ML18038A646
| ML18038A646 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 12/31/1983 |
| From: | Donlon W, Haehl J, Lempges T NIAGARA MOHAWK POWER CORP. |
| To: | NRC OFFICE OF ADMINISTRATION (ADM), Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 8403290177 | |
| Download: ML18038A646 (44) | |
Text
REGULATOR FORMATION DISTRIBUTION Sf M (RIDS)
ACCESSION NBR 8403290177 DOC ~ DATE 83/12/31 NOTARIZED NO FACIL:50 220 Nine Mile Point Nuclear Stat)on<
Unit ii Niagara Powe 50 410 Nine Mile Point Nuclear Station< Unit 2i Niagara Moha AUTH'AME AUTHOR AFFILIATION HAEHLiJ AGO Niagara Mohawk Power
- Corp, D~NLONE'IisJ ~
Ni agora Mohawk Power Corp>
LEMPGES>T.E, Niagara Mohawk Power Corp, RECIP ~ NAME-RECIPIENT AFFILIATION l
SUBJECT:
Annual Financia}
Rept 1983,H/840322 ltr.
DISTRIBUTION CODE:
MOORS COPIES RECEIVED:LTR jENCL g SIZE:
TITLE: Annual Financial Reports NOTES:PNL icy FSAR'S 8
AMDTS ONLY.
DOCKET 05000220 05000610 05000410 RECIPIENT ID CODE/NAME NRR ORB2 BC NRR ORB2 LA 01.
HERMANNgR COPIES LTTR ENCL
.1 0
1 1
1 0
RECIPIENT ID CODE/NAME NRR LB2 BC NRR LB2 LA 01 HAUGHEYgM COPIES LTTR ENCL 1
0 1
1 1
0 INTERN EG F ILE EXTERNAL: LPDR NTIS NOTES'0 03 05 1
1 1
1 1
1 1
1 1
TOTAL NUMBER OF COPIES REQUIRED:
LTTR 12 ENCL 8
f w>> )lit ""Il S t,V)t)>> f it'If II 1')
'f >>i l'II w
rt II
}I
}
W t i f
!il)3 i')g f
t t)ti)f
.f 'I t
W>>'
f f
t) I I
nl
)M
\\
}t ~
$t') 'e
~ I'} ~
<<e II t
(
t 1
y I >> q l,t }I "4 t g f I
I
, I,ff
'I. I)
<<\\e<<<<W<<g<<<<W<<<<ttM<<W<<<<>>
~ '<< -tt j
I i>>t )
gt,))lti t
)
<<y,))
A))w
)I gr "t,l)',ll ',
I lip
)I f
g') Jt,
)I f,j "<<g
)It I
t I>>)
'I
, tl l 4 I 0 If r
'C w
I
'>>f t
I f, u
)t)l ijk t 4)'.'t fii ll 4
w'
NIAGARAMOHAWKPOWER CORPORATION NIAGARA ~( MOHAWK THOMAS6. LSMPGES VCE P$CSICNT~ GENERATION 300 ERIK GOULEVARO WEST SYRACUSE, N.Y. 13202 March 22, 1984 Director Office of Nuclear Reactor Regulations c/o Distribution Services
- Branch, DDC, ADM U.S. Nuclear Regulatory Commission Washington, DC 20555
Dear Sir:
As required in Title 10, Chapter I, Code of Federal Regulations, Section 50.71(b),
and compiled in Regulatory Guide 10.1, enclosed are ten (10) copies of Niagara Mohawk Power Corporation's 1983 Annual Report.
Cordially, TEL/jkr Enclosures (10)
?
4 fP I)
Qp'8
~
~
D Q
~
9 I I
~
9 OOEIOOCIEIO
. CJOCJC1DDGDQCJQOCK3 00000000 OCJOQOOQO 000000QOOOCI OOQOCIOEIOQQCIOCIO 00000QQOOEIEIGQ0000 OOOEIOQQQEIQEIRilQ0000 0
CIOOOOOEIQEIEIEIEIEICIRiIOCICJOCICI OOOOElDEIQEIEIQQEIRilQEIQCIOOGG OOOOEIOGQRilEIQEIEilEIRiIEilRilEIEIOEIGOOGCI OOOOOEIEIQEIEIEIQEIQQOQEIOOOCJOO OOOOEIOEIQQQEIEIEIOEIOQOEIOEIOOG QOCIOOOCIOOQQQOOQOQOQOOOOCI GRlOOOOOOOQOOEICJQOOOOOOOOGGGG OG CIIBIBI700QCJCICICIQQEEQClC3C3C3HClC3000CICIO CIO
- HCIOQE3000C300CIDOHCIOC3 00
'000000000000 CIOOOOCI OOCIOEIOEIOOO OOQOEIOCJ OOCIOOEICICIOO 00000000 zHi 30 30 NOTICE THE ATTACHED FILES ARE OFFICIAL RECORDS OF THE DIVISION OF DOCUMENT CONTROL.
THEY HAVE BEEN CHARGED TO YOU FOR A LIMITED TIME PERIOD AND MUST BE RETURNED TO THE RECORDS FACