner Utmties . 1.035 1.638(b) 1.801 1.806 1.778 Streett.gnting. 177 179 186 187 189 19.591 20.557(b) 20.567 20.46.; 19 964 T ot al .

Customers: (average)

Residentia!. . 991,069 979.963 969.698 957.417 941.763 Commercial . 88.315 87,480 87.055 86.584 85.790 5.004 5.036 5.016 5.040 5.087 industnal .

2.398 2.315 2.301 2.340 2.382 Other .

Total . 1.086.786 1.074.794 1.064.070 1.051.381 1.035 022 Average AnnualUse Per Residential 7,361 7.548 7.664 7.659 7.648 Customer (kWh). .

Average Annual BHi

$634 71 $592 29 $479 26 $398 43 $359 51 Per Residential Customer .

Average Revenue Per kWh:

8.62C 7 85C 6 25C 5 20C 4 70C Residential. .

7 78 7.21 5.75 4 88 4 35 Commercial .

6.45 6 04 4 67 3.80 3 34 Industnal . .

(a) Generated in system and regional nuclear generating plants (b) Sates to Connect. cut Municipal Electnc Energy Cooperatn,e. a pewwr eupNy agency for three rnunicipal systems in Connecticut, have been shown as sales to otner utilities en penods poor to '

October t .121 Comrne,ncing on October 1,1981. these sa!es have teen recorded as purchased and net tr:terchange power delivered 52

Northeast Utilities and Subsidiarics

. dAS WM STATISTICS 1982 1981 1980 1979 1978 4

Source of Gas (Mcf-thousands) 24.809 Purchased. . . . ..... ... . 29.263 23.158 28.342 26.048 464 573 410 454 358 Produced. .. ...... ...... .

Company Use And Unaccounted For . . ...... .. . ... (810) (702) (1206) (936) (1.468) 28.917 29.029 27.546 25.566 23.699 Net Sold. . . . .. ..... ... . .........

Maximum Day Sendout

.. .... 2.068 2.C36 1.854 1.772 1.467 (M -Therms). . .

Ravenues: (thousands)

Aesidentia'.. . .. . .. . $ Ji,115 $ 75.500 $ 61.472 5 48.221 $ 45.900 58,189 44.143 31.772 21.472 19.383 Cornmecia' . . . . . .

69.350 59202 47.053 34.140 25.004 industnal . .

7.293 2.323 0.C87 2.133 2.008 Miscellaneous .. . . .. .. ..

$224.447 $181268 $145.384 $105.966 $ 92.385 Total . . . . .. ..

Sales: (Mcf-thousands) 10.003 10299 Residentia!. . ... . .. .. .. .... . 10.294 10.532 10.174 7,722 7.103 6.075 5.175 4.973 4

Commercial .. . .... . .. ....

10,886 11.378 11278 10.374 8.075 Industnal . . . .. . ... .

15 16 19 14 352 Other. . ... . .. . .... .. .

28.917 29.029 27.546 25.566 23.699 Total . . .. ..... . .

t i

i Customers: (average) 137,204 135.992 134.075 131.634 131.036

Resident #al. . . , . . .... ...

13.829 13.605 13.202 12.617 12222 Commercial . . . . . ..

1274 1273 Industnal . . .. ... . ... 1.296 1.304 1297 152.329 150.901 148.574 145.525 144.531 l Total . .. .. . . . . ... .. .

Average Annual Use Per Residential 76 0 78 6 75.0 77.4 75.9 Customer (Mcf) .. ... .. . . .

Average Annual Bill $350 97

$685.95 $555.18 $458.49 $366.33 Per Residential Customer .. . . . .. .

4 Average Revenue Per Mcf:

$9.14 $ 7.17 $6.04 $4.82 $4.47 Residential.. . .. ... . ..

3.90 Commercial . ... . .. ... . . ... . 7.54 621 523 4.15 6.42 5 21 4 17 3 29 310 industnal . . .. .. .. .

53

7 Northeast Utihties and Subsidiaries CONSOLIDATE] STATEMENTS OF QU ARTEZLY FINANCIAL DATA (Unaud.tedj

(

Ouarter Ended 1982 March 31 June 30 September 30 December 31 (Thousands of Dollars encept pet share daiai Operating Revenues . $522,634 $396.266 $404.486 $439.834 Operating income. S 82.250 $ 51.456 $ 60.863 $ 62.099 Net income . $ 50.613 $ 24.739 $ 37,233 $ 38.657 Earnings Per Common Share. $0 29 $0.42 $0 41

$_0_64 _

1991 ._

Opera *,ng flev ws . $455 651 $375 SM $400 282 $423 270 Operating income. $ rA381 $ 4890 $ 53134 $ o0 274 Net locorT,a . 3 32.415 $ '> '.71 $ 18.883 $ 23n!4 Eam.ngs Per Common Share. $047 $0 21 10 2'1 $0 34 COMMON SHARE INFORMATION The common shares of Northeast Ut.hties are listed on the New York Stock Exchange The ticker symbol is "NU, although it is frequently presented as "Noest Ut' in various financial pubkcations There were approximately 201,269 common shareholders of record of Northeast Utihties at January 31,1983.

The annual market price range of common shares is included with the Selected Consol. dated Financial Data on page 50. The high and low sales prices and dividends paid for the past two years by quarters are shown below Quarterly Dividend Year Quarter High Low Per Share 1981 First 94 8 $0295 Second 9% 84 0.295 Third 9% 8W 0295 Fourth 9% 84 0 295 1982 First 10% 8% 0.320 Second 11 9% 0.320 Third 11 % 9% 0.320 Fourth 12% 10% 0.320 The Connecticut Bank and Trust Company Stock Transfer Department One Constitution Plaza.

Hartford, Connecticut 06115 and State Street Bank and Trust Company, Corporate Stock Transfer Department. 225 Frankhn Street, Boston, Massachusetts 02107, have been appointed Transfer Agents and Registrars of NU common shares. The Connecticut Bank and Trust Company is the company's g dividend paying agent and administers the company's Dividend Reinvestment and Common Share Purchase Plan 54

SECURITIES AND EXCHANGE COMMISSION Washington D. C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1982 Commission file number 2-30057 CANAL ELECTRIC COMPANY (Exact name of registrant as specified in its charter)

Massachusetts 04-1733577 (State or other jurisdiction of (l.R,S. Employer inccrporation er organization) Identification No.)

1 l 675 Mtc sacnusetts Avenue, Cambridge, Massachusetts 02139 _

( Addrcss of principal e>.cr.utive offices) (Zip Code) i Registrant's telephone number, including area code 617 - 864 5100 Securities registered pursuant to Section 12(b) of the Act:

! Name of each exchange on i Title of each class which registered Ivone None Securities registered pursuant to Section 12(g) of the Act:

i j None j (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, and (2) has been subject to such filing requirements for the past 90 days.

Yes X No Shares of common stock outstanding at March 15, 1983 1,523,200 Documents incorporated herein by reference - None Exhibit index begins on page 33 of this report.

i I

i i

CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 PARTl.

Item 1. Business Canal Electric Company (the " Company"), a wholly-owned subsidiary of Commonwealth Energy System (" System"), is a wholesale electric generating company organized in 1902 under the laws of the Commonwealth of Massachusetts.

The Company assumed its present corporate name in 1966 after the sale to an affiliated company of its electric distribution and transmission properties together with the right to do business in the territories served. The System together with its subsidiaries is sometimes collectively referred to as the "Tystem" .

The Company's generating station is located in Sandwich, Massachusetts at the eastern end of the Cape Cod Canal. The station consists of two oil-fired steam electric generating units: Canal Unit No.1, with a rated capacity of 568 MW, is wholly-owneci by Canal; and Canal Unit No. 2, with a rated capacity of 584 MW, is jointh owned by Canal and Montaup Electric Company (a non-affiliated company). Canal Unit No. 2 is operated under an agreement with Montaup which provides for the equal sharing of output, fixed charges and operating expenses.

Construction of Unit No.1 was completed in 1968 and Unit No. 2 commenced commercial operation February 1,1976. The Company also participates as a joint-owner in other generating units being constructed by another New England utility.

By virtue of its charter, which is unlimited in time, the Company generates and sells electricity at wholesale to other utilities without direct competition in kind from any privately or municipally owned utility.

Power Contracts The Company has entered into substantially identical life-of-the-unit power contracts with Boston Edison Company, Montaup Electric Company and New England Power Company (neighboring utilities), under each of which the customer is severally obligated to purchase one quarter of the capacity and energy of Unit No.1, and with Commonwealth Electric Company (" Commonwealth Electric") and Cambridge Electric Light Company (" Cambridge Electric"), both distribution subsidiaries of the System, under which the two are jointly obligated to purchase the remaining one quarter of the unit's capacity and energy.

A similar contract is in effect between the Company and Commonwealth Electric and Cambridge Electric, under which those companies are jointly obligated to purchase the Company's entire one-half share of the net capability of Unit No. 2.

The price of power under the power contracts is based on a two part rate consisting of a demand rate and an energy rate. The demand rate

I CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 Item 1. Business (Continued)

Power Contracts (Continued) covers all expenses except fuel costs and provides for a return on investment as well as recovery of investment over the economic lives of the units. The energy rate is based on the cost of fuel and is billed to each purchaser in proportion to its consumption of power. Purchasers are billed monthly. The power contracts are on file with the Federal Energy Regulatory Comm!ssion ,

("FERCd).

New England Power Pool The Company is a member of the Nesv England Power Pcol ("NEPOOL"),

whose centrai dispatchirig facility ("NEPEX") coordinates the operation of '

essentially all of the generation and transmission facilities in New England.

Under its Irmg-range program, NEPCOL wi;l enable member utilities to install fewer but far(;er, trore efficient generating units and higher voltage transmission lines for the purpose of obtaining lower cost power an'i increared reliability.

'Jrier NEPEX, the most economically available generating units of member compsnies are operated to fill the demand for power in the region. In the past, this has requireci that Unit No.1 operate whenever possible since it is one of the most efficient oil-fired units in the country. Unit No. 2 is designed for cycling operation which provides for economic changes in unit load permitting reduced generation during nights and weekends when demand is lowest. It has performed as one of New England's most efficient units in this type of service.

The Company and the System's other electric subsidiaries are also members of the Northeast Power Coordinating Council ("NPCC"), an advisory organization which establishes criteria and standards for reliability and serves as a vehicle for coordination in the planning and operations of these systems to enhance reliability.

Regulation i

The Company is subject to regulation by the Massachusetts Department of Public Utilities ("DPU") as to the issuance of securities, accounting, and other matters. The Company is a "public utility" within the meaning of I Part 11 of the Federal Power Act and is subject to regulation thereunder by the FERC as to rates, accounting and other matters and has filed its power contracts with the FERC as rate schedules.

i I

I i

CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 Item 1. Business (Continued)

Fuel Supply Effective January 1,1981, the Company negotiated a long-term contract with Charter Oil (Massachusetts) Inc., for the purchase of the total estimated requirements of residual fuel oil for Unit No.1 and Unit No. 2. This contract will expire on June 30, 1985.

During 1982 the Company maintained an average daily inventory of approximately 485,000 barrels of fuel oil which represents 14 days of normal operation of the two units. This supply is maintained by regular tanker deliveries.

Mure Generating Plant Commitments The Company is a joint-owner in Seabrook's nuclear electric generating units which are being constructed by Public Service Company of New Hampshire

(" PS N H " ) . The units will have a totat plant capacity of 2300 T4W of which the Company will own approximately 81 MW or 3,52%, The Company's total cost of entitlement is presently estimated at approximately $200,000,000 of which

$67,207,000 had been expended through December 31, 1982. Estimated completion dates for Unit 1 and Unit 2 are 1984, and 1987, respective!y.

The cost estimates and completion dates are based upon the latest information made available to the Company by PSNH and include the estimated cost of nuclear fuel and allowance for funds used during construction

("AFUDC"). The completion dates reflect delays encountered to date by PSNH which have resulted, in part, from government licensing requirements, financing, environmental, legal and other problems. In addition, there has l

been particular public controversy concerning development of nuclear energy, which may cause further delays in completion of this project and the operation of existing plants.

For additional information concerning the Seabrook units see the " Construction and Financing" section below and Note 6 of Notes to Financial Statements filed under item 8 of this report.

l l Construction and Financing i

The Company has made substantial commitments in connection with its construction program. Estirrated construction expenditures for the five-year period ending in 1987 are $117,000,000. Approximately $113,000,000 or 97% of this amount is applicable to the Company's investment in the jointly-owned Seabrook nuclear generating units. The Company purchased its interest in these units from affiliate Commonwealth Electric Company on December 31, 1981 for approximately $52,330,000 (book value net of related taxes). For additional information concerning the Company's construction program and future expenditures refer to. Note 6 of Notes to Financial Statements filed under item 8 of this report.

i i

l CAN AL ELECTRIC COMPANY FORM 10-K DEC EMB ER 31, 1982 Item 1. Business (Continued)

Construction and Financing (Continued)

During the five-year period ending December 31, 1987, it is estimated that internally generated funds will provide approximately $53,000,000 for construction. The balance will be provided on an interim basis by short-term borrowings which are expected to be reploced by long-term debt and equity securities, and internally generated funds. ,

Financings presently clanned for the period ending Deccmber 31, 1987 include $30,000,000 of loc.g-term debt issues, $5,000,000 in the form of a nuclear fuel lease and $30,000,000 from tw sale af equity securities to the System. The exact type, timing and amount of future long-te m debt end equity financings are subject to change becaura of market conditions and other factors.

Environmental Matters The Company's gener.iting facilities are subject to Federal, state and loca! environmental quality control regulations. With respect to Unit No.1 and Unit No. 2, these regulations have required capital expenditures by the Company of approximately $16,500,000. Environmental regulations limit the sulphur content of oil burned to 2.2%.

Future compliance with existing regulations will require capital expenditures by the Company through 1987 of an estimated $10,100,000 including approximately $6,300,000 for the Company's proportionate share of such costs to be incurred in connection with the Seabrook project. These amounts have been included in the construction estimates discussed under

" Construction and Financing".

Environmental regulations which govern both the site selection for new electric generating facilities and air and water pollution standards which require the installation of costly pollution control facilities have had and may continue to have an effect upon the capital costs and construction schedules of NEPOOL generating facilities. The increases in cost cannot be predicted, since the standards and the technology required to meet them are in a state of rapid change. There has been particular public controversy concerning development of nuclear energy. Despite the safety record of the nation's nuclear power plants, these plants have become the target of certain groups claiming, through litigation or intervention in regulatory proceedings, that the present state of nuclear tecnnology presents unacceptable risks to public health and safety and the environment. These claims may cause delays in, or interfere with, scheduled construction of new nuclear plants.

Although the Company is not aware of any existing or proposed environmental regulations having a significant effect upon its electric business, it is unable to predict the possible effect on capital expenditures or earnings resulting from regulations which may be adopted in the future.

CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 Item 1. Business (Continued)

Employees The Company has 100 regular employees, 70 of whom are represented by the Utility Workers' Union of America, A.F.L.-C. I .O. The existing collective bargaining agreement expires May 31, 1983. Employee relations have generally been satisfactory.

Item 2. Properties 1

The Company operstes a generating station located at the eastern end of the Cape Cod Canal in Sandwich, Massachusetts. The station consists of two oll-fired steam electric generating un!ts: Canal Unit No.1 with a rated capacity of S68 MW, which is wholly-owned by Canal; and Canal Unit No. 2, with a rated capacity of 584 MW, wnich is jointly owned by Canal and Mcntaup Electric Company.

Item 3. Legal Proceeding The Company is not a party to any pending material legal proceedings.

Item 4. Submission of Matters to a Vote of Security Holders None 4

] CAN AL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 PART ll.

Item 5. Market for the Registrant's Common Stock and Related Security Holder Matters (a) Principal Market Not applicable. The Company is a wholly-owned subsidiary of Commonwealth Energy System.

(b) Number of Shareholders at December 31, 1982 One (c) Frequency and Amount of Dividenos Ceclared in 1932 ano 1981 1982 1981 Per Share Per Share Decia.'aticn Date Amount Declaration Date Amount April 30,1982 $ 1.30 April 27,1981 $ 1.00 July 2S,1982 1.25 July 27, 1981 1.00 October 25, 1982 1.25 October 23, 1981 1.00 December ~l6,1982 1.50 December 18, 1981 1.25 ,

$ 5.30 $_4 25 Reference is made to Note 4 of Notes to Financial Statements filed under item 8 of this report for restriction against the payment of cash dividends.

(d) Future dividends may vary depending upon the Company's earnings and capital requirements as well as financial and other conditions existing at that time.

Item 6. Selected Financial Data

- 1982 1981 1980 1979 1978 (in Thousands Except Common Share Data)

Operating Revenues:

Electric $213 109 $229 457 $197 256 $141 976 $110 769 Net income $ 7 957 $ 6 731 $ 6 361 $ 5 919 $ 6 027 Common Share Data -

Earnings per share $ 5.22 $ 4.42 $ 4.18 $ 3.89 $ 3.96 Dividends declared per share $ 5.30 $ 4.25 $ 4.20 $ 3.70 $ 3.85 Common shares issued and outstanding 1 523 200 1 523 200 1 523 200 1 523 200 1 523 200 Total Assets $182 662 $170 310 $143 684 $122 377 $118 498 Long-Term Debt Out-standing $ 47 604 $ 48 367 $ 49 130 $ 49 893 $ 50 562 Common Share investment $ 53 756 $ 53 372 $ 53 615 $ 53 651 $ 53 368

CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Regulation The Company is a wholly-owned electric generating subsidiary of Commonwealth Energy System (the " System") and is subject to the jurisdiction of the Federal Energy Regulatory Commission with respect to the establishment of rates affecting wholesale electric sales. The Company is also subject to regulation by the Massachusetts Department of Public Utilities as to issue of securities, accounting and other matters.

Ceitol itesources At December 31, 1982, the Company had short-term notes payable outstanding totating $50,650,000 which were used to temporarily finance construction and working capital requirements. Interim and permanent financing is done by tha Company, with the System provic:ing, when available, a portion of the Company's short-term financing needs through advances and by purchasing 100% of any new common equity issue.

The Company is also a member of the COM/ Energy Money Pool (the

" Pool"), an arrangement among the utility and non-utility subsidiaries of the System, in which short-term cash surpluses of all subsidiaries may be used to meet the short-term borrowing needs of the Company. Lenders to the Pool, in general, receive a higher rate of return than they otherwise would on such investments. Borrowers from the Pool pay a lower interest rate than they l would otherwise pay to banks and, as a result, the Company has a reduced l need of bank lines of credit.

The Company has made substantial commitments in connection with its construction program. Forecasted construction expenditures for the five-year l

period ending in 1987 are $117,000,000 including $113,000,000 applicable to the l Company's 3.52% joint-ownership in the Seabrook nuclear generating units.

Financing this program will require a long-term debt issue of $30,000,000 with an additional $5,000,000 to be arranged under the terms of a nuclear fuel leasing agreement and a $30,000,000 equity investment by the System. The exact type, timing and amounts of future long-term debt and equity financings are subject to changes in market conditions and other factors.

l Liquidity l The Company's ability to generate adequate cash to meet its neec:s results primarily from the wholesale sales of electric energy through life-of-the unit l power contracts with several affiliate and non-affiliate utilities. Additional sources include periodic short-term borrowings from banks and advances from l affiliate companies. Although the Company is projecting significant capital l requirements during the next five years for its constuction program, internally l generated funds are expected to provide $53,000,000 or approximately 45% of these requirements. In keeping with a sound capital structure, short-term

borrowings are, from time to time, permanently financed through debt and

! equity issues.

1 l

- - _ _ _ - -. - - - . . _ . _ - - _ - _ _ _ - = -. .-

, . i CANAL ELECTRIC COMPANY  ;

FORM 10-K DECEMBER 31, 1982 i

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

Results of Operations For the Years Ended December 31, 1982 1981 1980 .

j (Dollars in Thousands)

! Electric operating reve;nues $213 109 $229 457 $197 256 i

j Costs and Expenses:

Fuel oli used in production 174 930 192 325 161 72?

Other operation 9 000 8 805 6 882 -

l Maintenance 8 675 7 268 7 705 Interest 2 929 4 165 4 299 incorne taxes 5 398 6 706 6 459 i All other 7 058 7 022 6 630 Total 207 990 226 291 193 697 Other income 2 838 3 565 2 802 1

j Net income $,l_%1 $ 6 731 $ 6 3S1 ,

Cash dividends declared on common stock paid to Commonwealth Energy System (Parent Company) $ 8 073 $ 6 474 $ 6 392 Number of common shares outstanding 1 523 200 L523 200 1 523 2qQ Operating Revenues and Expenses Operating revenues decreased by $16.3 million or approximately 7.1%

from 1981. The power contracts for the sale of the capacity of the Canal units provide for the recovery of all operating expenses and fixed charges (including a return on equity) whether or not the units are operating.

Variations in revenue result from changes in operating expenses, primarily the cost of fuel oil and to a lesser degree from changes in the length of

outages for scheduled maintenance. Such variations have no effect on net l income. Fuel expense is the Company's singie most significant operating cost,

! representing over 82% of the total revenue dollar. The per barrel cost of oil averaged $P,6.28 in 1982, $28.59 in 1981 and $22.57 in 1980.

Inflationary pressures on material costs and wages contributed to the

< increase in other operating expenses. Maintenance expense increased approximately j 19.4% due primarily to the replacement of generation coils for Unit 1 during the first quarter.

Other Income and Interest Charges The decrease in other income was largely due to a reduction in interest income due to the absence of funds available for short-term investments and f

to a lesser extent to a lower level of interest income accrued on income tax

1 CANAL ELECT RIC COMPANY FORM 10-K DECEMBER 31, 1982 f tem 7. Mangement's Discussion and Analysis of Financial Condition and Results of Operations (Continued) issues. These factors were offset by an increase in allowance for equity -

funds used during construction, reflecting the increased construction activity resulting from the Seabrook project.

Interest charges on short-term borrowings increased due primarily to the higher level of borrowings required to finance the Seabrook project. However, total interest charges for 1982 declined 29.7% due primarily to an increase in allowance for borrowed funds used during construction.

Item 8. Financial Statements The Compar y's financial statements required by this item are filed herewith on pages 11 through 27 of this report.

Item 9. Disagreements on Accounting and Financial Disclosures None CANAL ELECTRIC COMPANY F_O R M 10- K DECEMBER 31, 1982 ltem 8. Financia! Statements REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Canal E!ectric Company:

We have examined the balance sheets of CANAL ELECTRIC COMPANY (a Massachusetts corporation and wholly-owned subsidiary of Commonwealth Energy System) as of December 31,1982 and 1981, and the related stateme its of income, retained earnings and sources of funds used for construction for each of the three years in the perled ended December 31, 1982. Our examinations were made in accordance with genet ally accepted auditing standards and, accordingly, included such tests of the accounting records and such other auditing procedures as we considerad necessary in the circumstances.

s in our opinion, the financial statements referred to above present fairly the financial position of Canal Eiet.1ric Cor.1pany as of December 31, 1962 and 1981, and the results of its operations and its sources of funds used for construction for each of the three years in the perioc* ended December 31, 1982, in conformity with generally accepted accounting principles applied on a consistent basis.

Our examinations were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index to financial statements are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the examinations of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

ARTHUR ANDERSEN & CO.

Boston, Massachusetts, February 14, 1983.

f INDEX CANAL ELECTRIC COMPANY INDEX TO FINANCI AL STATEMENTS AND SCHEDULES PART ll.

FIN ANCI AL STATEMENTS Balance Sheets at December 31,1982 and 1981 Statements of Income for the Years Ended Decemoer 31,1?S2,1981 and 1980 Statements of Retained Earnings for the Years Ended December 31, 1982, 1981 and 1980 Statements of Sources of Funds Used for Construction for the Years Ended December 31, 1982,1981 and 1980 Notes to Financial Statements PART IV.

SCHEDULES V Property, Plant and Equipment for the Years Ended December 31, 1982,1981 and 1980 VI Accumulated Depreciation of Property, Plant and Equipment for the Years Ended December 31,1982,1981 and 1980.

IX Short-term Borrowings for the Years Ended December 31, 1982, 1981 and 1980 SCHEDULES OMITTED All other schedules are not submitted because they are not applicable or required or because the required information is included in the financial statements or notes thereto.

I BALANCE SHEETS CANAL ELECTRIC COMPANY BALANCE SHEETS DECEMBER 31,1982 AND 1981 ASSETS 1982 1981 (Dollars in Thousands)

PROPERTY, PLANT AND EQUlPMENT , at original cost: $131 806 $131 100 Less - Accumulated depreciation 47 025 42 196 Accumulated deferred taxes 13 283 15 463

_71 498 73 441 Add - Construction work ir p" ogress, not (Notes 2 and 6) '7 800 53 G34 149 298 127 275 CURRENT ASSETS:

Cash 52 384 Accounts receivable -

Affiliated companies 10 999 12 703 Other 15 456 17 826 Unbilled revenues 130 -

Prepaid property taxes 915 915 income tax refund receivable 1 430 6 436 Electric production fuel oil, at average cost 2 576 2 667 Other 492 896 32 050 41 827 DEFERRED CHARGES, net 1 314 1 208

$182 662 $170_3L0 The accompanying notes are an integral part of these financial statements.

BALANCE SHEETS (Continued)

CANAL ELECTRIC COMPANY BALANCE SHEETS DECEMBER 31,1982 AND 1981 CAPITALIZATION AND LI ABILITIES 1982 1981 (Dollars in Thousands)

CAPITALIZATION:

Common Equity -

Common Stock, $2S par value -

1 Authorized and outstanding -

1,523,200 shares, wholly-cwned by Cornmonwealth Energy System (Parent) $ 38 080 $ 38 080 Amounts paid in excess of par va!us 8 321 8 321 Retained earnings 7 355 7 471 53 756 53 872 Long-term debt, including premiums, less current j sinking fund requirements 47 604 48 367 4

101 360 102 239 i CURRENT LI ABILITIES:

interim Financing -

l Notes payable to banks (Schedule IX) 44 250 22 500 l Advances from affiliates 7 205 3 375 t

51 455 25 875 Other Current Liabilities -

{ Current sinking fund requirements 920 892 l Accounts payable -

i Affiliated companies 659 862 Other 11 749 27 237 i Accrued taxes -

l Local property and other 915 916 i income 1 945 801 l Accrued interest and other 1 767 1 706 i 17 955 32 414 69 410 58 289 DEFERRED CREDITS:

l Unamortized investment tax credits 11 604 9 494 Other 288 288

! 11 892 9 782 l COMMITMENTS (Note 6)

$182 662 $170 310 i

i l

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

l 1

STATEMENTS OF INCOME CANAL ELECTRIC COMPANY STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,1982,1981 AND 1980 1982 1981 1980 (Dollars in Thousands)

ELECTRIC OPERATING REVENUES $213 109 $229 457 $197 256 OPERATING EXPENSES:

Fuel oil used in production 174 930 192 325 161 722 Other operation 9 000 8 805 6 882 Maintenance 8 675 7 268 7 705 Depreciation 4 909 4 848 4 617 Taxes -

Income (Note 2) 5 398 6 706 6 459 Local property 1 822 1 888 1 791 Payroll and other 327 __

286 222 205 061 222 126 189 398 OPERATING INCOME 8 048 7 331 7 858 OTHER INCOME:

Allowance for equity funds used during construction 2 349 29 -

Other, net 489 3 536 2 802 2 838 3 565 2 802 INCOME BEFORE INTEREST CHARGES 10 886 10 896 10 660 l lNTEREST CHARGES:

1 Long-term debt 4 075 4 124 4 174 l Other interest charges 4 893 59 161 Allowance for borrowed funds used during construction (6 039) (18) (36) 2 929 4 165 4 299 NET INCOME $ 7 957 $ 6 731 $ 6 361 l

l l

l l

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

l L

c STATEMENTS OF RETAINED EARNINGS CANAL ELECTRIC COMPANY STATEMENTS OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31,1982,1981 AND 1980 1982 1981 1980 (Dollars in Thousands)

Balance at beginning of year $ 7 471 $ 7 214 $ 7 250 Add (Deduct):

Net income 7 957 6 731 6 361 Cash dividends on common stcck (8 073) (6 474) (6 397)

Balance at end of year ( 7_31!i $ 7_471 $_7_?J _4 The accompanying notes are an integral part of these financial statements.

, STATEMENTS OF SOURCES OF FUNDS USED FOR CONSTRUCTION CANAL ELECTRIC COMPANY STATEMENTS OF SOURCES OF FUNDS USED FOR CONSTRUCTION FOR THE YEARS ENDED DECEMBER 31,1982,1981 AND 1980 1982 1981 1980 (Dollars in Thousands)

SOURCES OF FUNDS -

Internal Sources From Operations -

Net income $ 7 957 $ 6 731 $ 6 361 Items not requiring or (providing) funds:

Depreciation 4 909 4 848 4 617 Deferred income taxes - long-term 3 418 1 803 451 Investment tax credits, net 2 110 4 427 (110)

Allowance for equity funds used during constructicn (2 349) (29) -

16 045 , 17 780 11 319 Less -

Payment of dividends 8 073 6 474 6 397 Retirement of iong-term debt through sinking funds 763 763 763 Other (725) (1 426) 114 8 111 5 811 _ 7 274 Changes ir net current assets:

Cash 332 26 481 (21 133)

Accounts receivable and unbilled revenue 3 944 1 230 (13 171)

Income taxes, net 6 150 (9 617) 2 896 Electric production fuel oil 91 228 9 496 Accounts payable and other (15 199) (1 960) 20 588 (4 682) 16 362 (1 324)

Net available from internal sources 3 252 28 331 2 721 increase (Decrease) in Interim Financing 25 580 25 875 (1 300)

$_28 832 $_51 206 $ 1 421 FUNDS USED FOR CONSTRUCTION -

Canal Unit No.1 $ 528 $ 1 126 $ 1 241 Canal Unit No. 2 150 779 180 Jointly-Owned Projects (Note 6) 30 503 52 330 -

31 181 54 235 1 421 Less - Allowance for equity funds used during construction 2 349 29 -

$28_832 $34_206 $ 1 421 The accompanying notes are an integral part of these financial statements.

Y NOTES TO FINANCI AL STATEMENTS CANAL ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS (1) Significant Accounting Policies General and Regulatory The Company is a wholly-owned subsidiary of Commonwealth Energy System. The parent company is referred to in this report as this System and together with its subsidiaries is sometimes collectively referred to as "the system." The Company is regulated by various authorities, including the Federal Energy Regulatory Commission ("FERC") and the Massachusetts Department of Public Utilities ("DPU"). The System is an exempt holding company under the provisions of the Public Utility Holding Company Act of 1935 and, in addition to its investment in the Company, has interests in other utility companies and several non-regulated companies.

Transactions with Affiliates Transactions between the Company and other system companies include purchase and sale of electricity and payment fcr management, accounting, data processing and otner services. Transactions with other system companies are subject to review by the FERC and the DPU.

Operating revenues include sales of electricity to affiliated companies of $117,945,000 in 1982, $129,448,000 in 1981 and $105,279,000 in 1980.

Other Major Customers The Company is a wholesale electric generating company which sells power under life-of-the-unit power contracts to several utility companies in the New England area. Information regarding the customers and their

. participation in these contracts may be found in the " Business" section of this report.

Depreciation Depreciation is provided using the straight-line method at rates intended to amortize the original cost of properties over their estimated economic lives. The Company's composite depreciation rate, based on average depreciable property in service, was 3.8% in 1982 and 1981, and l 3.6% in 1980.

l Maintenance l

Expenditures for repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expense. Additions, replacements and renewals of property considered to be units of property, are charged to the appropriate plant accounts. Upon retirement, accumulated depreciation is charged with the original cost of property units and the cost of removal net of salvage.

. _ - ~ . _ _ . .. - .. ..-. . - - . - _ - - . _ - . - - - - _ _ _ _ - - - _

1 .

l CANAL ELECTRIC COMPANY _

NOTES TO FINANCIAL STATEMENTS (CONTINUED)

(1) Significant Accounting Policies (Continued) ,

Allowance for Funds Used During Cons'truction The Company includes as an element of the cost of construction of depreciable property an allowance for. funds employed during periods  !

when property is under construction. An amount equal to the allowance capitalized in the current period is~ reflected in'the statements of income.

y Under applicable rate-making practices, property under construction is i

not included in rate base on which the' Company is permitted to earn a return. Amounts so capitalized, while .not currently providin0 funds, are inciuded in rate base when property is placed in service, and these amounts are recoverable in revenues over the service life of the constructed 4

property.

j The Company develops rates based upon its current cost of capital and used a compound rate of 121/4% ,in 1982,11% .in 1981 and 19% in 1980. .

(2) income Taxes i

For financial reporting purposes, the Ocmpany provides taxes on a separate return basis. However, for Federal income tax purposes, the Company's taxable income and deductions are included in the consolidated

income tax return of its Parent and it makes tax payments or receives refunds on the basis of its tax attributes in the consolidated income tax return in accordance with applicable Federal income tax regulations.

The following is a summary of the provision for income taxes for j the years ended December 31,1982,1981 and 1980:

, 1982 1981 1980 Total Federal State Total Federal State Total Federal State j (Dollars in Thousands) 1 Currently j payable $ 117 $ 21 $ 96 $ 272 $ (379) $651 $6 436 $5 SES $851 Currently i deferred (247) (4'0) 4 193 204 178 26 (318) (275) (43)

Long-term -

deferred 3 418 3 192 226 ' .1 803 1'566 237 451 392 59 4

investment tax-credits 2 332 2 332 -

4 671 4 671 .

33 33 -

! 5 620 5 105 515' ~6 950 6 036 914 6 602 5 735 867 4

Less-Amortization ,_

g I of investment '

i tax credits 222 222 -

'244 244 -

143 143 -

$5 398 SLB&3 $.5_15 $6 706 $.5 792 $114 $ft459 $1_fi92 381iZ

~

i i  !

- _ , ~ . _ . _ _ _ _ . .

CANAL ELECTRIC COMPANY NOTES TO FINANCI AL STATEMENTS (CONTINUED)

(2) Income Taxes (Continued)

Income taxes are provided for the tax effects of timing differences other than certain construction-related costs. Timing differences result from reporting income and expense for tax purpo.es in periods different from those used for financial reporting purposes. The accumulated deferred income taxes resulting from long-term differences are presented as reductions in the assets to which they relate, consistent with rate-making treatment. Additionally, construction work in progress is presented not of accumulated deferred income taxes which totaled $9,719,000 in 1982 and $3,329,000 in 1981.

The Company's long-term deferred provision for income taxes results from the use of the following:

1982 1981 1980 (Dollars in Thousands)

Adjustment for canal dredging costs $ - $1 143 $(1 143)

Accelerated depreciation for tax purposes 693 863 1 470 Cancelled nuclear units (249) (249) (7)

Allowance for borrowed funds used during construction 2 990 8 18 Other (16) 38 113 Long-term deferred income tax provision $3_418 $1 803 $ 451 The tax effects of current timing differences are included in the currently deferred provision and accrued income taxes. Investment tax credits are deferred and amortized over the life of the property giving rise to the credits.

The total income tax provision set forth above represents 40% in 1982, and 50% in 1981 and 1980 of income before such income taxes. The table below reconciles the statutory Federal income tax rate to these percentages:

1982 1981 .1980 Statutory Federal income tax rate 46% 46% 46%

Increase (decrease) from statutory rate:

Allowance for equity funds used during construction (8) - -

State income tax net of Federal tax reduction 2 4 4 Amortization of investment tax credits (2) (2) (1)

Other 2 2 1 4D% 50% 50%

(3) Interim Financing and Long-Term Debt Advances from Affiliates The Company had short-term notes payable to the Parent totaling

$6,400,000 at December 31, 1982. These notes are written for a term of eleven months and twenty-nine days. Interest is at the prime rate (11.5% at December 31, 1982) and is adjusted for changes in the rate during the term of the notes.

'4 L .

i .

f

.- CANAL ELECTRIC COMPANY

, NOTES TO FINANCI AL STATEMENTS (CONTINUED)

(3) Interim Financing and Long-Term Debt (Continued) i ,

The Company is a member of the COM/ Energy M$ney Pool (the Pool) which is an -arrangement among the public utility and non-utility subsidiaries of the system, by which short-term cash surpluses of'all subsidiaries may be used to meet the short-term borrowing needs of the utility subsidiaries.

The DPU approved the Pool in 1981. Lenders to the Pool, in general, receive a higher rate of return than they otherwise would on such j investments. Borrcwers from the Pool pay a tiower interest rate than

. they would otherwise pay to banks and, as a' result, the system has a

! reduced need for lines of credit than otherwise would be req'uired. At December 31, 1982, the Company had borrowings from the Pool totaling

$805,000.

Notes Payable to Banks I

The Company and other system companies have banking relationships in which borrowings are arranged as required for interim financing of construction projects. These arrangements are not formal lines of credit but provide for unsecured borrowings evidenced by notes payable which are . written for terms of up to 90 days.

Informal iines of credit with several banks totaling $149,000,000 for the system were utilized by the Company as of December 31, 1982. The terms of one line require a compensating balance of 5% of the line or a fee if such balance is not maintained. The terms of a second line require that wrien system companies are borrowing, they must maintain normal e operating balances for cash demand and bank service charges. The

, interest on all borrowings is at an adjusted money market rate.

j The Company had outstanding borrowings from banks totaling i ,- _.$44,250,000 at December 31, 1982.

Long-Term Debt

';~,. Long-term debt outstanding, exclusive of current sinking fund requirements and related premiums, is as follows:

Original Balance December 31, Issue 1982 1981

1. (Dollars in Thousands)

First M.ortgage Bonds, Series A, 7%, due 1996 $19 000. $12 920 $13 680 Series B, 8.85%, due 2006 35 000 34 650 34 650

$47 570 $_48 330

r 1 CANAL ELECTRIC COMDANY NOTES TO FINANCI AL STATEMENTS (CONTINUED)

(3) Interim Financing and Long-Term Debt (Continued)

Long-Term Debt (Continued)

The Series A First Mortgage Bonds require an annual sinking fund payment of $760,000 from 1982 to 1996. At December 31,1982 and 1981 the Company had purchased $190,000 and $218,000 of its bonds, respectively, in anticipation of future sinking fund requirements.

The Series B First Mortgage Bonds require an annual sinking fund payment of $350,000. The requirement may be met by payment, repurchase of bonds or certification of an amount of property additions equal to 60%

of bondable property (as that term is defined in the indenture). The Company expects to certify additional bondable property in lieu of making sinking fund payments on these bonds.

(4) Dividend Restriction At December 31, 1982, approximately $2,089,000 of retained earnings was restricted against payment of cash dividends by the terms of the indenture of Trust securing long-term debt.

, (5) Pension and Employees Savings Plans The Company has a noncontributory pension plan covering substantially all regular employees who have attained the age of 25. Pension costs

, are funded as accrued and include amounts applicable to prior service costs which are being amortized over a period of 30 years. Total pension expenso was approximately $354,000 in 1982, $317,000 in 1981 and $325,000 in 1980. The assumed rate of return used in determining the actuarial i value of accumulated plan benefits was 71/2% in 1982 and 1981.

A comparison of accumulated plan benefits and plan net assets for the Company's benefit plan is presented below.

January 1, 1982 1981 i (Dollars in Thousands) i Actuarial present value of accumulated plan

! benefits:

Vested $1 453 $1 227 Nonvested 161 149 Total actuarial present value of accumulated plan benefits $1 614 $1 376 l Net assets available for benefits $1 958 $3_Z38 i

. - - . . , - - - - - . . , _, ,,m. _ --- .- -__c _ _ _ ~ < - - -r,--,~-,,, ,,....,,m.-- --y,,,,v.--m.,.----.,,-

CANAL ELECTRIC COMPANY NOTES TO FINANCI AL STATEMENTS (CONTINUED)

(5) Pension and Employee Savings Plans (Continued)

The Company has an Employee Savings Plan which provides for Company contributions equal to contributions by eligible employees but not in excess of four percent of each employee's compensation rate. The total Company contribution was approximately $104,000 in 1982, $96,000 in 1981 and $87,000 in 1980.

(6) Commitments Construction Program The Company has made substantial commitments in connection with its construction program, most of which relates to its com .tment .o joint-ownership interest in the Seabrook nuclear electric c .arating units. Construction expenditures for the five year pericd ending in 1987 are estimated at $116,600,000 including approximately $112,800,000 related to commitments by the Company for the Seabrook project. The Company's construction program is subject to periodic review, and actual expenditures may vary from the above estimates because of factors such as changes in business conditions, rates of growth, effects of inflation, equipment delivery schedules, licensing delays, availability and cost of capital and environmental factors.

Purchase of Seabrook Ownership Interest On December 31, 1981, the Company purchased a 3.52% commitment in the Seabrook nuclear electric generating units, which are presently under construction by the lead participant - Public Service Company of New Hampshire (PSNH). This interest was purchased from Commonwealth Electric Company for approximately $52,330,000, net of income tax reserves.

Commonwealth Electric is an affiliated electric distribution company which purchases wholesale power from the Company and from other non-associated companies.

The purchase of the Company's interest in the project was conditioned upon receipt of various regulatory approvals including those of the DPU, the New Hampshire Public Utilities Commission (NHPUC) and the Nuclear Regulatory Commission (NRC). Approvals of the DPU and the NHPUC were received during 1981 and in 1982 the NRC issued its approval.

The project has experienced numerous delays due to regulatory, legal and other problems, resulting in significant increases in cost estimates.

In late 1982, PSNH announced its most recent estimate, increasing the cost of the project from $3.56 to $5.24 billion and changes in the cor'nercial operating dates of Unit I and Unit 11 to December,1984 and July,1987.

The PSNH estimate includes allowances for funds used during construction but excludes the cost of nuclear fuel. Independent construction consultants have been retained by PSNH to review and evaluate the validity of its estimated cost and completion dates. PSNH has indicated that adequate l and timely rate increases and external financing are both essential to  ;

j enable it to continue its construction program.

r CANAL ELECTRIC COMPANY NOTES TO FINANCI AL STATEMENTS (CONTINUED)

(6) Commitments (Continued)

Purchase of Seabrook Ownership Interest (Continued)

Based upon a $5.24 billion project cost, the Company's ownership interest will amount to approximately $200,000,000, including allowance for funds used during construction and nuclear fuel. Through December 31, 1982 expenditures were $87,000,000.

(7) Supplementary information to Disclose the Effects of Changing Prices (Unaudited)

The following supplementary information is supplied in accordance with the requirements of Financial Accounting Standards Board Statement No. 33 for the purpose of providing certain information about the effects of changing prices. It should be viewed as zn estimate of the approximate effect of inflation, rather than as a precise measure.

Constant dollar amounts represent historical costs stated in terms of dollars of equal purchasing power, as measured by the Consumer Price Index for All Urban Consumers. Current cost amounts reflect the changes in specific prices of plant from the date the plant was acquired to the present, and differ from constant dollar amounts to the extent that specific prices have increased more or less rapidly than prices in general.

The current cost of plant is determined primarily by indexing surviving plant using the Handy-Whitman index of Public Utility Construction Costs. Since the utility plant is not expected to be replaced in kind, current cost does not necessarily represent the replacement cost of the productive capacity. Depreciation is determined by applying the Company's depreciation rates to the revised asset amounts.

Fuel inventories and the cost of fuel used in generation have not been restated from their historical cost in nominal dollars because regulation provides for the recovery of fuel costs through the operation of adjustment clauses. For this reason fuel inventories are effectively monetary assets. Since only historical costs are deductible for income tax purposes, the historical income tax expense is not adjusted.

Under present ratemaking procedures prescribed by the regulatory commissions, only the historical cost of plant is recoverable ir- m ouer as depreciation. Because the excess cost of plant stated o M . ..is of constant dollars and current cost is not recoverable in rates, a write-down to net recoverable cost is required. While the rate-making process does not recognize the current cost of replacing plant, regulated companies have, historically, been allowed to earn a return on the increased cost of its investment when replacement actually occurs.

CANAL ELECTRIC COMPANY NOTES TO FINANCI AL STATEMENTS (CONTINUED)

(7) Supplementary Information to Disclose the Effects of Changing Prices (Unaudited) (Continued)

During periods of inflation, holders of monetary assets suffer a loss of general purchasing power while holders of monetary liabilities experience a gain. The gain from the decline in purchasing power of net amounts owed is primarily attributable to the substantial amount of debt which has been used to finance property, plant and equipment. These gains are unrealized and, therefore, do not contribute to cash flow or distributable income.

CANAL ELECTRIC COMPANY NOTES TO FINANCI AL STATEMENTS (CONTINUED)

(7) Supplementary Information to Disclose the Effects of Changing Prices (Unaudited) (Continued)

STATEMENT OF INCOME FROM CONTINUING OPERATIONS ADJUSTED FOR CHANGING PRICES For the Year Ended December 31, 1982 Conventional Constant Dollar Current Cost Historical Average Average Cost 1982 Dollars 1982 Dollars (Dollars in Thousands)

Operating revenues $213 109 $213 109 $213 109 Fuel used in production 174 930 174 930 174 930 Depreciation expense 4 909 10 366 11 467 Other operation and maintenance 17 675 17 675 17 675

, income and other taxes 7 547 7 547 7 547 m Interest charges 2 929 2 929 2 929

• Other income and deductions - net (2 838) (2 838) (2 838) 205 152 210 609 211 710 income from operations (excluding adjustment to net recoverable cost) $ 7 951 $ 2 500* $ _1_399 increase in specific prices (current cost) of property, plant and equipment held during the year ** $ 7 308 Adjustment to net recoverable cost $ (432) 698 Effect of increase in general price level (7 337)

Excess of specific prices over the increase in general price level after adjustment to net recoverable cost 669 Gain from decline in purchasing power of net amounts owed 3 492 3 492 Net $__3__03Q $ 4 163

• Including the reduction to net recoverable cost, the income from operations on a constant dollar basis would have been $2,068,000.

• • At December 31, 1982, cu' rent cost of property, plant and equipment, net of accumulated depreciation was $189,174,000, while historical cost or net cost recoverable through depreciation was $170,999,000.

CANAL ELECTRIC COMPANY NOTES TO FINANCI AL STATEMENTS (CONTINUED)

(7) Supplementary information to Disclose the Effects of Changing Prices (Unaudited) (Continued)

FIVE YEAR COMPARISON OF SELECTED SUPPLEMENTARY FINANCI AL DATA ADJUSTED FOR EFFECTS OF CHANGING PRICES (in thousands of average 1982 dollars)

Year Ended December 31, 1982 1981 1980 1979 1978 Operating revenues:

Actual $213 109 $229 457 $197 256 $141 976 $110 769 g Adjusted to average 1982 dollars $213 109 $243 524 $231 064 $188 801 $163 886 N Historical Cost Information adjusted i

for general inflation:

Income from continuing operations (excluding adjustment to net recoverable cost) $ 2 500 $ 2 255 $ 3 362 $ 2 855 Net assets at year-end at net recoverable cost $ 53149 $ 55 326 $ 59 985 $ 67 421 Current Cost Information:

Income from continuing operations (excluding adjustment to net recoverable cost) $ 1 399 $ 1 053 $ 2 196 $ 2 708 Excess of general prices over the increase (decrease) in specific price level after adjustment to net recoverable costs $ (669) $ 4 243 $ 7 862 $ 11 432 Net assets at year-end at net recoverable cost $ 53 149 $ 55 326 $ 59 985 $ 67 421 General Information:

Gain from decline in purchasing power of net amounts owed $ 3 492 $ 3 945 $ 4 640 $ 6 041 Average consumer price index 289.1 272.4 246.8 217.4 195.4 Note: The Company's stock is entirely owned by the Parent System, therefore, per share information is not relevant. .

CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 PART lil.

Item 10. Directors and Executive Officers of the Registrant Age at Position December 31, Name of Director (1) with Company Business Experience 1982 Charles T. Abbott None Retired; former 77 President of COM/

Energy Services Company (formerly NEGEA Service Corporation)**

0 Gerald E. Anderson (2) Chairman of the Board (3) 51 and President CEarl G. Cheney (4) Financial Vice (3) 46 President Leland R. Crowell None Retired; former 74 General Manager and Vice President of the Company Burdette A. Johnson None Retired; former 77 Financial Vice President of the Company and its' affiliates 0 Jeremiah V. Donovan (5) Executive Vice Presi- (3) 47 dent - Electric Operations William R. Smith Vice President - (3) 60 Energy Supply Richard G. Velte Vice President - (3) 62 Facilities Development Prior to their retirement Messrs. Abbott, Crowell, and Johnson served in executive capacities with the Company and/or an affiliated Company.

All directors have served in executive capacities either with the Company, an affiliated company or with another company for five years or more.

(1) Present term of office of all Directors will expire on January 27, 1984, the date of the next annual meeting of shareholders.

1

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CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 Item 10. Directors and Executive Officers of the Registrant (Continued)

(2) Chairman of the Board - Cambridge Electric Light Company **, COM/ Energy Services Company **, Commonwealth Electric Company **, and Commonwealth Gas Company **.

(3) Director is also an executive officer of the Company. (See Executive O fficers. )

(4) Director of Cambridge Electric Light Company **, Commonwealth Electric Company **, Commonwealth Gas Company **, and other non-operating affiliate companies.

(5) Director of Cambridge Electric Light Company ** and Commonwealth Electric Com pa ny ** .

• Member of Executive Committee

• • Affiliated Companies.

Age at Name of Officer (6) Position and Business Experience December 31, 1982 Gerald E. Anderson Chairman of the Board since 1977; 51 President since 1974; Financial Vice President 1972 - April 1974

]

Earl G. Cheney Financial Vice President since 46 May 1974; Comptroller 1972-1974 Jeremiah V. Donovan Executive Vice President - Electric 47 4

Operations since October 1978; Vice President and General Manager, l Cambridge Electric Light Company 1

since April 1976; Assistant Vice President, Cambridge Electric Light Company November 1975-1976; Engineer, COM/ Energy Services Company (formerly NEGEA Service Corporation) 1963-1975.

t i Michael P. Sullivan Vice President, Clerk and General 34 l Attorney since 1981; Clerk 1976-1981 Andrew S. Griffiths Vice President-Administration since 46 February 1979; Assistant Vice President since April 1975 and Assistant Treasurer since 1972,

Commonwealth Electric Company (formerly New Bedford Gas and i Edison Light Company).

~

- - . - ._ .. ... .__. _ , _ _ , _ _ . . _ , _ . . . . _ _ _ _ _ . _ . _ _ _ . . . _ _ _ _ . _ . . . - . - - ~ ~. . _ . . _ -

CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 Item 10. Directors and Executive Officers of the Registrant (Continued)

Age at Name of Officer (6) Position and Business Experience December 31, 1982 Ronald F. MacDonald Vice President-Customer Services 52 since February 1979; Executive Vice President end General Manager, Commonwealth Electric Company since April 1973.

William R. Smith Vice President-Energy Supply 60 since February 1979; Vice President and General Manager since 1973.

Richard G. Velte Vice President-Facilities Development 62 since February 1979; Vice President, Engineering since October 1974 and Chief Engineer since January 1972, COM/ Energy Services Company (formerly NEGEA Service Corporation).

Robert E. Healey Vice President-Human Resources 45 since February 1979; Assistant Vice President and General Manager, since April 1975 and Manager of Employee and Public Relations since

1972, Commonwealth Electric Company

. (formerly New Bedford Gas and Edison l Light Company).

! John J. Tasillo Vice President-Rates since February 1979; 40 Rate Manager, COM/ Energy Services l Company (formerly NEGEA Service t

(Corporation) since 1973.

Robert S. Parker Treasurer since 1971 57

( John A. Whalen Comptroller since September 1978; 35

Audit Manager, COM/ Energy J Services (formerly NEGEA Service l Corporation) since 1975; Product

! Line Controller, Rockwell International

( since 1973.

I (6) The Vice President, Clerk and General Attorney and the Treasurer of the Company are elected to serve until the next annual shareholders' meeting. All other officers are appointed to serve until the next annual organization meeting of directors which follows the shareholders' meeting.

T CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 Item 10. Directors and Executive Officers of the Registrant (Continued)

There is no family relationship between any director or executive officer and any other director or executive officer of the Company. There were no arrangements or understandings between any officer or director and any other person pursuant to which he was or is to be selected as an officer, director or nominee.

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 11. Management Remuneration and Transactions The following table shows remuneration of each person deemed to be an Executive Officer or Director of the Company whose total remuneration exceeded

$50,000, and all Officers and Directors as a group.

Cash or Cash Equivalent Forms Employees' Name of Individual Capacities in which of Remuneration

• Savings and or Number of Persons Remuneration Salaries insurance TRASOP Plan in Group was Received and Fees Benefits Contributions **

W. R. Smith Officer $ 55 762 $259 $3 496 Officers and Directors Officers $139 721 $444 $6 534 of the Company as and a Group (15) Directors i

• No remuneration is paid directly by the Company to its officers. Their compensation is paid by affiliated companies, of which they are officers and employees. For the year 1982, approximately 15% of these officers' compensation was charged by affiliated companies to the Company. In his capacity as Vice President of Energy Supply, Mr. Smith was closely associated with the daily operation of the Company's generating facility and, as such, $55,762 or approximately 77% of Mr. Smith's compensation was charged to the Company by, an affiliated company, Commonwealth Electric Company.

• • This represents the aggregate contributions by the Company during 1982 on behalf of the above group to the Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies and/or the Tax Reduction Act of 1975 Employees Stock Ownership Plan of Commonwealth Energy System and Subsidiary Companies. No Director, as such, receives any benefits under the above Plans.

f i

CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 Item 11. Management Remuneration and Transactions (Continued)

Pension costs are not included in the table because the Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies costs are computed on an aggregate acturarial basis without individual allocation.

During 1982, the System and/or its subsidiaries made aggregate contributions to the Plan in the amount of 12.0% of the total base salary of qualified Plan participants in effect on January 1,1982. Remuneration covered under the Plan includes base salary with the limited exception of certain commission sales persons. No Director, as such, receives any benefits under the above Plan.

The following table shows annual pension benefits payable to employees, including Officers, upon retirement at age 65, in various remuneration and years-of-service classifications, assuming the election of a retirement allowance payable as a life annuity:

Highest Annual Consecutive 3-Year Average Basic Salary of Last Annual Benefits For Years of Service 10 Years 10 Years 20 Years 30 Years 40 Years

$ 60 000 $ 6 542 $17 084 $25 626 $ 31 626 90 000 13 542 27 084 40 626 49 626 120 000 18 542 37 084 55 626 67 626 150 000 23 542 47 084 70 626 85 626 180 000 28 542 57 084 85 626 103 626 Item 12. Security Ownership of Certain Beneficial Owners and Management Amount and Nature Percent Title of Name of of Beneficial of Class Beneficial Owner Ownership Class Common Commonwealth Energy System 675 Massachusetts Avenue Cambridge, MA 02139 1 523 200 100.00 Common All Directors and Officers as a group (16 persons) 41 455 (1) .50 (1) in accordance with the Securities Exchange Act of 1934, officers and directors beneficial ownership set forth in the above schedule includes, where applicable, shares owned by the wife of any directors or officers.

The directors and officers of the Company as a group at December 31, 1982 owned 41,455 shares of the parent company (based on information furnished to the System by these persons) which represents less than one percent of the total number of shares at that date.

CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 PART IV.

Item 13. Exhibits, Financial Statement Schedules and Reports on Form 8-K Incorporated Documents Filed SEC Herewith Exhibit File No. at Page (a) The following documents are filed as part of this report:

1. Financial statements of the Company together with the Report of Independent Public Accountants, are filed under item 8 of this report and listed on the Index to Financial Statements and Schedules in item 8. 11

2. The following financial statement schedules are attached hereto:

Schedule V - Property, Plant and Equipment for the Years Ended December 31, 1982, 1981 and 1980. 40 - 42 Schedule VI - Accumulated Depreciation of Property, Plant and Equipment for the Years Ended December 31,1982,1981 and 1980. 43 Schedule IX - Short-term Borrowings for the Years Ended December 31, 1982, 1981 and 1980. 44 (b) No reports on Form 8-K were filed during the three months ended December 31, 1982. However, a report on Form 8-K cated December 21, 1982 was filed with the Commission on February 2, 1983 in response to Public Service Company of New Hampshire revised cost estimate for the Seabrook nuclear electric generating units of which the Company is a 3.52%

owner.

(c) List of Exhibits:

Exhibit 3. Articles of incorporation and by-laws.

Incorporated herein by reference thereto:

3(a) Articles of incorporation of the Company have been filed with the Commission as an exhibit in the Company's 1980 Form 10-K. 1 2-30057 f

I CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 Item 13. Exhibits, Financial Statement Schedules and Reports on Form 8-K (Continued)

Incorporated Documents Filed SEC Herewith Exhibit File No. at Page 3(b) By-laws of the Company, as amended, i have been filed with the Commission l as an exhibit in the Company's 1980 '

Form 10-K. 2 2-30057 Exhibit 4. Instruments defining the rights i of security holders, including indentures. I Incorporated herein by reference thereto:

4(b)1 Copy of Indenture of Trust and First Mortgage dated as of October 1,1968 between the registrant and State Street Bank and Trust Company, Trustee, has I been filed with the Commission as l an exhibit to Form S-1. 4(b) 2-30057 .

l 4(b)2 Copy-of First and General I Mortgage Indenture dated as of September 1,1976, between the registrant and Citibank, N. A. ,

Trustee, has been filed with the Commission as an exhibit to Form S-1. 4(b)2 2-56915 4(b)3 Copy of First Supplemental l

Indenture dated as of September 1, i 1976, to indenture of Trust and First Mortgage dated as of October 1,1968 between the registrant and State Street Bank and Trust Company, Trustee, closing such indenture, has been filed with the Commission as an exhibit to Form S-1. 4(b)3 2-56915 l

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CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 Item 13. Exhibits, Financial Statement Schedules and Reports on Form 8-K (Continued) incorporated Documents Filed SEC Herewith Exhibit File No. at Page Exhibit 10. Material contracts.

Incorporated herein by reference thereto:

10(a) Power contracts.

10(a)(1) Copies of power contracts dated December 1,1965 between Canal Electric Company and other utility companies have been filed by the Company with the Commission as an exhibit to Form S-1. 13(a)(1-4) 2-30057 10(a)(2) The following have been filed with the Commission as exhibits to the 1975 Form 10-K of Canal Electric Company:

Copy of agreement between the registrant and Montaup Electric Company for use of common facilities by Canal Units I and il and for allocation of related costs. 1 2-30057 Copy of agreement between the registrant and Montaup Electric Company for joint ownership of Canal Unit II. 2 2-30057 Copy of agreement between the registrant and Montaup Electric Company for lease relating to Canal Unit ll. 3 2-30057

f l 1

. 1 CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982

)

Item 13. Exhibits, Financial Statement Schedules and Reports on Form 8-K (Continued)

incorporated Documents Filed SEC Herewith Exhibit File No. at Page 10(a)(3) Copy of Contract dated January 12,

! 1976 between Canal Electric Company and Commonwealth Electric Company (formerly New Bedford Gas and Edison Light Company) and Cambridge Electric Light Company, affiliated companies, for the sale of specified amounts of electricity from Canal Unit No. 2 has been filed with the Commission as an exhibit to the System's 1975 Form 10-K. 4 1-7316 10(a)(4) Copy of amendment dated August 6,1976 to joint-ownership i agreement between Canal Electric Company, New England Power Company, and other utilities dated January 11, 1976 has been filed with the Commission as an exhibit to the Company's 1976 l Form 10-K. 1 2-30057 10(a)(5) Copy of Purchase and Sale Agreement dated January 2, 1981 together with an implementing Addendum dated December 31, 1981, between the Company and Commonwealth Electric for the purchase and sale of that l company's 3.52% Joint-ownership

interest in the Seabrook nuclear l electric generating units has been I

filed as an exhibit to the Company's Form 8-K (December 1981). 1 2-30057 i

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CANAL ELECTRIC COMPANY FORM 10-K DECEMBEk 31, 1982 Item 13. Exhibits, Financial Statement Schedules and Reports on Form 8-K (Continued)

Incorporated Documents Filed SEC Herewith Exhibit File No. at Page 10(a)(6) Copy of Fourteenth Amendment to Agreement for Joint Ownership of New Hampshire Nuclear Units between Common-wealth Electric Company (for itself and for Canal Electric Company) and Public Service Company of New Hampshire and others amending certain rights and provisions has been filed with the Commission as an exhibit to Commonwealth Electric Company's Form 10-Q (Ju n e, 1982) . 3 2-7749 10(a)(7) Copy of the Capacity Acquisition Agreement dated September 25, 1980 between Canal Electric Company, Cambridge Electric Light Company and Commonwealth Electric Company has been filed with the Commission on the Company's Form 10-Q (March 1981). 1 2-30057 10(b) Other agreements.

10(b)(1) Copy of Tax Reduction Act of 1975 Employee Stock Ownership Plan and Trust of Commonwealth Energy System and Subsidiary Companies as amended May 11, 1981 has been filed with the Commission as an exhibit to the System's Form 10-Q, September 1981. 1 1-7316 10(b)(2) Copy of Employees Savings Plan of Commonwealth Energy System and Subsidiary Companies as amended May 11,1981 has been filed as an exhibit to Form S-8 (October 1981) by the System. 3 2-74536 r

CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 Item 13. Exhibits, Financial Statement Schedules and Reports on Form 8-K (Continued)

Incorporated Documents Filed SEC Herewith Exhibit File No. at Page 10(b)(3) Copy of Pension Plan for Employees of Commonwealth Energy System and Subsidiary Companies as amended May 11, 1981 has been filed with the Commission by the System on Form 10-Q (September 1981). 2 1-7316 10(b)(4)(a) Copies of New England Power Pool Agreement (NEPOOL) dated September 1,1971 as amended through August 1,1977, between COM/ Energy Services Company (formerly NEGEA Service Corporation), as agent for Cambridge Electric Light Company, Canal Electric Company, Commonwealth Electric Company (formerly New Bedford Gas and Edison Light Company), and various other electric utilities operating in New England, together with amendments dated August 15, 1978 and January 31, 1979 filed with the Commission as an exhibit to Commonwealth Energy System's Form S-16 (May 1980). 5(c)13 2-64731 10(b)(4)(b) Copy of an amendment to the New England Power Pool Agreement dated September 1, 1981 filed as an exhibit with Commonwealtn Energy System's

, 1981 Form 10-K. 5 1-7316 10(b)(5) Copy of oil Supply Contract effective January 1,1981, between Canal Electric Company and Charter Oil (Massachusetts)

Inc. filed with the Commis ,lon as an exhibit in the Company's Form 10-Q (September 1981). 1 2-30057 l

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1 C_AN AL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 Item 13. Exhibits, Financial Statement Schedules and Reports on Form 8-K

(Continued) incorporated Documents Filed SEC Herewith Exhibit File No. at Page 10(b)(6) Copy of the Assignment Agree-ment between Charter Oil (Mass-achusetts) inc., COFI Credit (Massachusetts) inc. , and Canal Electric Company. 1 47 10(b)(7) Copy of Facilities Lease and Operating Agreement between Canal Electric Company and Nepco Terminal, Inc. effective January 1,1981 filed with the Commission as an exhibit to the Company's Form 10-Q j (September 1981). 2 2-30057 l

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.- , . . . .~ .. . - - - - - ~ . _, . - - - . . . - _ . - - . .- - _ - . -._.

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CANAL ELECTRIC COMPANY 1

j P roperty, Plant and Equipment (A)

I For the Year Ended December 31, 1982

) Balance Retirements Balance Beginning Additions Charged to End of Classification of Year at Cost Reserve Transfers Year

, (Dollars in Thousands)

ELECTRIC Land and rights of way $ 236 $ - $- $- $ 236 i Structures and leasehold improvements 15 687 16 -

15 703 a Production equipment 108 881 593 62 -

109 412 j Transmission equipment 5 011 - - -

5 011 j General equipment and other 299 9 2 -

306 Total electric plant in service 130 114 618 64 -

130 668 Construction work in progress 57 163 30 356 - -

87 519 u

Total electric 187 277 30 974 64 -

218 187

, o e OTHER

! Realty property 588 49 55 -

582 Miscellaneous physical property (principally real estate) 397 159 - -

556 Total other 985 208 55 -

1 138

Total Property, Plant and Equipment 188 262 31 182 119 -

219 325

! Less-Accumulated deferred income taxes on:

Property, plant and equipment 15 463 (2 180)(B) - -

13 283 l 9 719 j Construction work in progress 3 328 6 391 (B) - -

i Property, Plant and Equipment $369_All $2S_91.1 $119 $- $396J23 i

J

(A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates. g (B) Net change. o m

) <

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)

un O

CANAL ELECTRIC COMPANY I m

O Property, Plant and Equipment ( A) f m

For the Year Ended December 31, 1981 <

Balance Retirements Balance Beginning Additions Charged to End of Classification of Year at Cost ' Reserve Transfers Year (Dollars in Thousands)

ELECTRIC Land and rights of way $ 236 $ - $- .*- $ 236 Structures and leasehold improvements 15 558 129 - -

15 687 Production equipment 107 611 1 763 493 -

108 881 Transmission equipment 5 011 - - -

5 011 General equipment and other 250 62 13 -

299 Total plant in service 128 666 1 954 506 -

130 114 Construction work in progress 817 (358) -

56 704 57 163 Total electric 129 483 1 596 506 56 704 187 277

' OTHER Realty property 618 80 110 -

588 Miscellaneous physical property (principally real estate) 136 261 - -

397 Total other 754 341 110 -

985 Total Property, Plant and Equipment 130 237 1 937 616 56 704(B) 188 262 Less-Accumulated deferred income taxes on:

Property, plant and equipment 13 420 2 043 (C) - -

15 463 Construction work in progress 129 3199 (C) - -

_ 3 328 Property, Plant and Equipment, net $116_688 $Q_3Q5) $616 .$56_7!L4 E j9 471 (A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates.

(B) Purchase of Seabrook nuclear generating units from Commonwealth Electric Company, an affiliate.

(See Note 6 of Notes to Financial Statements.)

(C) Net change.

+

4

CANAL ELECTRIC COMPANY Property , Plant and Equipment (A)

For the Year Ended December 31, 1980 Balance Retirements Balance Beginning Additions Charged to End of Classification of Year at Cost Reserve Transfers Year (Dollars in Thousands)

ELECTRIC Land and rights of way $ 236 $ -

$ - $- $ 236 Structures and leasehold improvements 15 314 243 -

1 15 558 Production equipment 107 543 148 79 (1) 107 611 Transmission equipment 5 009 2 - -

5 011 General equipment and other 244 6 - -

250 Total plant in service 128 346 399 79 -

128 666 Construction work in progress 13 804 - -

817 Eu Total electric 128 359 1 203 79 -

129 483 OTHER Realty property 452 218 52 -

618 Miscellaneous physical property (principally real estate) 136 - - -

136 Total other 588 218 52 -

754 Total Property, Plant and Equipment 128 947 1 421 131 -

130 237 Less-Accumulated deferred income taxes on:

Property, plant and equipment 9 924 3 496 (B) - -

13 420 Construction work in progress 4 327 (4 198)(B) - -

129 Property, Plant and Equipment, net $114 696 $2_123 $131 $- $1163SS (A) Refer to Note 1 of Notes to Financial Statements for depreciation method and rates. h (B) Net change $

m 4

_. _ _ _ . _ . . _ . . . . ..._ .. .-. . . . . . _ _ . . _ . _ _. . _ _ . _ . _ . _ . . - __ _ . _ __ - .~ -.

4

(

CANAL ELECTRIC COMPANY ,

9 l

ACCUMULATED DEPRECI ATION OF PROPERTY, PLANT AND EQUIPMENT g 9

m FOR THE YEARS ENDED DECEMBER 31, 1982,1981 AND 1980 l M Y

(Dollars in Thousands) i 4

I Provision Clearing

! Accounts and Balance j Balance at Beginning of Charged to Other Removal at End

! Classification Year Operations income Retirements Cost Salvage of Year I YEAR ENDED DECEMBER 31, 1982 i

l Electric $42 171 $4 909 $ 11 $ 64 $17 $ 1 $47 011 Other 25 - 41 55 - 3 14 1

i I Total Accumulated Depreciation W 96 na w 1112 11Z W 14Z D2fi YEAR ENDED DECEMBER 31, 1981

)

i j Electric $37 637 $4 848 $ 27 $506 $- $165 $42 171 Other 36 - 84 110 J 16 25 l.w Total Accumulated Depreciation g7_57J 14_R46 1111 1616 M 1111 142 196 YEAR ENDED DECEMBER 31, 1980 Electric $33 094 $4 617 $ 7 $ 79 $2 $- $37 637 42 - 42 52 - 4 36 Other i

l Total Accumulated Depreciation g3._136 14_$12 M 1Q1 W W Q2._122 4

4 i

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r SCHEDULE IX CANAL ELECTRIC COMPANY Short-Term Borrowings For the Years Ended December 31,1982,1981 and 1980 (Dollars in Thousands)

Maximum Average Weighted -

Notes Weighted Amount Amount Average Outstanding Average Outstanding Outstanding Interest at interest During During Rate at Category ( A) Year-End Rate the Year the Year (B) Year-End(C)

Year Ended December 31, 1982 Banks $44 250 13.6% $44 250 $30 962 10.1%

Year Ended December 31, 1981 Banks $22 500 13.0% $22 500 $1 731 13.0%

Year Ended December 31, 1980 Banks 3 -

i i

{ (A) Refer to Note 3 of Notes to Financial Statements for- the general terms of notes payable.

l (B) The average amount of short-term debt outstanding is determined by = eraging i the level of short-term debt outstanding at month-end for the thirteen-month

period ending December 31, 1982.

l (C) The weighted average interest rate at year-end is determined by annualizing j the interest cost based on rates in effect during December and dividing this i

by the notes outstanding at year-end.

CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1932 SIGN ATU R ES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CANAL ELECTRIC COMPANY (Registrant)

By: GERALD E. ANDERSON Gerald E. Anderson, Chairman of the Board and President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Principal Executive Officer:

GERALD E. ANDERSON March 28,1983 Gerald E. Anderson, Chairman of the Board and President Principal Financial Officer:

EARL G. CHENEY March 28,1983 Earl G. Cheney, Financial Vice President Principal Accounting Officer:

JOHN A. WHALEN March 28,1983 John A. Whalen, Comptroller 1 A majority of the Board of Directors:

CH ARLES T. ABBOTT March 26,1983 l

Charles T. Abbott, Director GER ALD E. ANDERSON March 28,1983 Gerald E. Anderson, Director l

1 l

r CANAL ELECTRIC COMPANY FORM 10-K DECEMBER 31, 1982 SIGN ATU R ES (Continued)

EARL G. CHENEY March 28,1983 Earl G. Cheney, Director

. March , 1983

! Leland R. Crowell, Director JEREMI AH V. DONOVAN March 21,1983 Jeremiah V. Donovan, Director BURDETTE A. JOHNSON March 17,1983 Burdette A. Johnson, Director

! WILLI AM R. SMITH March 18,1983 William R. Smith, Director 4

RICHARD G. VELTE March 18,1983 i Richard G. Velte, Director l

I l

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1 JTO THE -MEMBERS ,r 1  ; m+ . - .Jm 4 L .

s . a, .M>

r .az._ m ,_ , - ._ me - . .

a DIRECTORS (for terms expiring) 1983 1954 19S5 Fletcher Adams. Ply mouth Edwm Sloulton. Steredah Everett Sackett, Dover Treasurer Secretary James Page. Benton Gail F. Pame, Intervalt Arthur Wadleigh, Ashland Pre.sident Ena %! ann, Woodsville Denms Fenton. Andover Ted Putnam, Charlestown Vice. President Wlutman Ide, Belmont Grace II. Bean. Waterville Valley

.lANAGER

\ AUDLTOR ATTORNEY John Pdisbury 51ultennan, Ty rrel & G!cason 51ayland H. Storse

?

DEAR 51EilBERS.

This has been a challengmg y ear for your Cooperative and Boad of Directors. The ;ame good $

weather that helped us avoid storm damage expense cut into power consumption m November and {^.; ,

{hL I December and reduced expected operatmg marpns. The 40 percent merease m the projected final l i b 5 . N 'b'/ ' #" g cost of the Seabrook nuclear plant caused quesuons to be raised about our mvestment m future k' < 4 ki generanon. A small group of members have contmued their opposition to certam action of the i4 j( N. /' ' N,k board and, throuch the news media, court and lepslative actions, hase kept their opposition before 'g .7 the membership. tu The year 1%: was one of slow growth. Average household eleetne use responded to nsinz ~

@1 QD "

I costs and contmumg conservanon ef forts. Industnal use, affected by the economy dropped this kf' year. Your Cooperanve mereased its load management effort. controlling water heaters by radio ._

y command in the Conway and Thornton areas. By tlas effort, and alth member cooperation during ..

peak load penoJs. the high denunds of wmter were shaved down to avoid y e.,r round capacity ____

, w. a charges on the wholesale bdis. Rate rehef was soug'it dunng the year and a granted at year's end. President James Page The nsmg cost of power is a constant problem, and the deusion to mvest in Seabrook. while less of a bargain then it appeared in its onginal conception, defimtely remains the best alternatise for u; to stabilize our power supply and our rates some y ears down the road. The completion of both Units I and 2 as rapidly as possible is m the best interest of the Cooperanve.

The members of the Cooperante elect the Board of Directors and charge the board with the responsibihty of operatmg the second largest uttht) m New Hampshire for the beadit of all the members. With o.cr 40.000 members. there are always some who will disagree with certam actions of the board. Such a mmonty group sprang up foMowing the board's deelston to purchase a srnail percentage of the nuclear generation at Seabrook At the last three Annual %!cetmg of the Cooperatne, this group has actively soucht to elect directors famrable to their cause and to pass bylaw amendments limitmg the power of the Board of Dueetors m the operation of the Cooperante. Each ume the members have rejected their nommees and propmals.

Dunng the year the board was challenged under the new state corporate law on achon taken to channel bylaw amendmmts throuch the board but to guarantee the nght of any member to take his or her case directly to the membership. A Supenor Cot.rt decision upholdmg the board acuen was overturned at the Supreme Court level. Your board, with the assistance or the Niembersmp Advnory Committee on Bylaws.is proceedmg with study of a major revnion of our 44 year old b> laws.

l Unfortunateis , the Bylaws of the Cooperatne hmit votmg to those who attend the annual meeung. Each member attenda 2 nay sote one und on!y onei proxy fer an absent member. Stost of the proues sent m cannot be soted. All members must have the ught and abiht) to vote for the directors to whom they entrust the affairs of the Cooperative.

Our Annual Sleeuna wall be held on June -', IN.

I hope y ou will attend and sote m the best mterests of your Cooperanve. I assure you that the board a guteful for y our understandmg and support. I welcome any mquu), or suggestions y ou may base at anyttme.

For the Board of Dueetors.

l ,

\ & Q l

[

x James Page. President

STATEMENT OF INCOME AND EXPENSE NEW hah!PSIllRE ELECTRIC COOPERATIVE, INC.

( I l

Years 1982 and 1981 8l INCO51E: .y 1981

'(

? Operating Revenues: ~ + :." ,3

' S $19,068,596 Residential Sales General (Commercial Sales) L  ;;1'5,$, 9,366,120 Outdoor Lighting (Street & Yard Lights) $,831j 575,027 Rents from Electric Property gg163;585g 467,780 .

I Aliscellaneous Electric Revenues :My 210,42A 220,758 (m -w.w Total Operating Revenues $$30,384,277,p s

$29,698,281 g

?

EXPENSE: }' *

~

Operating Revenue Deductions: 3 Purchased Power i 521,834,854 Transmir.sion' Expense

,5, - 5,796 Distribution, Operations & hiaintenance Expense 1,247,248 Consumer Accounts Expense ' , 822,023 Administrative & General Expense 2Si 1.357,192 Total Operating Revenue Deductions h,h 2 525,267,113 yy NET OPERATING REVENUES:  ; ,

S 4,431,168 OTHER INCO51E:

Interest income s

$ 165,350 Other Income _

8,207 9.+a Total Other lacome f' S 173,557 OrilER INCO51E DEDUCTIONS:

", $ 1,697,702 Depreciation Expense ,

Tax Expense 684,943 Interest Expense ,9)

A2% $ 1,641,986 Interest Charged to Construction I 14} (63,837)

Donations . . T91 2,251 (ipe-d $ 3,963,045 Total Other income Deductions g-- A.192,93&q

' NET INC051E TO SURPLUS: $ 641,680 (Capital Cre 'its allocated to each patron at the rate of 2.6% of revenue for 1982) hhbhlES ' R YoYCht kvWhPerbh ff.Grren%#26?Mr M ~.L.W RGMis&h[&5ltKwh ountf.friPowerC6mpang W56,928 NclM

' M 3.764 V;MJ12,300M N *f Y h es U kh0A5480M ompanyb C ~(!g 3,663,3001.;2'11,22-jd35256,0341,3.'

I dIk q{ 5.490 ggCentral Vermont Pgblic Serripe Co p!,s. 33,179,6ho 8,004,729Qf }78.'4' ,N. 2.0I .id377,822'i;kc

' F.D872,797EPj ih2.$31I$Nb "4~.720e g mldPower Com ' ~

'w {$$2,$fhI (( ! 6 y.

l

/ BALANCE SHEET NEW liA3tPSlilRE ELECTRIC COOPERATIVE, INC.

e Years 1982 and 1981 ASSETS UTILITY PLANT 1981 Electric Plant in Service fi 2 $ 52,021,644 8,900,362 Construction Work in Progress - Seabrook Construction Work in Progress - Other %s49

. ww a w 2 651

^0,2

, 770,139 Total Utility Plant [W. $1;,692,145 Accumulated Provision for Depreciation W,$10Q36,207y 12,426,259 13,508:487g

$49,265,886 Net Utility Plant [ NY OTliER INVESThlENTS h 1 Other Utility Property dO2 . S 211,041 Investments in Cooperatise Finance Corp.

Other Investments g(

Mr

[A%2,00G.1lM6,72k{ 1,092,460 2.000

< ^ M

,l Tot d Other Property and Investments 1 5 1,305,501 CURRENT ASSETS: h ~

Cash - General 1 $ 1,635,123 Cash - Loan Funds 8; 35,580

} ~

Accounts Receivable - Net 2,345,271 hiaterials and Supplies 5

780,965 Prepayments 163,901 Other Current and Accrued Assets  !

7,495 Temporary Cash Investments  ! .54 -

Total Current Assats -

S 4,988,335 DEFERRED DEBITS.

Other Deferred Charges ;9 S 1,971,958 Total Deferred Debits S 1,971,958 TOTAL ASSETS . 1 $57,531,680 l

LIABILITIES EQUITIES & AIARGINS S 2,203,192 Patror.. ige Capital ,

LONG TERSI DEBT: ~

$41,864,910 Rural Electrification Administration 211,078 Plymouth Guaranty Savings Ptak '

328,597 Cooperative Finance Corporation (CFC) ,

f - 8.851,238 Federal Financing Bank (Seabrook) '

$51,255,823 Total Long Term Debt l

CURRENT LIABILITIES:

Accounts Paysble 5 3,422,830 91,689 Customer Deposits '

, ... s ,8333 _ 413.401 Other Current & Accrued Dabilities gr y m m p 9.Sa1153,6431 5 3,927,920 Total Ct.rrent Liabilities DEFERRED CREDITS: h,hh[h Other Deferred Credits > 1.,nR62,990 S 144,745 l

Total Deferred Credits $ AYNI,hh S 144,745

$57,531,680

TOTAL LIABILITIES $102[d[l'$2idf

- ._ r =

i

NEW liA31PSillRE ELECTRIC COOPERATIVE, INC. N' l

YEAR IN REVIEW e

GENERAL STATISTICS IN2 U 1981 Average Number of Accounts u 445,4921 44,448 Total hiiles of Electric unes 3,958 Number of New Services Connected During Year MEr 4,007;/

. ', O;1,209 1,345 Kilowatt. hour Sales - Total ( 356,796,481 352J99,018 Residential Sales [237,962,364l3 231,392,730 General (Commercial Sales) , I15,$82,414;, 1i7.754,199 Street & Yard Lights F 3,252.089 REA LONG TER$1 DEBT (LESS SEABROOK BORROWINGS)

Total Amount of Borrowing Authorized by REA ' zorpiv,% $52,687,000 Total Amount of Advances Q6,940,000g 52,376,000 Interest on Debt Coming Due & Paid During Year ig , 10 1,535,391 958,014 Principal on Debt Coming Due & Paid During Year 9 i Total Repayment of Interest & Principal to Date h

- $2

• $ 22,643,094 FIVE YEAR C051PARISONS 1982 1981 1980 1979 1978 Annual Kilowatt. hours Per h! ember (Domestic) 6,079 6,045 6,129 6,199 6,275 Annual Revenue Per Kilowatt-hour (Domestic) 8.38* 8.28* 6.80* 5.80e 5.21*

Average Distribution Plant Per 51 ember $ 1,125 51,061 998 947 892 Operations & Alaintenance Per hiile of Line S 376 5 315 5 344 5 307 5 279 Consumer Accounts Expense Per Niember 5 18 5 18 5 15 5 14 5 13 Number of Employees 177 176 175 178 178 Average Number of Consumers Per Employee 257 252 247 236 229 Operating Payroll Per 1,000 Kilowatt hours Sold S 5.98 5 5.26 5 5.21 5 5.01 5 4.41 Gross Payroll to investment in Distribution Plant 7.32% 7.16% 7.50% 7.41% 7.41%

Wholesale Cost of Power as a Percent of Revenue 71.56 % 73.52 % 71.26 % 67.13 % 64.31 %

t NOTE ON SEABROOK l

l The Cooperative is joint owner with other New England utilities of the Seabrook nuclear units now under i construction. In 1981, it purchased 2.17391 percent of each unit being built, acquiring 25,000 kilowatts of

( capacity in each unit. The plant was purchased from Public Service Company of New Hampshire, which is the l lead participant in the project (35.56942 percent) and which also is the principal wholesale supplier of power i

purchased by the Cooperative.

As of December 31,1982, the Cooperative has paid into Seabrook a total of $43,746,055 construction and related costs, borrowing the funds from the U.S. Federal Financing Bank in a loan guaranteed by the Rural Electrification Administration.it has also borrowed the funds necessary to pay interest on the borrowings to date.

The interest will be capitalized with other plant costs and be paid back over operating life of the plant. Total cost of construction and interest to December 31,1982 came to 549,480,606.

The lead owner's estimates of the cost of the two Seabrook units were increased substantially during 1982 as a j result of revised construction estimates and changes (delay)in scheduled completion dates.

The Cooperative,in 51 arch 1983, applied for $50 million of supplemental borrowing to complete its share of cost. Unit 1 is currently scheduled to operate in December 1984 with Unit 2 coming on line in mid.1987.

[

l I

fiq3ssMTN5Ii[p$koTfEEN ihTNeYhibkshdPE[c UtAtieYdoNmss ~ ~

' 'c'ord,iNeWHamp'shireLthe' Rural Eleitrificatio'n ~Administra'tioniWashingtorij D.C?and lthe,t

~

6 4 &

Coogisrative Office, Plymouth,'N.H3,r.;$,

.c t'I' D w w .2: a i_ W _ LM SW @M %#$'NG.f-VM5@6"

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,g.,a! c. u i ' m . .'. r'" n g a '-

MUNICIPAL LIGHTING PLANTS '

r. '. : ' q y'L.-]

" 'iS U N , ,,MS ,

EIje Commentucaltfj of JRaggacIjusetts RETURN OF THE b OF

$k C) D<SO K) Lt6 n T + PowfL D EPAe7Asui TO THE DEPARTMENT OF PUBLIC UTILITIES OF MASSACHUSETTS l

For the Year Ended December 31, 1982

~I EIje Commontnealtfj of Alaggatijugetts g

[

c .

OFFICE OF THE DEPARTMENT OF PUBLIC UTILITIES 100 Cambridge Street Boston, Massachusetts 02202 i

To the Mayors, Selectmen, Municipal Jght Boards and Managers of Municipal Lighting in the Several Cities and Towns in this Commonwealth operating Gas or Electric Light

< Plants:

This form of Annual Return should be filled out in duplicate and the original copy returned to the Office of the Department of Public Utilities, Accounting Division,

( by MARCH 31st in accordance with the requirements of the statutes

- ~

of the Commonwealth of Massachusetts and the regulatioTuiIof the' Department made in pursuance thereof.

Where the word "None" truly and completely states the fact, it should be given as the i

answer to any particular inquiry or portion of an inquiry.

l If respondent so desires, cents may be omitted in the balance sheet, income statement and supporting schedules. All supporting schedules on an even-dollar basis, however, shall agree with even-dollar amounts in the main schedules. Averages and extracted figures, where cents are important, must show cents for reasons which are apparent.

I Special attention is called to the legislation in regard to the Returns printed on the last page.

Inquiries and other communications in relation to Returns should be addressed to the l

DIRECTOR OF UTILITY ACCOUNTING I

I I

l 1

1 l

l Efje Commentucaltfj of Alaggacfjusetts RETURN i 0F THE

. . N. ... .. . 0F IIUDSO!I LIGIIT NiD POI.'ER D"PARZIENT l

TO THE DEPARTMENT OF PUBLIC UTILITIES OF MASSACHUSETTS For the Year Ended December 31, H rst !!uch aer Name of officer to whom correspondence should l., , , _, _

be addressed regarding this report. (

i Official title. . .W.n. age.r. . .  : Oflice address.O. .Forent . Avenue. .

Form AC 19. 500-12-71450708 Ilud s,o,n f , ,I.1A , , 01,7,4 9, , ,

M

2 TAHl,E OF CONTENTS Page General Information 3 Schedule of Estimates ~

1 Customers in each City or Town t Appropriations Since Beginning of Year 5 Changes in the Property 5 Bonds 6 Town Notes 7 Cost of Plant 8-9 Comparative Balance Sheet 10-11 Income Statement 12-13 Earned Surplus 12 Cash Llalances 11 31aterials and Supplies 14 Depreciation Fund Account 14 Utility Plant-Electric 15-17 Production Fuel and Oil Stocks 18 Aliscellaneous Nonopei ..ng Incomo "1 Other Income Deductions 21 31iscellaneous Credits to Surplus 21 Aliscellaneous Dobits to Surplus 21 Appropriations of Surplus 21 31unicipal Revenues 22 Purchased Power 22 Sales for Resale 22 Electric Operating Revenues 37 Sales of Electricity to Ultimate Consumers 38 Electric Operation and Alaintenance Expenses 39-42 Taxes Charged During Year 49 Other Utility Operatin Income 50 Income from hierchan ising, Jobbing and Contract Work 51 Electric Energy Account 57 31onthly Peaks and Output 57 Generating Station Statistics 58-59 Steam Generating Stations 60-61 Hydroelectric Generating Stations 62-63 Combustion Engine and Other Generating Stations 64-65 Generating Statistics (Small Stations) 66 Transmission Line Statistics 67 Substations 68 Overhead Distribution Lines Operated 69 Electric Distribution Services, aleters and Line Transformers 69 Conduit. Underground Cable and Submarine Cable 70 i Street Lamps 71 1 Rate Schedule Information 79 Signature Page 81 FOR GAS PLANTS ONLY:

Page Page Utility Plant-Gas 19-20 Gas Generating Plant 74 i Gas Operating Revenues 43 Boilers 75 Sales of Gas to Ultimate Consumers 44 Scrubbers. Condensers and Exhausters 75 Gas Operation & Alaint. Expenses 45-17 Purifiers 76 &

Purchased Gas 48 Holders 76 W Sa!"s for Resale 48 Transmission and Distribution Alains 77 Sales of Residuals 48 Gas Distribution Services. House Governors Record of Sendout for the Year in SICP 72-73 and Aleters 78 PAGES INTENTIONALLY 0311TTED: 23 to 36 and 53 to 56 M

3' I

GENERAL INFORMATION.

) 1. Name of town (or city) making this report. Hudson, Massachusetts 01749 fg 2. If the town (or city) has acquired a plant,

! Eind of plant, whether gas or electric. Electric Owner from whom purchased,if so acquired. Iludson Electric Light Company 7/1/1891

, Date of votes to acquire a plant in accordance with the provisions of 4.hapter 164 of the General Laws. 97171931 Record of votes: First vote: Yes. 30  ; No, 7 Second vote: Yes. 69  ; No. 11 Date when town (or city) began to sell gas and electricity, l

January 15, 1897 l 3. Name and address of manager of municipallighting:

Horst lluehmer es

4. Name and address NAen3rEyot o[rlA^Y en: EN9 Chairman George McGee, 271 Cox St. Hudson, MA 01749 Clerk: Paul R. Boire,10 Ridge Rd. Hudson, MA 01749 Joseph J. Durant, 22 Ilariman Road, Iludson, MA 01749 William G. Collette, 29 Maple St. Hudson, MA 01749 Albert A. Morel, Jr., 364 Main St. Hudson, MA 01749

5. Name and address of town (or city) treasurer:

David J. O'Neil 49 Temi Road Hudson, MA 01749

6. Name and address of town (or city) clerk:

Ralph Warner 18 Riverview Street Hudson, MA 01749 I

7. Names and addresses of members of municipallight board:

Chairman: Roland L. Plante, 136 Murphy St. Hudison, MA 01749 j Clerk: Richard J. Dion,110 Murphy St. Hudson, MA 01749 i Robert F. Wood, 14 Parkhurst Drive, Hudson, MA 01749 1

< 8. Total valuation of estates in town (or city) according to last State valuation 3309,000,000.00

9. Tax rate for all purposes during the year: 3 54.80

10. Amount of manager's salary: 3 48,433.38

O

11. Amount of manager's bond: 3 1,000.00 N 12. Amount of salary paid to members of municipallight board (each): 3 400.00

\

M

' 1:D PO Eti DEPARTMES2 OF llVD00 ; LIGlif A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Yeer end sd Oscsm bsr 31 Annuti rtport cf....... .....I..O..W..N .... ..............

FURNISil SCllEDULE OF ESTIMATES REQUIRED PY GENERAL LAWS. CIIAPTER 164. SECTION 57 FOR GAS AND ELECTRIC L1 Gilt PLANTS FOR TIIE FISCAL YEAR. ENDING DECEMBER 31. NEXT.

Amount.

INCOME FROM PRIVATE CONSUMERS:

! 1 From sales of gas. . . . .

2 From sales of electricity. .

10,083,762.00 3 TOTAL 10,083,762.00 4

4 5 EXPENSES:

9,000,507.00 6 For operatten, maintenance and repairs. , . ,

!, For interest on bonds, notes or scrip. . .. . , I one 7

For depreciation fund ( 5 per cent on 3 10,366,437.76 as per page 9). 543,321.3) 8 11,950.00 9 For sinking fund requirements. .

For note payments.. , .. . . . .  ::one 10 For bond payments. . .

1:one 11 For loss in preceding year.

i!one

! 12 13 T TAL l

9,835,778.89 14 15 Cost: For fiscal year.ending 6/30/04 Of gas to be used for municipal buildings. . . . . , IJone 16 None 17 Of gas to be used for street lights. . . .. . .

307,650.00 I 18 Of electricity to be used for municipal buildings. . . . ..

66,350.00 i 19 Of electricity to be used for street lights. . . . ..

374,000.00

! 20 Total of the above items to be included in the tax levy.. . . . ,,

21 New construction to be included in the tax levy. ..... .. . ... . . ..... Mone 22 Total amounts to be included in the tax levy. . . ... . . 374,000.00 y' 23 CUSTOMERS 1

! Names of the cities or towns in which the plant supplies Names of the cities or towns in which the plant supplies GAS, with the number of customers' meters in each ELECTRICITY, with the number of customers' meters in

' each Number of C astomers' Number of Customers' City or Town M eters. Dec. 31 City or Town

• Meters. Dec. 3t I 6211 IIudcon l Stcw 1910 i

l 1

3erlin, 3olton, Boxboro

Iarvard , liaynard,

iarlboro 100 i FOT APPLICABLE l

1

! I l

' TOTAL TOTAL 8221 u

., - . - - - ,-~

t 5

i TOWN 07 HUDSON LIGdr AUD POWEE DEPAhndi;N2 A".nuti ex port af. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

/ APPROPRIATIONS SINCE BEGINNING OF YEAR f (Include also all items charged direct to tax levy, even where no appropriation la made or required.)

e

) .

FOR CONSTRtlCTION OR PL'RCHASE OF PLANT:

'At meeting 19 , to be paid from t 3

• At meeting 19 . to be paid from t rOR THE ESTIMATED CORT OF THE gas OR ELECTRICITY TO BE t! SED BY THE CITY on TOWN FOR:

1. S t r eet lig hts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 53,000.00

2. Municipal buildings. . . . .@9.W.t,q, Aqq, ,$p,d p,ded. .iR .OEeT A11. .CPBIODE iations. . -

3. for each depart. tent TOTAL s 63,000.00

.o. .I ii.. . 4 6.in., r i., ., e-> tH.,. i ri b..a i r.

I CHANGES IN TIIE PROPERTY t . _ _ . _ _ _ _ .

q

1. Describe briefly all the important physical changes in the property during the last fiscal period including additions, alterations or improvements to the works or physical property retired.

In electric property:

t UQUE

--e l

l l

In gas property:

O a auw b

y Cn E

BONDS E (Issued on Account of Gas or Electric Lighting.)  !

i Period of Payments interest 2 Amount of Acnount Outstanding 8 Whsn Authorized

• Date of issue Original issuost et End of Year  :

Amounts When Payable p ete When Payable  :

April 7, 1913 Spec. June 1,1913 } .

S 9,000.00 Flarch 4, 1918 Reg. April 1,1918 .50,000.00 [

June 14, 1920 3pec. Feb. 1,1921 25,000.00 i

Slarch 5, 1928 Reg.Nov. 1,1928 40,000.00 -[>h Nov. 29, 1954 3pec. Mar. 1,1955 250,000.00 i9 starch 7, 1955 leg.May 1, 1955 100,000.00 jE 91 arch 7,1955 leg.Nov. 1, 1955 150,000.00 iG June 8, 1959 3pec.Aug. 1, 1959 300,000.00 lov. 7, 1961 3pec. July 15, 1962 450,000.00 l:_$

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c

O

c I

!b

0

.P*r i t i ei t

:a L

i O

R I

$1,374,000.00 * *' O The bonds and notes outstanding at end of year should agree with the Balance Sheet. When bonds and notes are repaid report the first three columns only. g D.te et nie tins and .-hethe, ,esut.r o, .peci.t. Ita. e,isi i or bona. a mot incluaias tho.e th.: h ve b a ,etired.

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TOTAL COST OF PLANT -ELECTRIC l.

1. Report below the cust of utility p!sr.t in service ceding year. Cuc!. iternnhouldte included in column effect of such as ounts.

according to prescribed accounts. (c) or (d) as appropriate. 4. Reclassifications or transfers within utility plant j

2. Do not include as adjustments. corrections of 3. Credit adjustments of plant accounts should accounts should be shown in column (!). 3 additior.s and retirements for the current or the pre- le enclosed I. parentheses to indiente the negative '

Balance  :

Beginning Balance j Litts Account of Year Additions itetirements Adjustments Transfers End of Year  :

N s. (e) (b) (c) (d) (e) (f) (g) j

e.1 1 1. INTANGIBLE PLANT $ $ $ $ $ $ io 2 i!

3

• O

w 4 i :=

5 2. PRODUCTION PLANT l@

6 A. Steam Production jg 7 310 Land and Land Rights. . . ... !M 8 311 Structures and Improvements. .  ![

9 312 Boller Plant Equipment. . ..

l@

10 313 Engines and Engine Driven !6 Generators. . . . ... .. *h 11 314 Turbogenerator Units. ... . .. i0 12 315 Acceuory Electric Equipment. ... l@

i 13 316 Miscellaneous Power Plant j@

14 Equipment. . . . .. .....  !:n l 15 Total Steam Production Plant. ig I

16 - D. Nuclear Production Plant ip i 17 320 La'n d and Land Righ's.

t . .. 944.00 944.00 im 18 321 Structures and Improvements. . . .

19 322 Reactor Plant Equipment. .... j2 l 20 323 Turbogenerator Units. . ... j' 21 324 Accessory Elcetric Equipment.

y

22 325 Miscellaneous Power Plant  !

Equipment. .. . g 23 Total Nuclear Production Plant 944.00 None None None Mone 944.00 1

. k

, 4

[x

.e N

I 300

, N 1

1

- w 4

~

h  %

f -

TOTAL COST OF Pl. ANT -ELECTitIC (Continued) j t.

Balance Saginning elYaa, Additions Rotbemonts Adj,astment s T,a nsfe,s Data nce End el Yea, f2 Lane Account No. (a) (b) (c) (d) (e) (f) (g) 8.,

C. Hydraulie Production Plant 8 8 8 5 $ $

2 330 Lan.1 and Land Itights. . .

3 331 Structures and improvements., . 3 4 3:12 Ileservoirs, Dams and Waterways 5 333 Water Wheels, Turbines and e jg Generators. . .. .. .. . 3g 334 Accessory Electric Equipment. .  :

6  : o 7 335 Miscellaneous Power Plant :w

• g Equipm<ent . . . . .. .

8 33G lloads, Railroads and Bridges. :o U ne Hone Mone None Hone None j 9 Total llydraulie Production Plant 10 D. Other Production Plant jg 11 340 Land and Land Itights. . .. 5,500.00 None 5,500.00 j#f 12 341 Structures and improvements. . . 332,639.70 123.00 332,767.70 jg 13 312 Fuel lloiders, Producers and  :>

Accessories. . . .. .. . 124,588.30 Mone 124,58G.30  !@

14 313 Prime Movers. . 2,452,173.12 4,272.00 2,456,445.92 j[,e 15 344 Gentrators. . . . 287,549.94 None 287,549.94 [3 16 345 Accessory Electric Equipment. 832,477.01 None 832,477.01 jy 17 34G Miscellaneous Power Plant 20,666.07 6,210.00 26,876.07 ie

ty Equipinent. , .. p5g4, g gg g77- 4,0 06,z04. '3 4  :*C 18 Total Other Production Plant

• 4,056,536.14 10,610.80) 4,06/,146.34 N y

19 Total Production Plant. . .

20 3. TitANSMISSION PLANT 53,804.14 ed 21 350 Land and Land Itights. . 53,004.14 , "

351 Clearing Lund and Itights of Way None Done 22 -

168,166.00 - 158,166.08 g 23 352 Structures and improvements. . .

24 353 Station Equipment. . 298,280.34 298,288.34  ;

5 354 Towers and Fixtures. .. .

Ilone Monc A A

26 355 Poles and Fixtures. . 790,839.02 795,839.02 c, 35G Overhead Conductors and Devices 227,329.01 227,329.01 2 27 28 357 Underground Conduit. .. 258.07 258.07 j 29 358 Underground Conductors and t Devict s . .

gone  !!one  :-

30 359 Itoads and Trails. . 3 g

31 Total Transmission Plant. 1,544,684.G6 Uone t'one None Done 1,544,684.66

I 10 un u , ,, ae. . . . .. ....l.'0.W..N OF HUDSON LIG11T AND POWER DEPART 10i212........,....,...........,,,,,,,,,,,,,,,,,,,,,,,,

l*

COMPARATIVE BALANCE SHF T Assets and Othee Debits ,

8elence Beginning of Balance increase yn, Title of Account Year End of Year o, (Decrea se)

No. (a) (b) (c) (d) 1 UTILITY PLANT 101 Utility Plant - Electric (P.17). . 4,774,9'l5.27 4,942,990.19 168,054.92 2 ..

3 101 Utility Plant - Gas (P. 20). . . .. None None None 4

5 Total Utility Plant. .

4.774.935.27 4,942,990.19 168,054.92 6

7 8

9 I 10 11 FUND ACCOUNTS 125 Sinking Funds. None None None 12 .

13 126 Depreciation Fund (P.14). 1,661,315.44 1,903,394.95 242,079.51 14 128 Other Special Funds. . .

88,140.07 29,226.28 ( 58,913.79) 15 Total Funds. 1,749,453.51 1,932,621.23 183,165.72 t 16 CURRENT AND ACCRUED ASSETS 17 131 Cash (P.14). 2.80 9,166.90 9,164.10 18 132 Special Deposits. 128,221.07 117,743.71 ( 10,477.36) 19 135 Working Funds. ... ..

. 200.00 200.00 None

, 20 171 Interest &.Div. Recei.vable.... 26,755.32 12,631.59 ( 14,123.73) 21 142 Customer Accounts Receivable. 945,533.82 971,951.72 26,417.90 22 143 Other Accounts Receivable. 16,854.35 15,066.33 ( 1,788.02) )

23 146 Receivables from Municipality. 5,657.88 None ( 5,657.88) 24 151 Materials and Supplies (P.14). 843,839.79 908,765.30 64,925.51 25 173 Accrued Utility revenue 277,915.70 None ( 277,915.70) 26 165 Prepayments. . 210,180.13 219,070.49 8,890.36 27 174 Miscellaneous Current Assets. . .00 452.51 452.51 28 Total Current and Accrued Assets.. 2,455,160.86 2,255,048.55 ( 200,112.31) 29 DEFERRED DEBITS l 30 181 Unamortized Debt Discount. . None None None 31 182 Extraordinary Property Losses None None None I

32 185 Other Deferred Debits. 42,111.37 34,387.96 ( 7,723.41)

! 33 Total Deferred Debits. 42,111.37 34,387.96 ( 7,723.41)

I 34 9,021,663.01 9,165,047.93 14 3_f384.92 3r Total Assets and Other Debits.

i 45 k

l8 TO'#N OF flVDSON LIGilT AND F0nh D&AMMERI ~

ag Annual ,eport of.. . . . .. .... . . . .. Year ended December 31.19M

' COMPARATIVE BALANCE SilEET Liabilities and Other Credits Balance Beginning of Balance increase Tette of Account Year End of Year or (Decrease)

Une No. (a) (b) (c) (d) 1 APPROPRIATIONS _ _

2 201 Appropriations for Construction. None None _ None_

3 SURPLUS None None None 4 205 Sinking Fund Reserves.

1,925,000.00 1,925,000.00 None 5 206 Loans Repayment.

20,093.39 20,093.39 None 6 207 Invest . by Municipality 208 Unappropriated Earned Surplus (P.12).

6,125,985.12 6,743,689.71 617,764.59 7

8 Total Surplus. 8,0712 078.51 8,688,78_3.10 617,704.59 9 LONG TERM DEBT None None None 10 221 Bonds (P. 6).

231 Notes Payable (P. 7). None None None 11 12 Total Bonds and Notes. None ~~lT6ne None 13 CURRENT AND ACCRUED LIABILITIES 232 Accounts Payabic. 772,554.09 284,906.11 (487,647.98) 14 15 234 Payables to Municipality. None None None 16 235 Customers' Deposits. 128,221.07 117,743.71 ( 10,477.36) 17 236 Taxes Accrued. None None None IS 237 in'.erest Acerued . None None None 19 242 Miscellaneous Current and Accrued Liabilities 12,787.34 4,668.39 ( 8,118.95) 20 Total Current and Accrued Liabilities. . 913,562.50 407,318.21 (506,244.29)

') 21 DEFERRED CREDITS 22 251 Unamortized Premium on Debt. None None None 23 252 Customer Advances for Construction. 33,800.00 32,400.00 ( 1,400.00) 24 253 Other Deferred Credits 3 J22.00 4 276.50 1,054.50 25 Total Deferred Credits. 31 022.00 36_J76.50 ( 345.50) ed RESERVES 27 260 Reserves for Uncollectible Accounts.

23 261 Property Insurance Reserve.

29 262 Injuries and Damages Reserves.

30 263 Pensions and Benefits Reserves.

31 265 Miscellaneous Operating Reserves.

fone

~

32 Total Reserves. None None 33 CONTRIBUTIONS IN AfD OF CONSTRUCTION 34 271 Contributions in Aid of Construction. None ~'3 2~,~270.12 32,270.12 35 Total Liabilities and Other Credits. 9,021,663.01 9,165,047.93 143,384 97 -

State below if any earnings of the municipallighting plant have been used for any purpose other than discharging indebted-ness of the plant, the purpose for which used and the amount thereof.

12 runa OTr HUDSOU LIG111 AUD POM.R DEPAkfMENT. . . . . . . . . . . . . . . . . . . . . . . . . . . .

g A nnuti report 6f... ... ... .. . . . .

STATEMENT OF INCOME FOR THE YEAR Total i increase or (Decrease) froni Account Current Year Preceding Year une No. (a) (b) (c) 1 OPERATING INCOh!E 113,182.28 H 9,697,661.22 S 2 400 Operating Revenues (P. 37 and 43) .

3 Operating Expenses: 192,805.80 8,240,269.40 8 401 Operation Expense (P. 42 and 47) .

342,342.72 41,232.87 5 I 400 Alaintenance Expense (P. 42 and 47) .

532,027.29 21,600.77 6 l 103 Depreciation Expense. None 7 1 407 Amortization of Property Losses. None

8

' 4,808.11 1,209.23 9 408 Taxes (P. 49).

Teta! Oparating Espenses 7,119 ,4 4 I . W 256,B48.67 10 l Operating Income. 578,213.70 (143,666.39) 11 i 10 ' 414 Other Utility Operating Income (P. 50). None None gl Total Operating Income. 578,213.70 (143,666.39) 14 !

15 OTilER INCOh!E IG 415 Ineome from Sterchandising, Jobbing and Contract Work (P. 51) 17 ! 419 Interest Income.

215,N$:N I lbbN*h 18 42131iscellaneous Nonoperating Income. None None 19 Total Other Income. 216,740.34 15,925.34 20 Total Income. .. 794,954.04 (127,741.05) _

21 atISCELLANEOUS INCOhlE DEDUCTIONS 22 125 Misa.llaneous Amortization. . None None 23 42G Other Income Deductions. None None 24 Total Income Deductions. None None 25 Income Before Interest Charges. 794,954.04 (127,741.05) 26 t INTEREST CHARGES Nou None 27 427 Interest on Bonds and Notes. . .

28 428 Amortization of Debt Discount and Expense.

one None 29 429 Amortization of Premium on Debt -Credit.

2,249.45 2,531.51 30 431 Other Interest Expense.

None None 31 432 Interest Charged to Construction - Credit.

32 Total Interest Charges. 2,249.45 2,531.51 33 NET INC011E. 792.704.59 (130,272.56)

EARNED SURPLUS Debits Credits une * (b) (c)

No. ' (a) 31 208 Unappriipriated Earned Surplus (at beginning of period).

6,125,985.12 35 f 3G '

37 ! 433 Balance Transferred from Income.

792,704.59 33 13 8 hliscellaneous Credits to Surplus (P. 21).

39 , 435 aliserilaneous Debits to Surplus (P. 21).

10 !136 Appropriations of Surplus (P. 21). 175,000.00 41 437 Surplus Applied to Depreciation.

42 208 Unappropriated Earned Surplus (at end of period). 6,743,689.71 43

• • " 6,918,689.71 6,918,689.71 48

14 R T 82 Annuit report af....... .... .. ..T. .O.W.N....O.F. H.UDSO..N.

. . . . . . . . . . . . . L.IG.11T...A.ND

. . . . . . . . . . . . . . . . . . POWER LEPA TM dit. ........ veer snded Diesmbst CASH BALANCES AT END OF YEAR (Account 131) items Amount Lintf No. , (a) (b) 1 i

9,166.90 1 Operation Fund. . .. .

!Jone 2 Interest Fund. , . .

IJone 3 Bond Fund. . . . ....... .

25,531.88 4 Construction Fund . . . . .(.12 8). . . , , .

2,704.02 5 141scellaneous Cash (128)

Advances from Contractors (128) 990.38 6

7 8

9 10 11 12 TOTAL 38.393.18 MATERIALS AND SUPPLIES (Accounte 151-159. 163)

Summary Per Balance Sheet Amount End of Year A" " "' Electric Gas Line (c)

No. (a) (b) 710,958.95 13 Fuel ( Account 151) (See Schedule, Page 25). . ... . . ..

14 Fuel Stock Expenses (Account 152). . . . . . .. . . . . .

1:0T 15 Residuals (Account 153). . . .. .

197,806.35 16 Plant Materials and Operating Supplies (Account 154). .

)

APPLICABLE 17 Merchandise (Account 155). .... .. .. . .

18 Other Materials and Supplies ( Account 156). . . . . . . .... .. . . .

19 Nue! ear Fuel Assemblies and Componenta -In Rer.ctor (Account 157). .

10 Nuclear Fuel Assemblies and Components - Stock Account (Account 158) 21 Nuclear Byproduct Materials (Account 159). . . .. .

22 Stores Expense (Account 163). . . . .. ....... .... . .. . .

Total Per Balance Sheet 3. . ..... . . ... . . 908,765.30 23 DEPRECIATION FUND ACCOUNT (Account 136)

Amount une (b)

No. (a) 24 DEBITS .

1,661,315.44 25- Balance of account at beginning of year. .. .. ... . . . . ... .

220,823.64

(

26 Income during year from balance on deposit. . . . ..

532,027.29 27 Amount transferred from income. . ..... ...

145,365.00 28 Reimbursement for plant sold or daraaged 29 TOTAL o ;44;GU _17 30 CREDITS 656,136.42 31 Amoun't expended for construction purposes (Sec. 57, C.164 of G.L.). . .

32 Amounts expended for renewals. viz.:-

33 34 35 36

)

37 38

. .. 1,903,394.95 39 Balance on hand at end of year. . . .. . .. . .. . .

~

TOTAL 2,559,531.37 40 M

- -y - , .

m

_- e

?

UTILITY PLANT-ELECI'RIC I

~

ceding year. Such items should be included in column efect of such amounts.

1. Report below the items of utility plant in service 4. Reclassincations or transfers within utility plant according to prescribed accounts. (c). accounts should be shown in column (f).

2. Do not include as adjustments, corrections of 3. Credit adjustments of plant accounts should ,

additions and retirements for the current or the pre- be enclosed in parentheses to indicate the negative j Balance '

Balance Beginning Adjustments Additions Deprocletion Other Credits Transfers End of D i Line Account of Year (g)  :

(b) (c) (d) (e) (f)  :

No. (a) i3

$ $ $ $ j 1 1. INTANGIBLE PLANT $ $

j$

2 f i-c tc 3

i :o f

4

2. PRODUCTION PLANT

! 5 i*

i 6 A. Steam Production

!.C l

7 310 Land and Land Rights. . :oH i .8 311 Structures and Improvements. i :::

9 312 Boiler Plant Egalpment. . .

se 313 Engines and Engine Driven .o I

I 10 j 11 Generators. . .

314 Turbogenerator Units. .

jo as

,M 12 315 Accessory Electric Equipment. . '

to 13 316 Miscellaneous Power Plant i t=r Equipment.

14

[Ew i

15 Total Steam Production Plant. iH 16 B. Nuclear Production Plant i

17 320 Land and Land Rights. . ..

944.00 944.00 ih

+ 18 321 Structures and Improvements. .  :

. [

19 322 Reactor Plant Equipment. . . . . .  :.

20 323 Turbogenerator Units. . . ... .

21 324 Accessory Electric Equipment..

22 326 Miscellaneous Power Plant I i Equipment. . ..

I 23 Total Nuclear Production Plant 944.00 944.00 F

5

-  ?

' 7

~

I B-e

> E

=

, UI'lLITY PLANT-ELECTRIC (Contleued) 1 Bolence Beginning Adjustments Belence Line Account of Year Additions Deprocletion Other Credits Transfers End of Year No. (a) (b) (c) (d) (e) (f) (s)  %

i 1 C. Hydraulic Production Plant $ $ $ $ $ $

2 330 land and Land Rights. . . . ...

3 331 Structures and Improvements....  !

4 E32 Reservoirs, Dams and Waterways 5 333 Water Wheels, Turbines and y@

i Oenerators.....................

6 334 Acaa=Wy Electric Equipment.... 9 7 335 Miscellaneous Power Plant  !$

Equipment . . . . . . . ..... ..... !E 8 336 Rcads, Railroads and Bridges. . . i@

9 Total Hydraulic Production Plant N ne None None None None Non  ; ,,,

10 D. Other Production Plant IE 11 340 Land and Land Rights. . . . .

5,500.00 29,517.10 128.00 4,157.99 5,500.00 25,487.11 g

1,.

. 341 Structures and Improvements. .  : >.

13 342 Fuel Holders, Producen and 24,312.54 3,114.70 21,197.84 Accessories. . . . . . . .... ...  : *e 488,115.19 4,272.80 76,893.02 415,494.97 :o 14 343 Prime Movers . . . . . . . . . . . . . . .  : si 37,873.45 3,594.37 34,279.08  : ta 15 344 Generators. . . . . . . . . . . . . . . .  :- se 111,252.84 10,405.96 100,846.88 16 345 Accessory Electric Equipment.... i ta 17 346 Miscellaneous Power Plant 2,348.46 6,210.00 258.33 8,300.13  : $.

i>

18 T tal ther r uction Plant ' * 'D * * * # '

• 19 Total Production Plant. . . . . . . . .

20 3. TRANSMISSION PLANT' l i

21 350 Land and Land Rights. . . . . . . . . 53,804.14 53,804.14 i 22 351 Clearing Land and Rights of Way 25,964.43 4,204.15 21,760.28 j 23 352 Structures and Improvements. . . . 80,337.55 11,185.81 69,151.74 4 24 353 Station Equipment. . . . . . . . . . . 84,952.12 9,920.98 75,031.14 I 25 354 Towers and Matures. ... .

None None None {

16 355 Poles and Flutures. . ... . ..

496,910.92 142,226.32 354,684.60 1 27 356 Overhead Conductors and Devices 140,273.24 11,366.45 128,906.79 y 28 357 Underground Condult. . . . . . . . . 196.90 12.90 184.00 $

cr 29 358 Underground Conductors and  %

Devices. . . . . . ...... ......

None None None ,$

30 359 Roads and Trails. . . . .

Nou Nou Hone g 31 Total Transmission Plant. . 882,439.30 178,916.61 703,522.69 h

_ m

.. v v i

g-UTILITY PLANT- ELECTRIC (Continued)  !

{

eatence Beginning Adjustments Selence j Line Account of Year Add tions Dep,eciation Othe, C, edits Transfers End of Year 6 No. (e) (b) (c) (d) (e) (O (s) f 1 4. DISTRIBUTION PLANT $ $ $ $ $ $ f 9 360 Land and Land Rights. .. .

None Hone Mone I J 3 361 Structures and Improvements. . 1,475.22 172.09 1,303.13  !

4 362 Station Equipment. .. . . ..

247,424.20 19,867.39 227,555.1 ( j es 5 363 Storage Battery Equipment.. .. Ilone lione Hone i 6 364 Poles, Towers and Fixtures. . . . . 78,617.29 24,881.6li 21,0Gl.39 3,405.95 74,031.60 I

!O 7 365 Overhead Conductors and Devices 294,102.84 99,501.00 55,708.72 7,337.35 330,507.77 8 366 Underground Conduit. .... ... 76,841.84 4,365.67 5,696.93 3.50 75,502.08  !=

9 3%7 Underground Conductors & Devices 207,442.42 19,920.0G 13,658.45 16,397.75 197,306.28 iE' j 10 368 Line Transformers. . . . . .

367,514.53 19,934.31 47,265.17 1,395;36 338,833.31 !E i 11 369 Services. . . .

112,553.36 11,709.17 14,960.03 673.59 108,628.91 iY '

! 12 370 Meters. . . . .. . . . . 104,583.14 24,,684.24 15,025.91 1,484.21 112,757.26 !b

• 13 371 Installations on Cust's Premises. . None Mone None Hone None. 3E 372 Iaaned Prop. on Cust's Premises.. None None Mone None Mone 14 15 373 Street Lighting and Signal Systems 6E.A71 - ~7 7 A.A4^ "3 12 640.56 976.6.2_ En,ns1 15 !g 16 Total Distribution Plant. .. .

1.556.176.61 211,902.93 206.057.14 36.729.40 1.525.291_00 jc l

j 17 5. GENERAL PLANT iE I

18 389 Land and Land Rights. . .. None Hone Hone None Mone j*

ik 390 Structures and Improvements. . . 206,691.90 3,580.15 21,288.55 188,9C3.50 fI 19 i 20 391_ Office Furniture and Equipment. 168,631.37 33,021.75 11,510.82 12,133.10 170,009.20 i$

j ,

21 392 Transportation Equipment. ... 102,186.13 13,011.65 12,532.42 102,665.36 g

{ 22 393 Stores Equipment. . . . . . . .

7,208.36 550.80 535.24 7,223.92 it" 23 394 Tools, Shop and Garage Equipment 4,367.81 3,131.80 374.74 7,124.87 24 395 Laboratcry Equipment.. . .

16,802.76 771.55 942.79 16,631.52 880.01 6

25 396 Power Operated Equipment.. . .. 936.92 5C.91 y 26 397 Communication Equipment. ..

11,085.04 1,21G.09 9,868.95  ;

7 '

27 398 Miscellaneous Equipment., ..... 2,308.72 205.95 171.61 2,343.06 1 5 764_60 n- 7a?_7K A,971_93 1

! 28 399 0ther Tangible Property. . . . . . . .

29 Total General Plant.. 979 47 t 7n 94 ?71_Es aR.g?q_17 17_qin_nn 519,702.32 ['

30 Total Electric Plant in Service.. 3.664.491_19 276.787_3R 512_027_99 10 . 6.t 9 _ ? M __ 3,35h569_02 1 j 31 104 Utility Plant Isased to Others.. . None Hone Mone None Hone Hone ,

32 105 Property IIeld for Future Use....

1,1 D 82.08 4h3340.09 k!oS$  !}oSe kkoS$ 1,58b32.17 5 33 107 Construction Work in Progress. .

34 Total Utility Plant Electric.. . 4,774,935.27 749,727.47 532,027.29 49,645.26 None 4,942,990,19 g

i

l'ItOI)UCTION FUEI. AND OII. STOCKS tincluded In Account ISI) k (Except Nuclear Materials) 1

1. Iteport below the information called for concerning production fuel and oil stocla. I

2. Show quantities in tons of 2,000 lbs., gal., or Mcf., whichever unit of quantity la. applicable. $

3. Each kind of coal or oil should be shown separately. e,

4. Show gas and electric fuels separately by specific use. j

~

• Kinds of FJel and Oil g,,,

1. 2 DIFSEL GAS MCF tons item Cost ~ Quantity Cost Quantity Cost  :

fio. (a) (b) (c) (d) (e) (f) *y

• :s On lland Beginning of Year. 8 665,224.52 1,202,376 3 665,224.52 None 3 None 1

2 Iteceived During Year. 1,113,589.60 258,503 245,577.85 195,865 868,011.75  !"O i

3 TOTAL. 1,778,814.12 1,460,879 910,802.37 ___

195,865 868_,_01_1.75 j@

4 Used During Year (Note A). .

1,067,855.17 278,918 199,843.42 l 195,865 868,011.75 !E 5 i 9

6 :e

s i9 8

i. E U

10

!b

o jg 11 Sold or Transferred. _,

12 TOTAL DISPOSED OF. 1,0_6_L8_15_,17 278.218 199,813 A los;nAs n68,01L75 [g 13 BALANCE END OF YEAlt. 710,958.95 1,181,961 710,958.95 None None i 80 Kinds of Fuel and Oil - Continued *N ~

p.

tins Item Quantity, Cost Quantity Cost f No. (g) (h) (i) (j) (k)  :

- i 14 On liar.d Ifeginning of Year. 3 3 jN j

15 Iteceived During Year. l 16 TOT.b. l l Used D)uring Year (Note A).  :

17 . ,

18 {

19 la 20 1 21 {

r a j 23 (

24 Sold or Transferred. p 25 TOTAL DISPOSED OF. .  ;;;

2G BALANCE END OF YEAlt. .

CD 19 Note A - Indicate speci6e purpose for which used, e.g., Boiler Oil, Make Oil, Generator Fuel, etc.

V

TO'KN OF !!UDSON LIG11T AND POWER DEPARTMENT A n nu d esport ef. , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Yx r E nd ed D Ictm b re 31, 19 g",

MISCELLANEOUS NONOPERATING INCOME (Account 421)

Une item Amount

no, (a) (b)

) 1 2

3 4

5 T TAL None 6

OTHER INCOME DEDUCTIONS (Account 426)

Une item Amount No. (e) (b) 7 3

9, 10 11 12 13 14 None MISCELLANEOUS CREDITS TO SURPLUS (Account 434)

Une item Amount No. (a) (b) 15 16 17

) 18 19 20 21 22 T TAL None 23 MISCELLANEOUS DEBITS TO SURPLUS (Account 435)

Une item Amount No. (a) (b)

~~..

24 25 26 27

, . 28 t

i 29 30 TOTAL 32 None APPROPRIATIONS OF SURPLUS (Account 436) item Amount Line No. (a) (b) 33 Transferred to Town Treasury 175,000.00 34 37

. 38 39 707^' 175,000.00 40

n ,- -- ,,

I 22 TOWN OF !!UDSON LIGHT AND' PO?iER DEPARTMENT.........Ystr EndId DIcembir 0231.19,4w Arnuelreportaf................................................................................

MUNICIPAL REVENUES (Accounto 482. 444)

(K.W.H. sold under the provisions of Chapter 269, Acts of 1927)

Average Revenue Cubic Feet Revenue Received per M.C.F. J Gas Schedule (50.0000)

Lina Acc.t (c) (d)

No. No. (a) (b) 1 482 a

3 11 O T A?PLIC ADLE 4

TOTALS Average Revenue per K.W.H.

Doctric Schedule K.W.H. Revenue Received ts (b) (c) (d)

(a) 5 444 Municipal: (Other than Street Lighting) 6 All Electric 5,892,000 350,239.61 .059443 7 Power 3,193,919 229,437.96 .071836 8 Commercial 310,276 28,232*.G6 .090992 Yard Lighting 22,305 2,200.22 .096480 9

10 II 9,419,000 610,110.45 .064774 Totals 12 Street Lighting: Town of Iludson 1,150,283 75,244.58 .065414 13 Town of Stow 64,360 6,388.90 .107037 14 Towns of M lton & Berlin 1,176 133.43 .113461 15 16 17 _ ng7(:s a m ALs 1,215,819 82.266.91 18 TOTALS 10,634,819 692,377.36 .065105 19 PURCHASED POWER (Account 555) Cost per K.W.H. Names of Utilities Where and at What Amount (cents) from Which Electric Voltage Received K.W.H. (0.0000) Line Energy is Purchased (d) (e) No. (a) (b) (c) 20 21 22 SEE PAGES 54 & 55 POR DETAILS 23 24 25 26 27 28 TOTALS 121,547,438 4,686,169 3.8554 29 SALES FOR RESALE (Account 447) Revenues per K.W.H. Names of Utilities where and at What Amount (cents) to Which Electric Voltese Delivered K.W.H. (0.0000) Lin') Energy is Sold (d) (e) No. (a) (b) (c) 30 31 SE". PAGES 52 & 53 FOR DETAILS 32 33 - ). 34 35 36 i 37

 -      $8 TOTALS         71.700                       2.757                     11.8836

D " w E 2. ELECTRIC OPERATING llEVENUES (Account 400)

1. Report below the amount of operating revenue for added for billing purposes, one customer shall be counted

4. Unmetered sales should be included belon. The f 2

the year for each prescribed account and the amount of for each group of meters so added. The average number details of such

5. Classification sales should of Commercial andbeIndustrial given in Sales, a footnote. o increase or decrease over the preceding year. of customers means the averrge of the 12 Agures at the Account 442, according to Small (or, Commercial),and 3

2. If increases and decreases are not derived from close of each month. If the customer count in the resi- I

                                                                                                                                                                           ]      be ac dm o the byts                   .

previously reported Agures explain any inconsistencies. dential service classincation includes customers counted k*gh"g'go,"dh,*I**Y

                                                                                                                                                                     ,         ,ed ,g

3. Number of customers should be reported on the more than once because of special services, such as water basis of classificatlan is not greater than 1000 Kw of  :

basis of number of meters, plus number of flat rate heating, etc., indicate in a footnote the number of such demand. See Account 442 of the Uniform System of In accounts, except that where separate meter readings are duplicate customers included in the clasalAcation. Accounts. Explain basis of classiacation. T

o l !N Operating Revenues Kilowatt-hours Sold C mers pe onth Increase or Increase or tastasse or iE Amount for (Decrease) f,om Amount for (Decrease) f,om Number for (Decrease) from  : "O Account Year Year Proceding Yaar Year heceding Year jo Line Precf(ing (g)

No. (a) (b) c) Year (d) (e) (f)  : cc i t* SALES OF ELECTRICITY $ $ iU 1 3,800,775.13 ( 158,463.14) 52,649,657 422,511 7121 126 ig 2 440 Residential Sales. . . . . . ............ 442 Commerei;l and Industrial Sales: 3 502,614.54 15,367.13 5,584,192 361,453 703 58 j';j 4 Small (or Commercial) see instr. 5. . . 77,976,321 165 (5) i, 4,903,493.56 348,535.32 }0,780,941 5 Large (or Industrial) see instr. 5. . . . . 692,3'Z7.36 (14,452.57) 10,634,819 257,411 87 5 *g 6 444 Etuniefpal Sales (P. 22) . ........... None None *y None None None None 7 415 Other Sales to Public Auth'orities. . . . None he 2ne None None None ja 8 446 Sales to Railroads and Railways.. . .. " "" " "* " "* ( ' * ' * " "* 55 9 449 Fuel Charge Adjustmerit.... 46,384.87 ( 953.04) 464,491 7,109 133 3 *g 10 449 31iscellaneous Electric Sales. . . . . . . . . . 9,667,729.76 213,976.50 147,309,480 3 1,829,425 8209 187 11 Total Sales to Ultimate Consumers. . . . 2,756.68 (107,437.46) 23,200 1 1,001,699) 1 (1) . I~ 447 Sales for Resale ~ ** ' '"'" 9,670,486.44 106,539.04 147,332,680 J O,827,726 6210 186

• Total Sales of Electricity *. . ........ j 13 ~

14 OTilER OPERATING REVENUES '  :. 15 450 Forfeited Diccounts.. .. .......... None None 16 451 Afiscellaneous Service Revenues. . . ... . None None .i

• Includes revenues from application of fuel clauses $..i.'.94 9.d.6,?,. 5,j ,,,,,

g 453 Sales of Water and Water Power. . . . .. None None

• 17 454 Rent from Electric Property. . . .. . . . . . None None 18 None None Total KWH to which applied . . . . . . . .l.4 6,,,y,9, ,1,9,7, _ ,, a 19 455 Interdepartmental Rents. . . . . . . . . . . . E 56.22 (91.42) 20 456 Other Electric Revenues. ...........

27,118.56 6,734.66 y 456-1 Other Elec. Revenues 21 RCS i oo. 23 2 24 27,174.78 6,643.24  ;; Total Other Operating Revenues. . . . . . 25 16 Total Electric Operating Revenues.. . 9,697,661.22 113,182.28 h9

35 R se ndid DIesmbi, 3

                                .... ...... .P. .O.W..N....O.F...li.U..D..S..O.N...L..I.G.11.T...A..N..D...P.O..W.E.R....D..E.P.A..R..T..M.I..N..T..........YM, Annuel F; port 6 f.......                              .          .                     .         .

SALES OF ELECTRICITY TO ULTDIATE CONSU.\1ERS Report by account, the K.W.!!. sold, the arnount derived and the nurnber of customers under each filed schedule or contract. Contract sales and unbilled sales muy be reported separately in total.

                                                                                                                   ^'8' reumbe, of Customers                   )

g g, (Per OHis Rendered) (cents) Uns Account Schedule K.W.H. Revenue (0.0000) July 31. December 31. p N D. No. (e) (b) (c) (d) (e) (f) . 1 440 *A" Rate Donostic 39,668,895 1 2,992,051.16 .075426 6511 6597 2 442 "C" Rate Commercial 5,458,796 49?.,533.66 .090603 734 717 3 442 'D" Rate Power 77,976,321 4,903,493.56 .062834 168 161 4 440 F" Rate All Elec. 12,980,762 808,723.97 .062302 604 622 5 442 G" nate Com. Heat 125,396 8,030.08 .064044 3 3 6 444 Street Lighting 1,215,819 82,266.91 .0675C4 4 4 444 IIunicipal Sales 9,419,000 610,110.45 .064774 92 32 7 449 Yard Lighting 464,491 46,384.37 .099362 125 129 8 449 Fuel Charge Adj. (277,915.70; 9 10 11 12 13 14 15 1G 17 18 19 20 21 ) 22

   ~

23

        '4 25 26 17 28 29 30 31 l        32 1

33 1 34 l _ l 35 36 37 38 39 40 41 O l 42 O 43 l 44 45 ^ 46 47

                                                                                                                                                                          )

48 49 TOTAL SALES' TO ULTntATE I i 147,309,480 9,667,729.76 .065629 8241 8325 ,; CONSUMERS (Pare 37 line 11)

                                                   ~

39 u n u. ,: oo,i o, . . . .TOWN . . . . OF . . IfUDSON

                                                                  . . . . . . LIG!!T
                                                                              . . . . .AND  . . .POWER     . . . . . DEPARTENT ELECTRIC OPERATION AND MAINTENANCE EXPENSES 1, Enter in the space provided the operation and maintenance expenses for the year.

() L

2. If the increases and decreases are not derived from previously reported figures explain in footnote.

Increase or I #' '} "' Account Amount for Year Pteceding (b) (c) No. (a) 1 POWER PRODUCTION EXPENSES h STEAM POWER GENERATION 3 Operation: 4 500 Operation supervision and engineering. . . . . . . . . 5 501 Fuel . . . . . ... . 6 502 Steam expenses. . . . . . . . . .. . 7 503 Steam from other sources. , 8 504 Stesm transferred - Cr.. . . . . . . . . . . . . . . 503 Electrie expenses. . . . . . . . . . .. .... . ............ 9 10 506 Miscellaneous steam power expe nses. . . . . . . . . . . . . . . . . . 507 Rents . . . . . . . . . . . . . . . ..... . .. . .. ... .. .... 11 None None 12 Total operation. . . . . . ............... .......... .... 13 Maintenance: 14 510 Maintenance supervision and engineering. . . . . . . . . . . . . . . . . . . 15 511 M aintenance of structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 512 Maintenance of boiler plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 513 Maintenance of electrie plant. . . . . . . . . . . . . . . . . . . . . . . . . . 18 514 Maintenance of miscellaneous steam plant. . . . . . . . . . . . . . . . . None None ( -) 19 20 Total maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total power production expenses - steam power. . . . . . . . . .  %  %

                                                                                                                                                              ~"'

21 N NUCLEAR POWER GENERATION 22 ' Operation: 23 517 Operation supervision and engineering. . . . . . . . . . . . . . . . . . . . . 24 518 Fuel. . . . . . . ..... . ......... .. .......... ... .... 25 519 Coolants and water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

          , 26      520 Steam expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

27 521 Steam from other sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 522 Steam transferred - Cr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 523 Electric expenses . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . . . . 30 524 Miscellaneous nuclear power expenses. . . . . . . . . . . . . . . . . . . . . . 52 5 Rents . . . . . . . . . . . . . ..... ............................ 31 None None 32 Total operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Maintenance: l 34 528 Maintenance supervision and engineering. . . . . . . . . . . . . . . . . . . 35 529 Maintenance of structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 530 Maintenance of reactor plant equipment. . . . . . . . . . . . . . . . . . . 37 531 Maintenance of electric plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 532 Maintenance of miscellaneous nuclear plant. . . .. . . . . . . . . . . None None 39 Total maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . None None 4C Total power production expenses-nuclear power. . . . . . . . . . . 41 HYDRAULIC POWER GENERATION 42 Operation: 43 535 Operation supervision and engineering...

        .      44    536 Water for power. . . . ... ..                   .      . . .

N 45 537 Hydrade sexpenses. . . . . .. . .. . .. ........... 46 538 Electric expenses. . . . . . . .. ... .... ....... ........ 47 539 Miscellaneous hydraulle power generation expenses. . . . . . . . . 48 540 Rents. . . None None 49 Total operation. . . ..

Anau. ree rt o................t..o..w..s...OFIfUDSOU LIGHT AMD P0iliE3 DEPAEIMEU'A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . a n ELECTRIC OPERATION AND MAINTENANCE EXPENSES-Continued

                                                                                                                                                                                                        )

increase or ( ' '"

                                                         ****""'                                                                     ^**""'Y

une P ecede'nse No. (a) (b) , (c) 1 IlYDRAULIC POWER GENERATION-Continued 3 $ 2 Maintenance: . . 3 541 Maintenanes sapervision and esgineering. . . . . . . . . . . . . . . 4 542 Maintenana of structures . . . . . . . . . . . . . . . . . . . . . . . . . . . ' 5 543 Maintenance of reservoirs. dams and waterways. . . . . . . . . . 6 544 Maintenance of electric plant. . . . . . . . . . . . . ..... ... . , 7 545 Maintenance of miscellaneous hydraulle plant. . ... . 8 Total maintenance. . . . . . . . . . . . .... . . . Gone Mone 9 Total powrr production expenset - hydreuite perrr. . pn ., ,, t w., c, 10 OTHER POWER GENERATION i 11 Operation: j 12 546 Operation supervision and engineering. . . . . . . . . . . . . . . . . . . . 11,564.49 433.18 13 547 Fuel . . . . . . . . . ... . .. . ........... . .... . 1,067,855.17 59,460.41 548 Generation expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155,311.27 16,595.73 14 . 549 Miscellaneous other power generation expenses. . . . . . . . . . . . . ' 35,893.SO 1,090.52 15 . 16 550 Rents . . . . . . . . . . . . . . . . .... ....... ..... ..... M ne Mone s 17 Total operation. . . . . . . . . ..... .... ............. .. 1,270.624.73 77.584.89 18 Maintenance: 19 551 Maintenance supervision and engineedng. .. . . . . . ..... 11,575.98 671.47 ' 3 14,824.19 0,363.54 / ) 20 552 Maintenance of structures. . . . . . .............. . . . 133,151.20 8,0G1.99 21 558 Maintenance of generating and electric plant. . . . . . . . . . . . . . . 22 554 Maintenanes of rnimaallaneous other power generation plant. . 3,349.93 G14.99 23 Total maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 162,901.30 17,711.99 24 Total power production expenses - other power. . . . . . . . . . 1,433,526.03 95,296.88 25 OTHER POWER SUPPLY EXPENSES 5,795',654.31 12,410.60 26 555 Purchased power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 556 System control and load dispatching. . . . . . . . . . . . . .. .. IG,936.45 (539.43), 28 557 Other expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118,008.90 77,512.26 29 Total other power supply expenses . . . . . . . . . . . . . . . . . . . . . 5,930,599.66 .89,38.s.43 30 Total power production expenses . . . . . . . . . . . . . . . . . . . . . . 7,364,125.69 164,680.31 31 TRANSMISSION EXPENSES 32 Operation: _ 33 560 Operation supervision and engineering. . . . . . . . . . . . . . .. .. Mone None None Mone 34 561 Load dispatching. . .. .. ... .. . .. 35 562 Station expenses. . . . . . . . . . . . . .. ... ... ... . ..... 273.65 (7.15) 36 563 Overhead line expenses. . . . .... ........ ........ None  ;;one 37 564 Underground line expenses. . . . . . . . . . . .. . ..... Mone Mone 38 -565 Transmission of electricity by others. . . . . .. .... . 194,074.96 1,820.42 39 566 Miscellaneous transmission expenses. . . . . .. .. ... Mone Uone 40 567 Rents. . . . . . . . .. . . . .. .. None None 41 Total operation . . . . . . . .. . .. . ..

                                                                                                                                   * * * * "                                  l'*'#

42 Maintenance: 43 568 Maintenance supervision and engineering. .. .. .. None N ne 44 569 Maintenanw of structures. . . .. . .. .. .. Mone Mone 45 570 Maintenance of station equipment. . . . . . . . . . . . . ....... 166.06 224.00 141.08 (2,617.72) [. . 46 571 Maintenance of overhead lines. . . . . . . . . . . . . . . .. ... 47 572 Maintenanes of underground lines. . . . . . . . . . . . .. . . Mone None 48 573 Maintenanen of miscellaneous transmission plant. . . . . . . UOUC UODO 49 Total maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ~390.06 (2.476.641 50 Total transmission expensee. . . ... . . .. .. 194.738.67 f 663.37)

• ~

                                              .                                                                                                                         41 Aanuei renort e f . ... .. .. ........ .. .I.O.M OF !!UD :'.ON L..I. .G..i.lT....A.N..D....P..O.W..I..R....D.E..P..A..R.T.

r .no.4 o.c.me., n , 3........y

                                                                                                                                                             .ggs. 3, M ELECTRIC OPERATION AND MAINTENANCF, EXPENSES-Cutinied increase or O '*I          **

Account Amount for Year Procedins Year Un* (c) {j L No. (a) (b) DISTRIBUTION EXPENSES $ $ 1 2 Oswration: 3 580 Operation supervision and engineering. ..... . ......... 12,836.94 999.16 4 . 581 Load dispatching. . . .. ... ... .. ........... None None 5 582 Station expenses. . . . . . . . . .... ... . ...... . None None 6 583 Overhead line expenses. . .. ............ 2,608.67 (66.53) 7 584 Underground line expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36.60 36.60 8 585 Street lighting and signal system expenses. . . . . . . . . . . 5,071.63 (258.07) 586 Meter expenses. . . . . . . . . . . ... ... . ...... .. 13,015.04 3,133.16 9 587 Customer installations expenses . . . . . . . . . . . . . . . . . . . . . . . 9,384.33 (2,234.76) 10 11 588 Miscellaneous distribution expenses. . . . . . . . . . . . . . . . .... 3,894.37 413.96

                                                                           ......... ..... ....                     None                     None 12   589 Rents.              ..             ... . .... ..

Total operation. . . . . . . . .. .. .. ....... ........ 46,847.58 2,023.52 13 14 Maintenance: 590 Maintenance supervision and engineering. . . . . . . . . . . . . . .. . 12,758.60 920.82 15 ' None None 16 591 Maintenance of structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 592 Maintenance of station equipment. . . . . . . . . . . . . . . . . . . . . . . . None None 17 118,703.90 16,645.07 18 593 Maintenance of overhead lines. . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,803.25 2,767.15 19 594 Maintenance of undergro unti lines . . . . . . . . . . . . . . . . . . . . . . . . 3,358.86 3,192.54 20 595 Maintenance of line transformers. . . . . . . . . . . . . . . . . . . . . . . 596 Maintenance of street lighting and signal systems. . . . . . . . . . . 6,267.06 ( 731.99) 21 614.80 (2,424.80)

22. 597 M aintenance of meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

None None 23 598 Maintenanca of miscellaneous distribution plant. . . . . . . . . . . . . To tal mainten ance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145,506.47 20,368.79 24 25 Total distribution expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192,354.05 _ 22,392.31 26 CUSTOMER ACCOUNTS EXPENSES 27 Operation: 901 Su pervision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,642.57 59.02 28 902 Meter reading expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27,713.21 4,869.52 29 903 Customer records and collection expenses . . . . . . . . . . . . . . . . . . . 86,405.13 16,870.69 30 11,532.04 (24,875.02) 31 904 Uncollectible accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 905 Miscellaneous customer accounts expenses. . . . . . . . . . . . . . . . . None None 32 Total customer accounts expenses . . . . . . . . . . . . . . . . . . . . . . . 131,292.95 ( 3,075.79) 33 34 SALES EXPENSES 35 Operation: None None 36 911 Supervision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . None None 37 912 Demonstrating and salling expenses . . . . . . . . . . . . . . . . . . . . . . 913 Advertising expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45.00 (20.00) 33 22,466.19 (10,397.21) 39 916 Miscellaneous sales expanaa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,511.19 (10,417.21) 40 Total sales expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 ADMINISTRATIVE AND GENERAL EXPENSES 42 Operation: 115,572.78 16,628.88 43 920 Administrative and general salaries. . . . . . . . . . . . . . . . . . . . . 9,515.17 1,149.73 44 921 Omce supplies and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . None None 45 S22 Administrative expensee transferred - Cr.. . . . . . . . . . . . . . . . 12,167.72 2,159.89 46 923 Outside services employed. . . . . .. .......... ....... 18,836.20 6,665.43 47 924 Property insurance . . . . . . . . . . . .. . ............. ...... 42,511.01 2,848.00 48 925 Injuries and damages. . . . . . . .. .. . ... .... 386,813.78 (6,277.40) 49 926 Employee pen'sions and bene 6ts. . . .. ........ . ... 9,329.89 395.14 50 928 Regulatory commission expenses . . . . . . . . . . . . . . . . . . . . . . . 4,285.31 31,438.44 51 933 . 'I;g NWpRQation , Exp.e,rige. . , , , .,,,,,,,, ,,,,,, 17,859.69 7,638.71 52 930 Miscellaneoun general expenses. . . . . . . .. . . .. .. . None None 53 931 Rents. . . ............. . ...... .............. ' 54 Total operation. . . . . . . 644,044.68 35.493.69

ALnuel report of............... 20.m...l..C..F

                                      .                      11 D0011
                                               .....................           LICl!I
                                                                        ..........         ' Af D PGiiER
                                                                                     .... ................... LIPARTk'ENT
                                                                                                              .......  ....Ystr Ended Dectmbir 31.19.h ELECTRIC OPERATION AND MAINTENANCE EXPENSES -Continued increase or

( * '} Account Amount for Year p,,d g No. (e) (b) (c) 1 ADMINISTRATIVE AND GENERAL EXPENSES-Cont. $ 3 2 Maintenance: 3 932 Maintenance of general plant. . . . . . . ..... .. . 33,544.39 5,600.73 4 Total administrative and general expenses. . . . . . . . . . . . 677,589.57 41,122.*42 5 Total Electric Operation and Maintenance Expenacs. . . . S,582,612.12 234,03C.67

SUMMARY

OF ELECTRIC OPERATION AND MAINTENANCE EXPENSES Line Functional Closelfication Operation Maintenence Total No. (a) (b) (c) (d) 6 Power Production Expenses 3 $ $ 7 Electric Generation: 8 Steam power. . . . . . . . . . . . . . . 9 liuclear power. . . . . .... .. .. 10 Hydraulle power. . . . . . . . . . . . . . 11 Other power. . . . . ..,..... 1,270,624.73 162,901.30 1,433,326.03 12 Oti:ct power supply expenses. . . . . . . . ~"*" 00 3 930 5% EO 13 Total power prod"ction expenses.. 7,201,224.39 162,901.30 7,304,125.G9 ) 14 Transmission E:penses. . . . . . . . . . . . . . 134,348.51 390.06 1^4,730.57 15 Distribution Expansee. . . . . ......... 46,847.58 145,50G.47 192,334.05 16 Customer Accounts Expenses. . .. ... 131,292.95 .00 131,232.95 17 Sales Expenses . . . . . . . . . . . . . . . . . . . 22,511.19 .00 22,511.19 18 Administrative and General Expenses... 6u .044.60 33,544.89 677,5S9.57 19 Total Electrie Operation and 8,240,269.40 342,342.72 8,532,612.12 20 Maintenance Expenses. . . . . I l I' 21 Ratio of ope %s % enst to operating revenues (carry out dedmal two places, e.g.: 0.00%) 43 On% Com % em i Reveues (Aces 400) late the sum of Operation and Main *== - Expenses (Pase 42 j lb .t a > ,Jos= t moa (Aces. 408) and Amortsentloa (Acet. 4o7).............. I 22 Total a3's.r te A.3 gn of electrie department for year, including amounts charged to oper-ating e,[t>enses, an.a r uction and other accounts. . .. . . ... .. . .. .. . . ...  ! 737.991.70 23 Total number of employees of electric department at end of year including adminIntrative, , l operating, maintenance, construction and other employeu (including part time employees) l

                                                                                                                                                        }  .

I i

b h.4 7 b I TAXES CIIARGED DURING YEAR (

3. The aggregate of each kind of tax should be listed number of the appropriate balanco sheet plant account 3

l. This schedule is intended to give the account dis-tribution of total taxes charged to operations and other under the appropriate heading of " Federal," " State," and or subaceount.

final accounts during the year. " Local" in such manner that the total tax for each State 5. For any tax which it was necessary to apportion {

2. Do not include gasoline and other sales taxes which and for ali subdivisions can readily be ascertained. to more than one utility department or account, state .-

htve been charged to accounts to which the material in a footnote the basis of apportioning such tax.  : ca which the tax was levies was charged. If the actual 4. The accounts to which the taxes charged were dis. 6. Do not include in this schedule entries with respect i they tributed should be shown in columns (c) to (h). Show to deferred income taxes, or taxes collected through pay-or estimated should amounts be shown of suchand as a footnote taxes are knownliether designated w both the utility department and number of account roll deductions or otherwise pending transmittal of such  : estimated or actual amounts. charged. For taxes charged to utility plant show the taxes to the taxing authority. i Distribution of Taxes Charged (omit cents) ie

                                                      *'      "                                      (Show utility department where applicable and account charged)                                   .

C During Year Electric Gas  : Z Line Kind of Tax (omit cents) (Acct. 408. 409) (Acct. 408. 409) *o No. (a) (b) (c) (d) (e) (f) (g) (h) (i) (1)  : *=3 i =

                                                                                                                                                                                                      - C o

1 Real Estate Tax 4808.11 4808.11 i. LO 2  : o 3 i *

t--

4  : s 5 iE 6 !h

u 7

8 9

.m o

a 10

e 11 s i*

                                                                                                                                                                                                      ': e 12

x 13

Y

in a 14  : s 15 16 i se 17 l 3

18

                                                                                                                                                                                                        'y 19

• 20 E

21 22 O 23 . 24 g 25

                                                                                                                                                                                                         .N 26 27                                                                                                                                                                                                    %

28 m ALs 4608.11 4608.11  % Me

n An.,vo roort et................COWN . . .. . ....I....... OF flUDSO

                                  . ..............                 LIGilT. .A.::D.POWER      D EPART.MEU.
                                                                                   ..... .. ..... ... .... .... 2.. . .. ... ..v.or enoso oecsmos, ai.1982      <

1 l OTHER UTILITY OPERATING INCOME (Acesunt 414) l Reprt below the particulars called for in each column. Amount Gain or p,, p ,,, Amount of Amount of of Operating (Loss) f rom L!ne Investment Revenue Expenses Operation No. (a) (b) (c) (d) (e) 1 2 3 4 5 6 7 8 9 10 11 12 13 1;OIM 14 - 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 . 31 32 03 34 35 36 37 38 39 40 41 42 43 44 45 46 47 1 48 49 50 3g TOTALS

                          . _            _ - =                                                    .

51 T0r) OT I!UDS01: LIGt1T AND P0 Hit DEPAhTME'A . . . . .. veer anord Decimber 31,19. . Annusa report et...... .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . INCOME FROM MERCllANDISING, JOBBING. AND CONTRACT WORK (Account 4I5) Report by utility departments the revenues, costs, expenses, and net income from merchandising. jobbing, and contract

  ,        work during year.

Other Doctric Gas  ; Utihty Department Department l Department Total Line item (a) (b) (c) l (d) (e) No. _ _ _. I Revenues: w 1 2 Merchandise sales, less discounts. 3 allowances and returns. 958.7.9 93,.79 4 Contract work. 5 Commissions. 6 Other (list according to major classes). 7 8 9 10 Total Revenues. 958.79  ::ene icne 95T,.79 11 12 13 Costs and Expenses: 14 Cost of sales (list according to major 15 classes of cost). 16 17 18 19 20 21 22 23 _ 24 25 , 26 Sales expenses. . .. 27 Customer accounts expenses. . . 28 Administrative and general expenses. 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47

 )           48                                                              '

49 , 50 TOTAL COSTS AND EXPENSES hgy w  % Net Proot (or Loss) 930.19 i.one i:one 956.79 51 w ~ e-a y

e

                      /

5*- , 20ml 0F HUDSON LIGHT A n n ua l r e s yrt ( f. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AND P. 0..m.......D..I..P..A.R.T.E....U..)...... Year endad Dxcsmb SALES FOR RESALE (Account 447)

1. Report sales during year to other electric utilities and and place an "x"in column (c)if sale involves export across to cities or other public authorities for distribution to a state line.

ultimate consumers. 3. Report separately firm, dump, and other power sold to

2. Provide subheadings and classify sales as to (1) Associ. the same utility. Describe the nature of any sales classified ated Utilities,(2) Nonassociated Utilities,(3) Municipalities, as Other Power, column (b).

(4) R.E.A. Cooperatives, and (5) Other Public Authorities. 4. Il delivery is made at a substation indicate ownership For each sale designate statistical classification in column (b), in column (e), thus: respondent owned or leased. RS: thus: firm power FP; dump or surplus power. DP: other, G, customer owned or leased, CS. e a Kw or Kva of Demand 1$ 3e

                                                                                              $I oc E

(Specify Which)

7. 3 42 t

t I_ _. - _ - . - _ , - ------

Annu:f rwort ef., .... ... .. IOWN OF UUDSCU LIGHT AND POT.IR. ..D..E.P..AR..N.I.. ...Ytar endid Oscambsr 31,19.8. PURCIIASED POWER (Account 555) (except interchange power)

1. Report power purchased for resale during the year. Authorities. For each purchase designate statistical classi-Exclude from this schedule and report on page 56 particulars fication in column (b). thus: firm power FP; dump or concerning interchange power transactions during the year. surplus power, DP: other,0, and place an "x" in column (c)

2. Provide subheadings and classify purchases as to if purchase involves import across a state line.

(1) Associated Utilities, (2) Nonassociated Utilities, (3) 3. Report separately firm, dump, and other power pur. Associated Nonutilities. (4) Other Nonutilities, (5) Muni- chased from the same company. Describe the nature of any cipalities, (6) R.E.A. Cooperatives, and (7) Other Public purchases classified as Other Power, column (b). g E e Kw or Kva of Demand

                                                       ,3j                 $,[                                                            y                (Specify Which)

N Average Purchased From 3$ o1 Point of Receipt $ Monthly Annual Lins $ -$5 Contract Maximum Maxemum No. Demand Demand Demand (a) (b) (c) (d) (e) (f) (g) (h) 1 2 NEPCO Pilgrim O O lX  !!arlboro-Hudson Line 16,000 2,500 UA NA NA NA 3 Vermont Yankee O X " 587 NA NA 4 Maine Yankee O X " 1,234 NA NA 5 Uyman-Yarmouth O X " 2,090 NA NA 6 NEPCO-Brayton Point O " 2,000 NA NA 7 f0IWEC- B.P./S.H. O 4,000 NA NA 8 9 10 11 N 12 13 14 15 POWER USED AT PONER PLA:4T AND 16 17 18 19 20 11 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 , 37 38 39 40 41 42 y yy + e.- ------+,e-m-.-.-wa+

                                                         .                                                           + - - - .        .-     -                 -mg-     py- -   -m7--     a ,e-.         -twa+   mi7 .-

55

                                       ~

TOWN OF !!UDSON .... LlGl:T .A.ND PCHR..D..Z.P. ART,EI.S.I... . ... Year endid Decernbar 31.1900 mu Annuit riport af..... . . . . ........ . .. . . .. ... .. . . PUltCilASED POWER (Account 555)-Continued (except interchange power)

4. If receipt of power is at a substation indicate' ownership should be furnished whether or not usad in the determination in column (e), thus: respondent owned or leased, RS; seller of demand charges. Show in column (i) type of demand owned or leased, SS. reading (instantaneous,15. 30, or 60 minu;es mtegrated).

5. If a fixed number of kilowatts of maximum deman,d 6. The number of kilowatt hours purchased should be the is specified in the power egntract as a b number should be shown in column (f,, number asis of billing, quantities shown by the power bills, this s . The of kilowatts of maximum demand to be shown in columns (g) 7. Explain any amount entered in column (n) such as fuel W' or other adjustments.

and (h) should be actual based on monthly readings and Cost of Energy (omit Cents) Cost Type of Voltage Kilowett. Demand at V,nich hours g$g Energy Other (Cents) Reading DeHvated Charges Charges Charges Total (0.0000) Line g) (k) (1) (w) (n) to) (p) No. NA 115 KV 91,680,780 965,008 2,367,537 90,502 3,423,047 3.7336 115 KV 12,265,256 491,977 59,459 551,436 4.4959 , NA ~ 115 KV 4,641,771 82,755 35,278 118,033 1.5428 NA 8 115 KV 6,707,148 111,189 49,665 2,716 163,570 .!.4387 NA N'A

                                 ~

115 K'I 3,843,599 99,436 207,385 306,821 7.9826 f i 115 KV 1,911,081 14,668 80,899 95,557 3.0000 6 NA 115 KV 978,795 5,123 40,146 45,269 4.6250 NA 7 8 9 10 11 12 (' - (17,564) 13 14 15 CilARGED TO 549 (480,992) 16 17 18

                                   . ~
                                                -                                                                                                               19 20 21 I                                                                                                                                                                22 23 24 25 I                                                                                                                                                                26 l
                -                                                                                                                                               27 l

28 29 30 31 32 33 34 35 36 37 38

      )                                                                                                                                                         39 N
                                                                                                      \                                                         40 41 3.8554 121.547.438 1,770,156 2,840,350 93,218 4,686,169                     42 Totals

pE INTERCIIANGE POWER (Included in Accrunt 555) s e

1. Report below the kilowatt-hours received and shall be furnished in Part B, Details of Settlement for coordination, or other such arrangement, submit a i delivered during the year and the net charge or credit Interchange Power. If settlement for any transaction copy of the annual summary of transactions and bill- g under interchange power agreements. also includes credit or debit amounts other than for Ings among the parties to the agreement. U the o

2. Provide subheadings and classify interchanges increment generation expenses, show such other amount of settlement reported in this schedule for any as to (1) Associated Utilities, (2) Nonassociated Utili- component amounta separately, in addition to debit transaction does not represent all of the charges and

                                                                                                                                                                                                        }:-

ties (3) Associated Nonutilities, (4) Other Non- or credit for increment generation expenses, and give credits covered by the agreement, furnish in a footnote i utih, ties, (5) Municipalities, (6) R.E.A. Cooperatives, a brief explanation of the factors and principles under a description of the other debits and credits and state  :* and (7) Other Public Authorities. For each inter- which such other component amounts were deter- the amounts and accounts in which such other change across a state line place an "x" in column (b). mined. If such settlement represents the net of debits amounts are included for the year. i

3. Particulars of settlements for interchange power and credits under an interconnection, power pooling, 3 A. Summary of Interchange According to Companies and Points of Interchange i

*s ee , :O h ,, gj h Kilowatt. hours f g.g sgj :o Name of Company 5 Point of Interchanse 1 Amount of f9 Line Ek 5 Received Delive,ed Het Difference ih' No. (a) (b) (c) (d) (e) (f) (s) (h)

                                                                                                                                                                                                         *{
                                                                                                                                                                                                        .O 1              !!EPEX Used as Station Power X      ;4arlboro-11udson Line                       ll5IN           20,278,700  (,400,250              l'),786,450         1,115,734.57   !h 2                                                    and Ch    Trged  to (549)                                                 (109,030)                           (109,080)             (6,248.93 P[g 3                                                                                                                                                                                                   : t:

4 5 5  !$ 6  ! , 7 , :m o j 8 !M 9 i*

e 10 :m

m 11  : >.

12 TOTALS 25,169,620 6,450,330 19,679,370 1,109,405.64 !N

g B. Details of Settlement for Interchange Power .

i:*L"a i i ' Line Name of Company Esplanation Amount (j) l No. (i) - (k) -

 ~

) 13 NEPEX Energy Received by II.L. & P. - Econeny . 1,343,121.71 j 14 - .3cheduled Outage 106,417.85 a 15 - Unscheduled Outage 5.,299_.76 h 16 - Deficiency 34.13 2 17 Energy Delivered by E.L. & Ps (103,995.24) g 18 NEPEX Savings , (172,236.39) t i 19 ilHPEX Expenses 10,112.70 .M i 20 G 21 TOTAt- 1,113,734.57 19

                             --                                                                                      %.c

57 EPARTMEN! o,y - Annud report of.................T..O..W..N...OF HUDSON LIGHT AND POWER D. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ELECTRIC ENERGY ACCOUNT Report below & informataea called for eonesraias the disposition of electrie emersy peersted, purebased, and ietsrehanged durms the year. Kilowatt hours [ Line item (b) No. (a) 1 SOURCES OF ENERGY 2 Generation (excluding station use): 3 Steam . . .

   ' ~

4 Nuclear. . . 5 Hydro. . . . 21,002,632 6 Other. . . . Total generath,n. .. 21,8G2,632 7 ... . .. . .

                                                                                                                                               ...                  . ..          121,547,433 8      Purchases. . .         . .        .          ..             ....,.             ....

9 In (gro.as). .. .. 26,169,620 10 . Interchanges. . . . , a . . . .< Out (gross). . . . ._ 6.490.250 Net (kwh). . .. ... 19,673,370 11 ******* 12 Remived. . .. 13 Transmission for/by others (wheeling). . Delivered. . 14 , Net (kwh). .. . .. .. ..

                                                                                                                                                                          ..      163,109,440 15       TOTAL. ...                ...         . . .. ...                       . . . ..              . ..            .               ...        .

16 DISPOSITION OF ENERGY Sales to ultimate consurnars (including interdepartmental sales). . . . .. ... .. 147,309,430 17 18 Sales for resale. . . . . . . .. .. . . . . ... ... 23,200 19 Energy furmahed without charge . ..... .... ... . . ... ..... ...... . none 20 Energy used by the company (excluding cation use): 260,256 21 Electrie department only. . . . ...... .. . . .. . .. . . . . ....... . 22 Energy losass: 23 Tranarm-ion and conversion losses. . . . ...... ..... . .. 4,823,080 6,193,824 (fL 24 25 Distribution t . . . . . . . . . . . . . . . . . . . . . Unaccounted for losses. . . . . . . . . . . . . . ................. f .w a-15,51G,50', 26 Total energy losses. . . . s. . . .. . ................. ...... ........... 27 Energy losass as perant of total on line 15. ...'At fd.2, . . .. . . % total t r 3 .1_ n o . 4 3 28 MONTHLY PEAKS AND OLTTPUT

1. Report bereunder the inforension entled for to aimal. 3. State type of monthly pemir reading Gaetastaneone 15, 30. e, ft1 meathly output Os mimetas integreesd.)

taasous penha esa awW suomehly Om kilowmees) kalowass.boere) for the somenmed soareas of eiseene emeesy of respe=4ema. 4. Monthly outpet should be the rusa of respondwet's not semeratun

2. Month 1r rank eel (b) should be Nependent's massimon kW band as and r ' plus er means met laterehange and plus or sumus met trans.

nummon er mLselims. Total for the year abould agree with line la above. messe,ed by the case of its soonedenent mes senermanos and purehesse p4= teens not phreienu or ensaus met intershames. minus dativanas aos Amtsrahamse) 5. If the respondsat has two or more power of emersonry power to emother eyeem. enably, laeludies ed esa,m,e,sted the information udnad for below shou emergener deliveries should be shown la a foemote with a br6sf espianstaos ,y, , as to the natu,e of the esnarsamey System Monthly Peak Monthly Output Day of (kwh) Kilowetts Day of week Month Hour Type of Reading (See instr. 4) Line Month (g) (b) (c) (d) (e) (O No. (a) January. . . 29,300 rue s/?.on. 12/18 ):00/11:00an 60 min 15,886,318 29 26,800 Thursday 11 9:00 ac 50 nin 13,486,157 3G February. March. . 27,200 Thursday 4 8:00 am 50 min 34,497,072 31 .. 26,300  :'onday 5 11:00an 60 min 12,854,325 g 32 April. . ... Thursday 27 3:00 pn 60 nin 12,186,487 W 33 May. 23,400 ruesday 29 1:00 pn 60 min 12,465,524 34 June. 24,400 30,000  :- onday 19 2:00 pn 60 nin 13,601,669 ! 35 July. August. , 25,500 Zuesday 10 2:00 pm 60 min 13,347,358 l 36 24,400 ;Iednesday 15 2:00 pn 60 nin 12,705,566 37 September. 26,100 :onday 25 10:00am 60 nin 13,127,711 38 October. November. 26,500  ?:onday 29 9:00 an 60 min 13,598,227 39 29,600 ruesday 14 , 9:00 a.1 60 min 15,352,026 40 December. TOTAL l 163,109,440 41

58 E0WN OF liUDSON LIGJJT AUD POWE 83 A n nus I r: port (f. . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . .. .R. . . .DI. .P. .A. .h. .T. M. .E. . GENERATING < STATION STATISTICS (Large Stations) (Except Nuclear, See Instruction 10)

1. taree stations for the purpose of this sebedule are steam and hydro 4. If reak demand for 60 rainutes is not available, give that which is statione of 2.300 Kw* or more of installed capacity and other stations of avaalable. specalysas period.

30o Ew* or more of installed espacity (name plate ratanas). (*10.00o Kw 5. If a aroup of employees attende more than one generating station, and 2.500 Kw. roepecuvely. if annual electrae operatans revenues of re. ,, port on tane 11 the approximate averase number of employees assi4*iatie pondent are $25A0o.0oo or more.) to each station.

2. If may plaat is leased, operated under a license from the Federal 6. If sne is used and purehneed on a therm benis, the B.t.u. content of Powe Com n . or aoperated as a soint facdity andiente euch facts by the saa should be given and the quantity of fuel consumed converted to bt eu,it.

the use of assertake and footnotes.

3. Speedy if total plant capacaty is reported in kva instand of kilowatte 7. Quantitise of fuel consumed and the averase cost per ur.it of fuel consumed abould be conassent with charges to expense accounta 3o1 and se called for on line 5.

Plant Plant Plant Lini item (d)

   "**                                           (*)                                             Cherry %..Sta. I.L&P. fdaking 1    Kind of plant (steam, hydro, int. comb., gas turbine)                                  Int. Comb.                          Int. Comb.

2 Type of plant construction (co.nventionalt outdoor boiler, full outdoor, etc.). . . . .. Conventional Conventional 3 Year originally constructed. .. ... . 1897 1962 4 ' Year last unit was installed. . . . . . . . . .. 1972 1962 5 Total installed capacity (manmum generator name plate ratings in kw). . . . . . . . . . . . . . . . . . . 17150* 4,400 6 Net peak demand on plant-kilowatts (60 min.). .. 14,000 4,200 7 Plant hours connected to load. . .. . . . . . . 2,569 1,594 8 Net continuous plant capability, kilowatts: 15'200 4'400-9 (a) When not limited by condenser water.. .. . 10 (b) When limited by condenser water. . . .. . 15,200 4,400 11 Average number of employees. . .. ....... ... 12 12 Net generation, exclusive of station use. . . . . . . . 17,636,150 4,246,482 13 Cost of plant (omit cents): ,I 14 Land and land rights.. . .. ... .. . .... 5,500 None ) 15 Structures and improvements..... . . . . . . . 332,640 None 16 Reservoirs, dams, and waterways. . . ....... None None 17 Equipment costs. . . . . . . . . . . . . . . . . . . . . . . . . 3,016,955 712,054 18 Roads, railroads, and bridges. . . . . . . . . . . . . . . . . None None 19 Total cos:. . . . . . . . . .... . ... . .... 3.355,095" 712,054 20 Cost per kw of installed capacity. . . . . . . . . . . . S207 S162 Production expenses: Total Combined Plan 21 11,564.49 22 Operation supervision and engineering.. .. 124,605.47 23 Station ! abor. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,067,855.17 24 Fuel. . . . . . . ....... ........ .... ..... ... 66,599.60 25 Supplies and expenses, including water. ... . 162;901.30 26 Maintenance. . . . . . . . ... .. . ... None I 27 Rents. . . .. .. ... . ... . ... None I 28 Steam from other sources. . . . . . . . . x. . . . . . . 29 Steam transferrad-Credit . . . . . . . . . . ....... None 30 Total production expenses . . . . . . . . . . ...... 1.433.526.03 31 Expenses par net Kwh (5 places). . . . . . ... , o p;q c;n o7 l 32 Fuel: Kind #2 Diesel Natural Gas 33 Unit: (Coal-tons of 2,000 lb.) (Oil-barrels of 42 gnis.) (Gas.M cu. ft.) (Nuclear, indicate). . . . . 42 Ga1. M Cu. Ft. 6641 195,865 3 34 Quantity (units) of fuel consumed. . . . . . . . ,y 35 Average heat content of fuel (B.t.u. per Ib. of coal, 140,000 BTU 910 BTU i per gal. of oil, or per cu. ft. of gas). . . . . . . . . . 36 Average cost of fuel per unit. del. f.o.b. plant. $39.8989 BBL $4.43168 MCF 37 Average cost of fuel per unit consumed. .... . $30.0924 BBL S4.43168 MCF SS.11782 S4.86998 j l 38 Average cost of fuel consumed per million B.t.u.. 39 Average cost of fuel consumed per kwh net gen.. .048799 40 Average B.t.u. per kwh net generation. . . . 9930 41 42

• Limited to 16,200 by Diesel

                                                                                                                                                                                       .19 Annual r$ port of..            ....... 20'.iTN
                                                    ... . .OF !!UDCOM
                                                               ..                10iiT A."..D PO.V E. R. DRAh.fMEN..T.. .
                                                                                   .             .                                         .Vetr endad Dscombar 31,19.8.. 2 GENEIIATING STATION STATISTICS (I.arge Stations)-Continued (Except Nuclear, see Instruction 10) 347 as shoni on line 24.                                                         operation with a conventional steam unit. the gas turbine shout,i be included f             8. The items under cost of plant and proauction expense, represents            "'kLh* g g*$",M" nt operates a nuclear power generating =tation accounts or combinataons of accounts prescrabed by the Unaform System             submit: (a) a brief en lanatory statement concerning accountang for the of Accounta.                                     to not include Purchased         enst of power senerate[ including any attribution of escene enets to rencarch Produeuon esposes, however.paty ng. and Other Espenses            and development expenses; th) a brief explanation of the fuel accounting claEf[ed as th               r$pp                                                 specifying the aceovating methods and ty e of cost un.as used with

9. If any plant is equipped with combinations of eteam, hydro, internal respect to the various components of the fue cost, and Ic) such additaonal combusbon engine or gas turbine equapment, each should 1,e reported as a inforniataan as may be informatare concerning the type of plant. kind of separate plant. Houever, if a gas turbane unat functaons in a combaned fuel used, and other physacal and operatang characterasucs of the plant.

Plant Plant Plant Plant Plant Pla nt Line

   'L                  (e)                        (f)                          (g)                   (h)                              (i)                    (3)                  No.

1 2 3 4 5 6 7 8 9 10 11 1 12 13 14 15 16 ( 17 18 19 20 K 21 22 a 23 24 25 26 27 28 s 29 s 30 31 32 33 34 35 36 37 38 39 40 41 42

^ N MGilT A n nuit r: port (f. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. .. .. .. .. .. ... .. .. .. .. .. .. .. ..A N D P O WER D E P. A.R. .T. .M. E. .N.T. . . . . . . . . Yst r E ndId STEAM GENERATING STATIONS

1. Report the information called for concerning gener- lessor, date and term of lease, and annual rent. For any ating stations and equipment at end of year. / generating station, other than a leased station or portion

2. Exclude from this schedule, plant, the book cost of thereof for which the respondent is not the sole owner but s which is included in Account 121, Nonutility Property. which the respondent operatea or shares in the operation of, '

3. Designate any generating station or portion thereof furnish a succinct statement explaining the arrangement and for which the respondent is not the sole owner. If such giving particulars as to such matters as percent ownership property is leased from another company, give name of by respondent, name of co.9wner, basis of sharing output.

Boilers Rated Max. Name of Station Location of Station Number Kind of Fuel Rated Rated Continuous and Year and Method Pressure Steam M lbs. Steam Installed of Firing in Ibs. Temperature

• per Hour No. (a) (b) (c) (d) (e) (f) (g) 1 - - - - - - -

2 3 4 5 6 7 8 9 10 11 12 13 14 15 *J gg t2E &?TLICa5L3. 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 s 37 Note reference: J

           ' Indicate reheat boilers thusly, 1050/1000.

61 on ICWN OF.........

                                                             !!UDSON    .. LI.G..i!T                                              .Yeer sndid Decembu 31.19 A.2(.
                                                                                       .ED. P.C. W..ER. D. E.P..A..R.T..M..D..i.'r-A.
          / Annuil riport of..     . . ...    ..  . . ..                                             -    -                  .

[ STEAM GENERATING STATIONS-Continued

5. Designate any plant or equipment owned, not oper-expenses or revenues, and how expenses and/or revenues are accounted for and accounts affectad. Specify if lessor, ated, and not leased to another company. If such plant or co owner, or other party is an associated company. equipment was not operated within the past year explain

4. Designate any generating station or portion thereof whether it has been retired in the books of account or what leased to another company and give name of lessee, date and disposition of the plant or equipment and its book cost are term of lease and annual rent and how determined. Specify contemplate <i.

whether lessee is an associated company. Turbine-Ge nev ators* Name Plate Rating in Kilowatts Station Steam Hydrogen p , Pressureg Capacity At At Maximum Y'*' Minimum Maximum Power Voltage Throttle Factor K.v.9 9 Name Pfate Installed Typet R. P. M . Hydrogen Hydrogen Ratinggt P*** 'E' Pressure Pressure M in. Max. Line (j) (m) (n) (o) (p) (4) (r) No. (h) (i) (k) (1) 1 2 3 4 5 6 7 8 9 10 11

                                                                         ,  1 IJFLl%SL8.                                                                      12 13 14 15 k                                                                                                                                                          16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 TOTALS                                                                                        37 Note references:
                       ' Report cross-compound turbinnenerator units omtwo lines - II.P. section and L.P. section.

tindicate tandem-compound (T.C.); cross-compound (C.C.); all single casing (S.C.); topping unit (T), and noncondensing (N.C.). Show back pressures. tDesignate air cooled generators. ttIf other than 3 phase,60 cycle, indicate other characteristic. t!Should agree with column (m).

62 Annuti nport Af.... TOWN OF HUDSON LIGHT AND POWER DIPARTMIN.T.. ... ... ...Ystr 6ndad DIctmbir 31, t9.8 HYDROELECTRIC GENERATING STATIONS

1. Report the information called for concerning gen. property is leased from another company, give name of erating stations and equipment at end of year. Show lessor, drte and term of lease, and annual rent. For any associated prime movers and generators on the same line. generating station, other than a leased station, or portion

2. Exclude from this schedule, plant, the book cost of thereof, for which the respondent is not the sole owner which is included in Account 121, Nonutility Property, but which the respondent operates or shares in the oper-

3. Designate any generating station or portion thereof ation of, furnish a succinct statement explaining the ar-for which the respondent is not the sole owner. If such rangement and giving particulars as to such matters as Water Wheels Gross Static Name of Station Location Name of Stream Attended or Type of Year Head with Lina Unattended Unit

• Installed Pond Full Ns. (a) (b) (c) (d) (e) (Q (g) 1 2

3 4 5 6 7 8 9 10 11 12 13 14 , 15 16 f;0T APPLICABLE. 17 18 19 20 21 og -

 "a 24 25 26 27 28 29 30 31 32 33 34 35 36                                                                                                                                                                                                  ,,

37 33 39

                                                                                                                                                                                               )
       'llorizontal or vertical. Also indicate type of runner - Francis (F), fixed propeller (FP), automatically adjustable propeller (AP), Impulse (I).

Annurl rrport of....

                               . ..... .DOMI.C7 41UDSON.1,IgiM. AND..pGg3;g.3gpkg7v;zhq. . .                  .Yeer endid Decembar 31.198 IlYDROELECTRIC GENERATING STATIONS-Continutd                                                  [

percent of ownership by respondent, name of exwner, Specify whether lessee is an associated company. basis of sharing output, expenses, or revenues, and how 5. l)esignate any plant or equipment owned, not oper-expenses and/or revenues are accounted for and accounts ated and not leased to another company. If such plant adected. Specify if lessor, co-owner, or other party is an or equipment was not operated within the past year explain associated company. whether it has been retired in the books of account or what

4. Designate any generating station or portion thereof disposition of the plant or equipment and its book cost are leased to another company and give name of lessee, date contemplated.

and term of lease and annual rent and how determined. [ ' Water Wheels - Continued Generators Total Installed Maximurn hp. Name Plate fiumber Generating l Capacity of ' Fre. Rating of of Capacity in Kil-Unit at Year quency U mt in Units in owatts (name Design Head R.P.M. Design Head Installed Voltage Phase or d.c. Kilowatts Station plate ratings) Line (h) (1) (j) (k) (1) (m) (n) (o) (p) (q) No. I 2 3 4 5 6 7 8 9 10 11 12 13

     ,                                                        LC f APPLICOLi                                                                I4 15 16 17 18 19 20 21 22 23
                                                                                                                                           '!4
  ~

25 26 27 28 29 30 l

31 32 33 34 35

(* 36 (. 37 38 TOTALS  ! 39 l l l

nnull riport of... . . . . 10,m . 0 F. . W DECH . M t G'ir .m. . Ecr.I.R. .nT,PAReg . . . ..vs , end d oscambsr an. i9 COMilUSTION ENGINE AND OTHER GENERATING STATIONS (except nuclear stations)

1. Report the information called for concerning gen- property is leased from another company, give name of crating stations and equipment at end of year. Show asso- lessor, date and term of lease, and annual rent. For any ciated prime movers and generators on the same line. generating station, other than a leased station, or portion

2. Exclude from this schedule, plant, the book cost of thereof, for which the respondent is not the sole owner but which is included in Account 121, Nonutility Property, which the respondent operates or shares in the operation

3. Designate any generating station or portion thereof of, furnish a succinct statement explaining the arrangement for which the respondent is not the sole owner. If such and giving particulars as to such matters as percent owner-Prime Movers Diesel or Belted Name of Station Location of Station Other Type Year 2 or 4 or Derect Lins Engine Name of Maker installed Cycle Connected No. (a) (b) (c) (d) (e) (f) (g) 1 Cherry St. Cherry St. Ilud son Diesel American Inco. 1937 2 Direct 2 Cherry St. Cherry St. Hud son Diesel Nordberg-Mfg .Co ,1951 2 Direct 3 Cherry St. Cherry St. Hudson Diesel No rd berg-Mfg .Co ,1955 2 Direct 4 Cherry St. Cherry St. Iludson Diesel Nord be rg-Mfg .co ,1960 2 Direct 5 2herry St. Cherry St. Iludson Diesel Cooper-Bessemer 1972 4 Direct 6

7 8 9 !!udson Light 10 Peaking Plt. Cherry St. Iludson Diesel Fairbanks-Morse 1962 2 Direct 11 :Iudson Light 12 Peaking Plt. Cherry St. Iludson Diesel Fairbanks-Morse 1962 2 Direct 13 14 15 1

 ,16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37                                                                                                                                         ,

38 39 i

65 o~ Annual r: port ef................l.'.O..'3:1 0F ilUD00:e

                                              ..........           LIJ ....
                                                         ............. M J.::D    PG.En......
                                                                            . . ......... LIPARTi!I.N.
                                                                                                  . . . . .. 2.... ...... Year Ended Dicimbir 31,190 4 COMBUSTION ENGINE AND OTIIER GENERATING STATIONS-Continued (except nuclear stations) ship by respondent, name of co-owner, basis of sharing                         Specify whether lessee is an associated company.

output, expenser., or revenues, and how experms and/or 5. Designate any plant or equipment owned, not oper-revenues are acccunted for and accounts affected. Specify if ated and not leased to another company. If such plant lessor, exwner, or other party is an associated company. or equipment was not operated within the past year, explain

4. Designate any generating station or portion thereof whether it has been retired in the books of account or what leased to another company and give name of lessee, date disposition of the plant or equipment and its book cost are and term of lease and annual rent and how determined. contemplated.

Prime Movers - Continued Generators iotal Installed Name Plate Number Generating Capacity Total Rated hp. of Station Year Frequency Rating of Unit of Units in Kilowatts Rated hp. Prime Movers Installed Voltage Phase or d.c. In Kilowatts in Station (name plate ratings) Line of Unit (p) No. (j) (k) (1) (m) (n) (c) (h) (1) 1480 1480 1937 2300 3d 60 cyl 1000 1 1000 1 4250 5730 1951 4160 3d 60 c f1 3300 1 3000 2 5100 10830 1955 4160 3d 60 cyl 4000 1 3600 3 4250 15080 1943 4160 3d 60 cyl 3250 1 3000 4 7760 22840 1972 4160 3d 60 cyl 5600 1 5600 5 6 7 8 9 3168 316S 1962 4160 3d 60 cyl 2200 1 2200 10 11 3168 6336 1?62 4160 3d 60 cyl 2200 1 2200 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 TOTALS 2;,350 7 20.600 39

  /

lme --

                                                                                                                                                                                             > SI GENERATING STATION STATISTICS (Sm ll Strtion;)                                                                             E E

1. Small genirtting stctions, for the purpose of this or oper~ted as a joint frcility, tnd giva a concise 5. If penk d;mm.nd for 60 rninutes k not evall-  ;

schedule, are steam and hydro stations of less than statement of the facts in a footnote. able, give that which is available, specifying period. j 2,500 KW* and other stations of less than 500 KW* 3. List plants appropriately under subheadings for 6. If any plant is equipped with combinations of 2 installed capacity (name plate ratings). (*10,000 KW steam, hydro, nuclear internal combustion engine and steam, dro, internal combustion engine or gas tur- o tnd 2,500 KW, respectively,if annual electric operat- gas turbme stations. For nuclear, see instruction 10 bine eq ment, each should be reported as a separate  : ing revenues of respondent are $25,000,000 or more.) page 59. plant, owever if the exhaust heat from the gas  :

2. Designate any plant leased from others, operated 4. Specify if total plant capscity is reported in kva turbine is utilizedin a steam turbine regenerative feed i under a license from the Federal Power Commission, instead of kilowatts, water cycle, report as one plant. j Production Expenses Fuel Cost :

Installed Het Plant Exclusive of Depreciation Per KWH j Capacity Peak Generation Cost and Taxes Net  : Name of Plant Name Demand Excluding Per KW (Omit Cents) Kind Generation : Year Plate KW Station Cost of Plant Inst. of (Cents) {c$ Lins Const. Rating-KW (60 Min.) Use (Omit Cents) Capacity Labor Fuel Other

• Fuel (0.0000) :

No. (a) (b) (c) (d) (e) (f) (g) (h) (I) (j) (k) (1) { gj ~

                                                                                                                                                                                             !O 1                                                                                                                                                                                     i :::
       ,,                                                                                                                                                                                    : c
                                                                                                                                                                                             .o

c2 3  : o 4 3g 5  : s 6 iS g

7 8 UOT APFLICABLE !E

                                                                                                                                                                                              .o 9                                                                                                                                                                                      :
                                                                                                                                                                                              * *c 10                                                                                                                                                                                        : o

si 12  :

                                                                                                                                                                                              *U 13                                                                                                                                                                                        : to

*c 14  : >

15 i. 17 jw 18 i 19 i .g 20 ) 821 g 22 E O 23 g 24 3 a 25 t u 26 ,- i

    - 7                                                                                                                                                                                       g 23                                         TOTALS                                                                                                                                           g n                                                                               _

67 Annust riport of.. .... .... .. .. .... .. .. . .. . .h.h..kNdb'1MI... . . ..Vaar ended Decembsr 31.19. . TilANS511SSION LINE STATISTICS Report information concerning transmission lines as indicated below. Designation Length (Pole Miles) Type of Operating Supporting On Structures of On Structures of Nu ber ' From To f C du tar Line Voltage Structure Line Designated Another Line Circuits and Material No. (a) (b) (c) (d) (e) (f) (g) (h) i t

f. t!arl-iludson 7orest Ave.

I 2 Town Line Substation 115KV Steel 3.2 2 336.4 MCF 3 at River St. Iludson Poles ACSR 4 " Linnet" 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

   %       o, 23 24 25 26 27 28 29 30 31 32 f          M 34 35 36 37 38 l          39 i          40 41 l   C      :'

44 l 45 46 t 1 \ -- g TOTALS 3.2 None 2

                  'Where other than 60 cycle,3 phase, so indicate.

l l L _

                    . . _ - . , . . . _ - - - , . _ - _ . . - - .                                                  - - - ,        --- -            - - ~ . -       --             --    -

69 A n nuei report et . . . . . . . . . .E0?fN

                                                  . . . . . . . .OF ..... 11UDSOU
                                                                               . . . . . . . . .1. .lGilT
                                                                                                     .       AUD
                                                                                                               . . . P0. H.H... D.E.P.A.R.T. M.
                                                                                                                                                    ........ .. Year Ended Decomter 31,19.g E..n..t.......

OVERIIEAD DISTRIBUTION LINES OPERATED

    '                                                                                                                                  Length (Pole Miles)

Line No. Wood Poles Steel Towers Total 1 Miles - Beginning of Year. 175.2 175.2 s [' 2 Added During Year. . . .4 ,4 3 Retired During Year. . None None 4 Miles - End of Year. 175.b 175.6 5 6 7 8 Distribution System Characteristics - A.C. or D.C., phase, cycles and operating voltages for Light and Power. 9 Prinary distribution at 2400/4160Y, 4800/8300Y, 8000/13800Y volts, 60 cycle, 10 3 phase secondary power at 600 volts, 60 cycle, 3 phase 3 wire; 480 volts 11 3 phase, 3 wire; 277/480 volts, 3 phase 4 wire; 220 volts, 3 phase 3 or 4 wire; 12 120/208 volts, 3 phase, 4 wire, lighting, heating and air conditioning 13 120/240 volts, 120/208 volts, 60 cycle single or three phase. 14 15 ELECTRIC DISTRIBUTION SERVICES, METERS AND LINE TRANSFORMERS Line Transformers Number of Total Electric Wett-hour Capecity y Line t No, item Services Meters Number (kve) A __ 16 Number at beginning of year. . 6822 8579 2810 67,120.5 17 Additions during year:

                                                                                                               *******                   394                      39                  1'500*0 18        Purchased.

19 Installed. 167 20 Associated with utility plant acquired. None None None None 21 Total additions. . . 167 394 39 1,500.0 22 Reductions during year: 23 Retirements. . . . . 29 64 Mone None 24 Associated with utility plant sold. None None None None 25 Total reductions. . . . 29 64 None None 26 Number at End of Year. . . 6960 8909 2849 68,620.5 27 In stock. 663 437 10,222.5 28 Locked meters on customers' premises. . None None None 29 Inactive transformers on system. None None None 30 In customers' use. . 8221 2404 58,264.0 31 In company's use. . 25 8 134.0 32 Number at End of Year. 8909 ' 2849 68,620.5 O

                         - _ ,        ,w-        g,-,-   --
                                                                      - - -, -                         -        - - ,           ,-                                  --r-- - -         , , - - -          -

o CONDUIT, UNDERGROUND CABl.E AND SUBMARINE CABLE-(Diltribution Syttsm) yo Report below ths information callzd for conctrning conduit, undtrground cable, and submarine cible tt end of year.  ! 1 Underground Cable Submarine Cable h Miles of Conduit Barik $ g Designation of Underground Distribution System (All Sizes and Types) Miles

• Operating Voltage feet
• Operating Voltage o.

No. (a) (b) (c) (d) (e) (f) j

  ) _                                                                                                                                                                                          i 1      Route 495 Underpass                                                                      .1                    .1           13,300                                             !

2 I*arvard Acres I: states, tou C.5 G.5 13,000 i 3  ;-ieedovbrcok F.obile !!ome Park, IIudson 1.0 1.9 13,800 l 4 Colburn & ilargaret Circle, IIudcon .0 .2 1,000 ie 5 t'ain, Felton, Central St. Iudson .7 .7 13,800 j@ 6 Seven Star Lane, Stow,:IA .0 .00 4,SCO i" 7 Forest Avenue , iudson, In 1.5 1.5 13,003 !o w 8 Juniper I:sta tes , Stow, III.. .5 . 13,000  :- i 9 Carriage Lane, Stow, ila .0 . 1.* 4,800 i.i c:d to Drigham Circle, ::udnen, F1. .9 .9 13,000 j [$ Rustic Lane, IIudson, in .0 .2 4,000  : ~~ 11 ~e 12 Wildwood subdivision, Stou, IIA .0 .0 13,000 is I 13 Birch !!ill 1: states, Stow, ;1A 1.8 1.0 11,000 j$$ 14 Appleton Drive, Hudson, IIA .1 .1 13,000 i "> 15 Cedar Street, !!udson,I4A .03 .03 4,000 jg 16 Country Estates , IIudson, P.A .0 .3*

• 000 Deacon Benhan Drive, Stow, ilA .0 .07 0,320 l

, 17 18 Forest Poad, S tou , Yo; .0 .22 0,320 i[N 39 Francis Circle, Stow, in .0 .1 4,000 l* 90

       ~

Faren Circle , IIudson, :C .0 .07 0,320 :O 21

                ;Iain Street, Iturlson, IIA (Uhispering Pines)                                            .11                   .11         13,000                                              ! p'.

22 Glen Road , Iludson, I:7. . 24

                                                                                                          .12
                                                                                                                                .24          13,000 13,300 l$

23 Erighan Street (Valley Park) IIudson, :II. .12 i 24 righan Street ( Arnabet Village) IIudson , IIA .G4 .04  !.3,300 ;w Chapin Road , Iludson, IM .07 .07 13,000 i

        '5
        ~

Great Road, Stow, :II. .07 .07 i 6 ., 27 ,E - 28 g a 29 e g 30 o a

                                                                                                                                                                                                  =

31 3 32 { 33 3 34 ToTAts 14.53 16.71 Hone 1. e

• Indicate number of conductors per cable. g00

                         ~

                                  . ..E0WN.0F..!!UD.S.Cl.LIMT..A7.9..g0,y14,,pif,4,4I@g,, ,, ,,              ,yy, ended oecsmer2r ai.19h l Annu: report af.....

STREET LAMPS CONNECTED TO SYSTE31 Type Y Total Fluorescent Incandescent Mercury Vapor Town Other Munecipal Other Municipal Other Municipal Other Municipal No. (a) -(b) (c) (d) (e) (f) (g) (h) (i) (i) 1 Ilud::on 1622 397 19 3')0 2')7 1:one IIone 13 6 176 104 3 17 52  ;;one  !!cne  ;;one ;Ione f, g stow

 \'             Derlin                            i           1      !!one   I!one      lione        ;onc       :: enc  !!one     ;ione 3

4 Colton 3 2 IIone I one 1 Iione  ::one I;one Icne

                !!arlboro                         1      l!one       I;onc   !!one            1      !one       :ione  leone       ;one 5

6 7 _- 8 9 10 11 12 13 l i 14 l 15 j 16 j I 17 18 , 1 19 20 21 22 I 23 24 25 26 l 27 l l 28 i 29 1 30 31 32 33 34 35 36 l 37 1 38 39 40 41 42 43 (. 44 45 46

       ~

47 48

    -1 49 50 51 T TA"    1803       504          22      907        351        Iione      lione         13      6 52

Annu;l report cf....... 20'#:1 CF I!UD00:; Licill' A:'u Penh LIPAhrgg:;2 [d

                                                                                                              . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Y ea r and ed D ecIm b ir 31. 19. . . .

RATE SCllEDULE INFORMATION

1. Attach copies of all Filed Rates for General Consumers.

2. Show below the changes in rate schedules during year and the estimated increase or decrease in annual revenue predicated on the previous year's operations.

Estimated Effect on Cate M.D.P.U. Rate nnual Revenues Effective Number Schedule Increases Decrea ses l flu 6 I l

x A nnual report of. . . . . . . . . . . . . .20'nN

                                                      . . . . . . . .OF. . . . 11UDSON
                                                                               . . . . . . . . . . . . . . .LIG11I        AUD POWEh
                                                                                                            . . . . ............              DIPARIEliEt.......
                                                                                                                                   . ...................          . ... Year onded Decernber 33. Ib THIS RETURN IS SIGNED UNDa1R THE PLNALTIES OF PERJURY i

Mayor

                                                                                                                                                                     . Manager of Eledric Light a!    . .S s'
                                             .             .M                                                                .                           .               .

Seledmes g .d. .>... .

                                                                                                                                                                                     .g ,/,,4 Light Board
 )                                .                                                                                                                                           .

b SIGNATURES OF ABOVE PARTIES AFFIXED OLTSIDE Tl;E COf1MONWEALTH OF MASSACHUSETTS MUST BE PROPERLY SWORN TO

                                                                                                                   ..sa.                                                                   19 Then personally appeared..

and severally made oath to the truth of the foregoing statement by them subscribed according to their best knowledge and belief. N>tary Public or

                                                                                                                                                                           .. Justice of the Peace
   * . -   h$

w

                                                                                                                                                                                             \

INDEX Page Appropriations of Surplus . . . . . . . . . . . . . . . . . . . . 21 Appropriations Since Beginning of Year . . . . . . . . . . . . . . . . . . 5 Bonds . . . . . . . . . . . . . . . . . . . . . . . . . 6

     , Cash Balances          .   .    .    .   .   .   .       .         .    .       .      .                .     .      .      .      .         .    .    .             .     .      14

( Changes in the Property . . . . Combustion Engine and Other Generating Stations .

                                                                                                                                                                                  . 64-65 5

Comparative Balance Sheet . . . . . . . . . . . . . . . . . . . . 10-11 Conduit, Underground Cable and Submartoe Cable . . . . . . . . . . . . , . . 70 Cost of Plant . . . . . . . . . . . . . . . . . . . . . . . 8-9 Customers in each City or Town . . . . . . . . . . . . . . . . . . . 4 Depreciation Fund Account . . . . . . . . . . . . . . . . . . . . 14 Earned Surplus . . . . . . . . . . . . . . . . . . . . . . . 12 Electric Distribution Services. Meters and Line Transformers . . . . . . . . . . . . . 69 Electric Energy Accounts . . . . . . . . . . . . . . . . . . . . . 57 Electric Energy Purchased . . . . . . . . . . . . . . . . . . . . 54,22 Electric Operating Revenues . . . . . . . . . . . . . . . . . . . . 37 Ele:tri: Operation and Maintenance Expenass . . . . . . . . . . . . . . . . . 39-42 Gcneral Infornation . . . . . . . . . , . . . . . . . . . . . . 3 Generating Station Statistics . . . . . . . . . . . . . . . . . . . . 58-59 Generating Station Statistia (Small Statfo m) . . . . . . . . . . . . . . . . SS Hydroelectric Generating Stations . . . . . . . .. . . . . . . . .'. . 62-63 Income from Merchandising. Jobbing and Contract Work . .. . . . . . . . . . . . 51 Income Statement . . . . . . . . . . . . . . . . . . . . . 12-13 Materials and Supplies . . . . . . . . .  ;*.. ,

                                                                                                                    .     .       .      .         .    .    .        .                  14 Mi=~11=neous Credits to Surplus         .   .   .       .         .    .       .      .
                                                                                                                    .    .        .     .          .    .    .        .    .    .        21 Miscellaneous Debits to Surplus          .   ,   .      .         .    .       .      .                .'    .     .       .      .         .    .    .        .    .     .       21 Misen11aneous Nonoperating lacome            .   .      .          .   .       .      .                .     .     .       .      .         .    .    .        .    .    .        21 Monthly Peaks and Output            .    .   .  .       .         .    .       .      .                .     .     .       .      .         .    .    .        .    .     .       57 s.

Municip-l Revenues . . . . . . . . . . . . . . . . . . .

                                                                                                                                                                      .    .     .       22

[ Other Income Deductions . . . . . . . . . . . . . . . . . . . . . 21

   %   Other Utility Operating Income           .  .    .      .         .    .       .      .                .     .     .       .      .         .    .    .        .    .     .       50 Ov*< head Distribution Lines Operated        .  .       . ..           .       .      .                .     .    .        .      .         .    .    .        .    .    .        69 Production Fuel and Oil Stocks          .    .   .      .         .    .. .           .- .                   .     .       .     .          .    .    .        .    .    .        18 Rate Schedule Information          .    .   .   .       .         .   .        .      .                .     .     .       .      .         .    .    .        .    .    .       71, Sales of Electricity to Ultimate Consumers      .       .         .   .        .      .               .     .     .        .     .         .     .   .        .          .       38 Sales for Resale - Electric         .   .   .   .       .         .    .       .      .               .     .     .       .      .         .     .   .        .    .   '. 52 22 Schedule of Esti==tes         .    .   .    .   .      .          .   .       .      .                .     .     .       .      .         .    .    .        .    .     .         4 Steam Generating Stations           .   .   .   .       .         .    .       .     .                .-.         .        .     .          .    .    .        .    .    . 60-61 Street Lamps          .   .    .    .   .   .   .       .         .    .       .      .                .     .     .       .     .          .    .    .        .    .    .        71 Substations .         .   .    .    .   .   .   .      .          .    .      .- .                    .- .        .- .           .         .     .   .         .   .     .        68    2 Taxes Charged During Year           .   .   .   .      .          .    .       .      .                .     .     .       .     .          .         .        .   .     .       49 Town Notes           .   .         .       .    .      .         .    .       .      .                .     .     .       .      .         .    .    .        .          .         7 Transmimion Line Statistics        .   .   .   .       .         .    .       .      .                .     .    .        .      .         .    .    .             .     .       67 Utility Plant - Electric      .    .    .   .   .      .          .    .       .      .                .    .     .        .     .          .    .    .       .    .     . 15-17 l

l i i Page FOR GAS PLANTS ONLY: , Boilers . . . . . . . . . . . . . . . . 75 Gas Distribution Services and House Governors and Meters . . . . . . . . . . . 78 Gas Generating Plant . . . . . . . . . . . . . . . . . . 74 m Css Operating Revenues . . . . . . . . . . . . . . . . . . 43 Gas Operation and Maintenance Expenses . . ., . . . . . . . . . 45-47 5- Holders . . . . . . . . . . . . . . . . . . . 76 Purchased Gas . . . . . . . . . . . . . . . . . . . 48 Purifiers . . . . . . . . . . . . . . . . . 76 Record of Sendout for the Yearin MCF . . . . . . . 72-73 Sales for itesale 4E Sales of Gas to Ultiniste Consuiners 44 Sales of Residuals . . . . 48 Scrubbers. Condensers and Exhausters . . . . 75 Transmission and Distribution Mains . . . . . . . . . 77

EXTRACTS FROM CHAPTER 164 OF THE GENERAL LAWS AS AMENDED ! SECTION 56. The Mayor of a city, or the salectuten or municipal light board,if any, of a town acquiring a gns or electrie plant l hsil appoint a ma.ager of municipal lighting who shall, under the direction and control of the mayor, selectmen or municipal light the manufacture and ,, sostd, if any, listributien andor of gas subject to this electricity, thechapter, purchr.se have full charge of supplics, theof the operation employment and management of agents ofthe and servants, themetho plant, d, time, price, uantity

-                                                                                                             liis compensation and term of o&ce shall               Axed l

l and quality of the supply, the collection of bille, and the keeping of accounts.n cities by the city council and in tow

, >f his oscis] duties, he shall give bond to the city or town for the faithful pericemance thereof in a sum and form and with sureties l 4 tha satisfaction of the mayor, selectmen or municipal light board, if any, and shall, at the end of each municipal year, render a tham such de'. ailed statement of his doings and of tho business and financial matters in his charge as & department may pro-l ieribe. All moneys payable to or received by the city, town, manager or municipal light board in connection with the operation
   >f ths plant, for the sale of gas or electricity or otherwise, shall be paid to the city or town treasurer. All accounts rendered so or upt in ths gas or electric plant of any city shall be subject to the inspection of the city naditor or emeer having similar duties,

( nayandrequire in towns they presenting any person shall be for subject to the settlement inspection un account or claimofagainst the selectmen. The oath such plant to make auditor before orhim oscer having or them,in suchsimilar , .'orm as ha or they may prescribe, as to the accuracy of such account or claim. The wilful making of a false cath shall be punish-I ibis rs pstjury. The auditor or omeer having similar duties in cities, and the selectmen in towns, shall approve the payment of

; dl bills or pay rolls of such plants before they are paid by the treasurer, and may disallow and refuse to approve for payment, in ebola er in part, any claim as fradulent, unlawful or excessive; and in that case the auditor or omcer having duties, or the select-nen, shall file with the city or town treasurer a written statement of the reasons for the refusal; and the treasurer shall not pay

, sny claim or bill so disallowed. This section shall not abridge the powers confened on town accountants by sections afty.6ve when required by the mayor, selectmen, municipal oight staty.ons, board, ifinclusive, of chapter forty-one. any, or department, make a statementThe manager to suchshall at any oscers time' doings, business, receipts, disbursements, balances, and of his

; if ths indsbtedness of the town in his department.

SecTrow 57. At t.he beginning of each Ascal year, the ==narer of municipal lighting shall furnish to b mayor, selectum l ir municipal light board, if any, an estimate of the income from sales of gas and electricity to private consumers during the ansc34 i iscal year, aad of the expense of the plant during said year, mannine b gross expenses of operation, mainhanea and repair, N

! ntere:t en the bonds, notes or certiSeates of indebtedness issued to pay for the plant, an amount for depreciation equal to th/cs
' per cent cf the cost of the plant exclusive of land and any water power appurtenant thereto, or such == airer or larger amount e.s

;hi department may approve, the requirements of the sinking fund or debt incurred for the plant, and the loss, if any, in the opesn-

d:n of tha plant during the precediug year, and of the costs, as deaned in section 58, of the gas and electricity to be used by tha

own. Thi town shall include in its r.nnual appropriations and in the tax levy not less than the estimated cost of the gas sad

 ! deetricity to be used by the town as above dettned and estimated. By cost of the plant is intended the total amount expendM i m th3 pl:nt to the beginning of the Ascal year for the purpose of establishing, purchamitig, extending or salargmg the same. TO l mes in operation is intended the diference between the actual incoma from private consumers plus A appopriations for main 6                                                    1 l sanco fer the preceding Ascal year and the actual expense of the plant, reckoned as above, for that year in case such arpensca taceeded b amount of such income and appropriation. The income from sales and the money appropriated as aforesaid shaU 23 used to pay the annual expense of the plant, deaned as above, for the Sacal year, except that no part of the sura therein included i fr dIpreciation shall be use.1 for any other purpose than renewals in excess of ordinary repairs ex+=i- reconstruction, enlaret i nents and additions. The surplus if any, of said annual allowances for depreciation after maldng the above payments shall te j kept as.a separate fund and used for renewals other than ordinary repairs, extensions, reconstructions, enlargements and additiom .

in succeeding years; and no debt shall be incurred under section forty fer any extension, reconstruction or enlargements of the plant in exe:ss cf the amount needed therefor in addition to the amount then on hand in said depreciation fund. Said depreciation food shall be k2pt and managed by the town treasurer as a separate fund, subject to appropriation by the city council or selectman u

, municipal llght board, if any, for b foregoing purpose. So trach of said fund as the department may from time to time approto ' may clso be used to pay notes. bonds or certi$entes of indebtedness issued to pay for the cost of reconstruction or renewals in excenc , " af crdinary repairs, when such notes bonds or certiacates of ladebtedness become due. All appropriations for the plant shan bc eithir f:r the annual expense denned as above, or for extensions, reconstruction, enlargements or additions; and no appropriation shall be used for any purpose other than that stated in the vote making the same. No bonus, notes or certinentes of indebtednesc shall be lasued by a town for the annual expenses as doomed in this section. i Section 63. A town manufacturing or selling gas or electricity for lighting shall keep records of its work and doings at its I manufacturing station, and in respect to its distributing plant, as may be required by the departmant. It shan instan and ms!n-tain cpparatus, satisfactory to the department, for the measurement and recording of the ou at of gas mid electricity, and aboll sell the same by meter to private consumers when required by b department, and, if by it, sha'.i measure au gas or alv:- tricity consumed by the town. The books, accounts and retu:ss shall be made and kept in a form prescribed by h de u t, and ths accounts shall be closed annually on the last day of the n=e=1 year of such town, and a balance sheet of that shall

be takin therefrom and included in the retun to the department. The mayor, selectmen or municipal light board and managst i

t sinll, et any time, on request, submit said books and accounts to the inspection of the department and furnish any statement cr l Inf:rmati:n required by it relative to the condition, management and operation of said business. The department shall, in its ' canett report, describe h o tion of the several municipal plants with such detail as may be necessary to disclose the fMmMal conc'itira and results of each nt; and shall state what towns, if any, operating a plant have failed to comply with this chapter, and what towns if any, are selling gas or electricity with the approval of the department at less than cost. The mayor, or selectmen, cr municipal ligitt board, if any, shall annually, on or before such date as the department fixes, make a return to the department, far b preceding ascal year, signed and sworn to 1.y the mayor, or by a majority of the selectmen or municipal li ht board, if any, and by ths manager, stating the financial condition of said business, the amount of authorized and existing indeb , a statement of incoma and expenses in such detail as the department may require, and a list of its salaried omeers and the salary paid to each. Th3 mayor, the selectmen or tho municipal light board may direct any additional returns to be made at such time and in such detail as ha er they may order. Any omeer of a town manufacturing or selling gas or electrielty for lighting who, being required by this meetira to make an annual return to the department, neglects to make such annual return shall, for the arst afteen days or portion th:reof during which such neglect continues, forfeit are dollars a day; for the second afteen days or.any portion thereof, ten dollsys a dry; cad for each day thereafter not more than afteen dollars a day. Any such omeer who unreasonably refuses or neglects to maka such return shall, in addition thereto, forfeit not more than ave hundred dollars. If a return is defective or appears ts he , erroneous, the department shall notify the ofBeer to amend it within afteen days. Any such omeer who neglects to amend #41d i return within the time speci3ed, when notified ta do so, shall forfeit afteen dollars for each day during which such neglect continues.  !' All farfzitures incurred under this section may be recovered by an information in equity brought in the supreme judicial court t tha attornsy general, at the relation of the department, and when so recovered shall be paid to the com'nonwealth. SecrtCN 69. The supreme judicial court for the county where the town is situated shall have jurisdiction on petition of the departmsnt or of twenty taxable inhabitants of the town to compel the axing of prices by the town in compliance with sections afty.eeven and afty-eight, to prevent any town from purchasing, operating or selling a gas or electric plant in violation of any provisica of this chapter, and generally to enforce compliance with the terms and provisions thereof relative to the manufacture , er dis 1ribution of gas or electricity 1y a town.

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I i FINANCIAL STATEMENTS AND AUDITORS' REPORT TAUNTON MUNICIPAL LIGHTING PLANT , December 31, 1982

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t i a f AlexanderGrant

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N

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FINANCIAL STATEMENTS AND AUDITORS' REPORT TAUNTON MUNICIPAL LIGHTING PLANT December 31, 1982

       .-__,,y        .           y,_-..~   .-   . _ _ - - .,

CONTENTS Page 3 AUDITORS' REPORT FINANCIAL STATEMENTS 4 BALANCE SHEET S STATEMENT OF EARNINGS STATEMENT OF SURPLUS 6 STATEMENT OF CHANGES IN FINANCIAL POSITION 7 8 NOTES TO FINANCIAL STATEMENTS SUPPLEMENTAL INFORMATION 14 AUDITORS' REPORT ON SUPPLEMENTAL INFORMATION UTILITY PLANT 15 17 OPERATING EXPENSES

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Alexander Grant & COMPANY MEMBER FtRM CERTIFIED PUBLIC ACCOUNTANTS ORANT THORHTON INTERN ATION AL Municipal Light Commission of the City of Taunton Taunton, Massachusetts We have examined the balance sheet of Taunton Municipal Lighting Plant, (a department of the City of Taunton) as of December 31, 1982, and the related statements of earnings, su rplus and changes in financial position for the year then ended. Our examination was made in accordance with generally accepted auditing standards and, accordingly, included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances. As discussed in note G, Taunton Municipal Lighting Plant records pension expense based on a formula determined by the Town; whereas, generally accepted accounting principles require the use of actuarial methods in determining annual pension expense. In our opinion, except for the effect on the financial statements of the accounting policy discussed in the second paragraph, the financial statements referred to above present fairly the financial position of the Taunton Municipal Lighting Plant at December 31, 1982, and the results of its operations and changes in its financial position for the year then ended, in conformity with generally accepted accounting principles applied on a basis consistent with that of the preceding year. f ft i Aw/ 7h' 4 Boston, Massachusetts April 1, 1983 1 99 HIGH STREET BOSTON MA 02110 (617)357-5787

l i Taunton Municipal Lighting Plant BALANCE SHEET December 31, 1982 ASSETS UTILITY PLANT - AT COST Plant in service $55,062,184 Less accumulated depreciation (note A2) 24,064,273 Net utility plant in service $30,997,911 Construction work in progress (note D) 2,284,773 Total utility plant 33,282,684 DEPRECIATION FUND Cash 2,542,984 CURRENT ASSETS Cash (note F) 1,407,732 Customer deposits (note F) Principal fund 149,213 Interest fund 20,876 Accounts receivable 4,714,414 Less allowance for doubtful receivables 449,239 4,265,175 Materials and supplies inventory (note A4) 2,878,194 Prepaid insurance 114,837 Total current assets 8,836,027

                                                              $44,661,695 The accompanying notes are an integral part of this statement.

4

1 i r PRC LIABILITIES AND SURPLUS SURPLUS CARJ Appropriated surplus Loans repayment $10,167,000 Construction repayment 32,434 10,199,434 Unappropriated surplus 7,045,065 Total surplus $17,244,499 LONG-TERM DEBT (note C) Bonds payable 23,027,417 Less current maturities 470,000 Total long-term debt 22,557,417 CURRENT LIABILITIES Accounts payable 2,628,358 Customer deposits 149,213 Current maturities of long-term debt 470,000 Accrued liabilities Interest 743,842 Compensated absences 820,247 Payroll 48,119 Total current liabilities 4,859,779 COMMITMENTS AND CONTINGENCIES (notes D and E) Also Available On Aperture Card

                                                            $44,661,695 f

k 8808240592-ot

Taunton Municipal Lighting Plant STATEMENT OF EARNINGS Year ended December 31, 1982 Operating revenues Sales of electricity 4 Commercial and industrial $13,720,331 Residential 10,437,331 Sales for resale (note D) 9,881,981 Municipal 1,553,408 $35,593,051 Other operating revenues 38,900 Total operatin!g revenues 35,631,951 Operating expenses Power production 24,815,777 Transmission and distribution 948,061 Customer accounts 597,853 Administrative and general 2,758,809 Depreciation (note A2) 1,539,074 Total operating expenses 30,659,574 Earnings from operations 4,972,377 Other income (expense) Interest income 272,374 Interest expense on bonds (1,783,483) Other (44,249) Total other income (expense) (1,555,358) NET EARNINGS BEFORE PROVISION FOR PAYMENT IN LIEU OF TAXES 3,417,019 Provision for payment to the City of Taunton in lieu of taxes (note B) 938,000 ! EXCESS NET EARNINGS AFTER PAYMENTS TO CITY OF TAUNTON $ 2,479,019 t The accompanying notes are an integral part of this statement. 5

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i i Taunton Municipal Lighting Plant [ STATEMENT OF SURPLUS 1 Fear ended December 31, 1982 ? 4

 .                                                                               Appropriated Surplus I                                                                                  Loans                                 Construction            Unappropriated Repayment                                         Repayment              Surplus i

i Balance at January 1, 1982 $ 9,722,000 $32,434 $5,011,046 I ADD OR (DEDUCT) Transfer from unappropri-ated surplus of bond payments during year 445,000 (445,000) Excess net earnings after payments to City of i Taunton 2,479,019 i Balance at December 31, 1982 $10,167,000 $32,434 $7,045,065 i i I The accompanying notes are an integral part of this statement. 4 6

_= .. - -. - ._. . Taunton Municipal Lighting Plant STATEMENT OF CHANGES IN FINANCIAL POSITION Year ended December 31, 1982 Sources of working capital From operations Net earnings before payment in lieu of taxes $3,417,019 Charges (credits) to earnings not using (providing) working capital Depreciation of utility plant (note A2) 1,539,074 Amortization of bond premium (3,354) Funds from operations before payment in lieu of taxes 4,952,739 Provision for payment to City in lieu of taxes (note B) (938,000) Net working capital provided from operations 4,014,739 Applications of working capital Current maturities of long-term debt (note C) 470,000 Utility plant additions - net 3,583,390 Increase in depreciation fund 101,378 Total applications of working capital 4,154,768 DECREASE IN WORKING CAPITAL (140,029) Working capital at January 1, 1982 4,116,277 Working capital at December 31, 1982 $3,976,248 j Changes in components of working capital Increase (decrease) in current assets Cash $ 814,469 Customer deposits 2,600 Accounts receivable - net (1,333,856) Inventories (63,953) , Prepaid insurance 36,149 (544,591) (Increase) decrease in current liabilities Accounts payable 490,612 Customer deposits 4,710 Current maturities of long-term debt (25,000) Accrued liabilities (65,760) 404,562 DECREASE IN WORKING CAPITAL $ (140,029) h The accompanying notes are an integral part of this statement. / 7

Taunton Municipal Lighting Plant NOTES TO FINANCIAL STATEMENTS December 31, 1982 NOTE A -

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES A summary of Taunton Municipal Lighting Plant's ("the Plant's") I significant accounting policies consistently applied in the preparation of the accompanying financial statements follows.

1. Rates Rates charged by the Plant are not subject to the approval of regulatory agencies. Pursuant to state laws, rates must be such that the resulting net earnings less bond payments do not exceed 8% of the cost of utility plant.

During 1982, the Plant's earnings amounted to 5.4% of utility plant. 4 2. Depreciation Pursuant to state laws, depreciation is calculated as a percentage of depreciable property at January 1. Depreciation was computed at 3% of the cost of depreciable property for 1982 and 1981. The amount transferred from the operating fund to the depreciation fund during the year was $3,919,074. Depreciation Fund cash is used in accordance with state laws for replacements and additions to the electric plant in service. ,l

3. Pension Pla_n_

Substantially all employees of the Plant are covered by a contributory pension plan administered by the City of Taunton in conformity with State Retirement Board i requirements. In addition, the Lighting Plant has a i separate Employees Retirement Trust for the financing of future pension premiums. At December 31, 1982, the

Retirement Trust had net assets of approximately l

                   $1,177,000.       The plant contributed approximately $984,000 for pensions        in 1982,                which     included  $350,000     to   the

, separate Retirement Trust. l l 4. gventory l Materials and supplies inventory is carried at cost, T principally on the average cost and first-in, first-out methods. f ( l 8

i Taunton Municipal Lighting Plant NOTES TO FINANCIAL STATEMENTS - CONTINUED December 31, 1982 NOTE B - CONTRIBUTION TO THE CITY OF TAUNTON IN LIEU OF TAXES By vote of the Municipal Light Commission, the Planc contributed

      $938,000 in 1982 to the City of Taunton in lieu of taxes.          All contributions   to   the  City   are  voted  by the  Municipal   Light Commission and are voluntary.

NOTE C - LONG-TERM DEBT Long-term debt at December 31, 1982, is comprised of the following: Electric loan, Act of 1969 Interest rate - various rates from 7% to 8.5% dated February 1, 1976. Interest payable February 1 and August 1. Due serially from February 1, 1977 to February 1, 2006 $22,515,000 Unamortized premium 77,417 Electric loan, Act of 1963 Interest rate 3.1% dated August 15, 1965. Interest paya' ole August 15 and February 15. Due serially from August 15, 1966 to August 15, 1985 135,000 Electric loan, Act of 1963 Interest rate 3% dated January 1, 1965. Interest payable January 1, and July 1. Due serially from January 1, 1966 to January 1, 1985 300,000 23,027,417 Less current maturities 470,000 Total long-term debt $22,557,417 9

Taunton Municipal Lighting Plant NOTES TO FINANCIAL STATEMENTS - CONTINUED I December 31, 1982 i l NOTE C - LONG-TERM DEBT - Continued 4 Annual maturities of long-term debt are: 7% - 8.5% 4 3% Bonds 3.1% Bonds Bonds Total 1983 $100,000 $ 45,000 $ 325,000 $ 470,000 1984 100,000 45,000 350,000 495,000 1985 100,000 45,000 380,000 525,000 1986 410,000 410,000 1987 445,000 445,000 1988-2006 20,605,000 20,605,000 Bond premium _ 77,417 77,4 Q

                             $ 3 0 0 ,0_0 0_                  $135,000                       $22,592,417                           $23,027,417 NOTE D - COMMITMENTS Interconnection Agreement The City of Taunton, acting by vote of its Municipal Lighting Plant Commission, has entered into an agreement with Montaup Electric Company ("Montaup"), dated July 31, 1970, as amended, concerning interconnection of electrical operations, purchase and sale of kilowatt capacity, and construction by Taunton                                                                          of a generating unit of approximately 110 megawatt capability.                                                                         The agreement   is      for             a     period             of         twelve               years              following         the commencement of operations of Unit No. 9 on December                                                                       1,  1975.

Under the interconnection agreement, the City agrees to sell and Montaup agrees to purchase all capacity of Unit No. 9 not utilized by the City with a maximum not to exceed 95 megawatts in the first year of operation and on a declielng scale in subsequent years. It is estimated that by 1986 or 1987 Montaup will have purchased the maximum capacity allowed by law for sale to that utility. The Plant credited to sales for resale

              $9,290,194 of capacity and energy charges billed to Montaup Electric Company in 1982 for its share of power under the i              interconnection agreement.                           This agreement includes a provision that Taunton will purchase 8.2163% of the capacity and associated energy from Montaup's Somerset No. 6. generating unit for the period November 1, 1978 through October 31, 1984.

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Taunton Municipal Lighting Plant NOTES TO FINANCIAL STATEMENTS - CONTINUED December 31, 1982 NOTE D - COMMITMENTS - Continued Entitlements The Plant is a joint owner of the Seabrook Units 1 and 2 nuclear generating station located in Seabrook, New Hampshire. The lead participant in the project is Public Service Company of New Hampshire. The Plant's ownership share is .10034%. Expenditures of $2,018,946 through December 31, 1982, are included in the Construction work-in-progress account. It is estimated that Unit 1 will be completed in December, 1984, and Unit 2 will be completed in July, 1987. Public Service Company's latest estimates put the cost of building the two units at $5.24 billion. NOTE E - CONTINGENCIES Several contractors have initiated litigation to recover additional costs alleged to have been incurred during the construction of Unit No. 9. The Lighting Plant has disputed these claims which total approximately $282,000. Although it is not possible to determine the outcome of this litigation, management of the Lighting Plant does not anticipate that the ultimate disposition of these suits, even if adversely decided, will have a material adverse effect on earnings or financial position of the Plant since such amounts would be capitalized to the cost of Utility Plant. , NOTE F - CASH Municipal Lighting Plant cash is in the custody of the City of Taunton Treasurer and is commingled with other city funds. NOTE G - DEPARTURE FROM GENERALLY ACCEPTED ACCOUNTING PRINCIPLES Pension expense is not recorded in accordance with generally acceptred accounting principles which require, as a minimum, an annual provision equal to the total of normal cost of present employees under the plan, an amount equivalent to interest on any unfunded prior service cost, and a provision for vested benefits. I

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Taunton Municipal Lighting Plant NOTES TO FINANCIAL STATEMENTS - CONTINUED December 31, 1982 NOTE G - DEPARTURE FROM GENERALLY ACCEPTED ACCOUNTING PRINCIPLES - Continued Instead, the Plant's pension expense is based on the current year contributions to the City's retirement fund and the Plant's retirement trust. The contribution to the City's retirement fund is based on the projected benefits to be paid during the year, while the contribution to the retirement trust is a straight-line funding of $350,000 per year for ten years. The Plant's retirement trust is presently being actuarially viewed. The effect on the accompanying financial statements of this departure from generally accepted accounting principles has not been determined. i 4 e 12

4 e SUPPLEMENTAL INFORMATION k 1 h

AUDITORS' REPORT ON SUPPLEMENTAL INFORMATION Taunton Municipal Lighting Plant Our examination was made for the purpose of forming an opinion on the basic financial statements taken as a whole of Taunton Municipal Lighting Plant for the year ended December 31, 1982, which are presented in the preceding section of this report. The supplemental information presented hereinafter is presented for purposes of additional analysis and is not a required part of the basic financial statements. Such information has been subjected to the audit procedures applied in the examination of the basic financial statements, and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole. M Me / s% d Boston, Massachusetts April 1, 1983 l l

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k ( Taunton Municipal Lighting Plant UTILITY PLANT Year ended December 31, 1982 Balance January 1, 1982 Utility plant in service Steam production plant Land and land rights $ 245,509 Structures and improvements 5,791,295 Boiler plant equipment 14,054,535 Turbo-generator units 11,888,375 Accessory electric equipment 2,507,298 Miscellaneous power plant equipment 228,448 Total steam production plant 34,715,460 Other production plant Fuel holders, producers, and accessories 507,164 Generators 82,607 Accessory electric equipment 402,423 Total other production plant 992,194 Transmission plant 3 p Land and land rights V 217,807 Clearing land and rights of way -- 22,601 [( .f _~- ,k ; k;< 1 '_, 129,376 Structures and improvements Station equipment 1,871,529 Towers and fixtures . (j [k,k .) 849,092 284,208 Poles and fixturgs overhead conductors and devices 234,501 Underground conduit 3,104 Underground conductors 6,113 Total transmission plant 3,618,331 Distribution plant Land and land rights 189,056 Structures and improvements 101,704 Station equipment 1,669,928 Poles, towers and fixtures 1,876,759 Overhead conductors and devices 1,893,640 Underground conduit 1,383,927 Underground conductors and devices 1,443,531 l Line transformers 1,160,060 l Services 270,395 Meters 993,524 l l Street lighting and signal system 603,772 j y Total distribution plant 8308240592-ol. 1,586,296 Forward _ _ 15 _ , 50,912,281

Also Available On APerture Card Accumulated Net Book Balance Depreciation Value December 31, December 31, December 31, Additions Retirements 1982 1982 1982

                           $    245,509                     $      245,509
 $    13,775                  5,805,070   $ 3,141,413            2,663,657 294,873                 14,349,408     6,031,994            8,317,414 1,866,641                 13,755,016     4,113,510            9,641,506 21,255                  2,528,553     1,607,682              920,871 175,368                    403,816         75,336             328,480 2,371,912                 37,087,372    14,969,935          22,117,437 800                    507,964       116,017              391,947 800                     83,407         18,996              64,411 402,423         92,357             310,066 1,600                    993,794       227,370         ,

766,424 217,807 217,807 6,300 28,901 28,901 113 129,489 18,833 110,656 440,591 2,312,120 364,636 1,947,484 10,354 859,446 192,314 667,132 20,397 304,605 53,369 251,236 73,531 308,032 43,933 264,099 3,104 501 2,603 6,113 630 5,483 551,286 4,169,617 674,216 3,495,401 189,056 189,056 101,704 94,919 6,785 9,944 1,679,872 1,344,602 335,270 27,949 1,904,708 1,608,747 295,961 21,926 $ 33,660 1,881,906 852,098 1,029,808 11,612 1,395,539 978,434 417,105 24,104 35,500 1,432,135 833,254 598,881 40,393 8,697 1,191,756 739,418 452,338 9,349 1,980 277,764 76,495 201,269 28,097 29,600 992,021 639,964 352,057 l 8,178 3,960 607,990 316,550 291,440 181,552 113,397- 11,654,451 7,484,481 4,169,970 53,905,234 23,356,002 30,549,232 3 1 M 50 113 A

Taunton Municipal Lighting Plant i UTILITY PLANT - CONTINUED Year ended December 31, 1982 Balance January 1, 1982 Forwarded $50,912,281 Gnneral plant Land and land rights 35,691 Structures and improvements 281,965 Office furniture and equipment 101,284 Transportation equipment 534,336 Stores equipment 1,740 Tools, shop and garage equipment 13,093 Laboratory equipment 14,888 Power operated equipment 17,388 Communication equipment 85,101 Miscellaneous equipment 15,363 Total general plant 1,100,849 Total utility plant in service 52,013,130 Construction work in progress 1,893,795

                                                         $53,906,925 l

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1 Accumulated Net Book Balance Depreciation Value December 31, December 31, December 31, Additions Retirements 1982 1982 1982

 $3,106,350    $113,397      $53,905,234     $23,356,002                 $30,549,232 35,691                                                 35,691 281,965           231,868                               50,097 7,446                      108,730            54,385                               54,345 81,151      34,539          580,948           351,998                          228,950 1,740            1,684                                      56 13,093            13,093 14,888            10,003                                   4,885 17,388           14,294                                   3,094 1,757                       86,858            19,762                               67,096 286                        15,649           11,184                                   4,465 90,640      34,539        1,156,950_          708,271                          448,679 3,196,990     147,936       55,062,184        24,064,273                 30,997,911 390,978                    2,284,773                                    2,284,773 l
 $3,587,968    $147,936      $57,346,957     $24,064,273                  $33,282,684 l

( l ?RC "! A'l " UUR3 Also Available On 0 A;R,J . Areri re c ra l l l t I

8308240592-o3

Taunton Municipal Lighting Plant OPERATING EXPENSES Year ended December 31, 1982 POWER PRODUCTION EXPENSES Operation Supervision and engineering $ 233,055 Fuel 9,353,105 Labor and expenses 752,796 $10,338,956 Maintenance Supervision and engineering 61,547 , Structures 51,723 Boiler plant 491,082 Electric plant 869,251 Miscellaneous 28,964 1,502,567 Purchased power 12,974,254 Total power production expenses 24,815,777 TRANSMISSION AND DISTRIBUTION EXPENSES Operation Supervision and engineering 161,981 Labor 187,560 Supplies and expenses 44,603 Meter expenses 53,290 Customer installation 54 Street lighting and signal systems 154 Miscellaneous 76,421 524,063 Maintenance Lines - electric 273,240 Lines - steam 757 Street lighting and signal systems 51,812 Meters 42,308 Structures and equipment 43,337 Line transformers 717 Station equipment 9,255 Miscellaneous 2,572 423,998 Total transmission and distribution expenses 948,061 Forward 25,763,838 4 17

Taunton Municipal Lighting Plant OPERATING EXPENSES - CONTINUED Year ended December 31, 1982 Forwarded $25,763,838 CUSTOMER ACCOUNTS EXPENSES Operation Meter reading labor and expenses $ 98,647 Accounting and' collecting expenses 439,724

               !?ncollectible accounts                        42,000 Advertising expense                            17,482 Total customer accounts expenses                      597,853 ADMINISTRATIVE AND GENERAL EXPENSES Operation Administrative and general salaries           202,673 Office supplies and expenses                   82,683 Outside services employed                     221,114 Property insurance                            136,728 Injuries and damages                          257,189 Employee pensions and benefits              1,624,621 Miscellaneous general expenses                 36,615 Transportation expenses                        89,136 Regulatory commission expense                  15,593   2,666,352 Maintenance General plant                                               92,457 Total administrative and general expenses                               2,758,809 DEPRECIATION EXPENSE                                         1,539,074
                                                                     $30,659,574 4

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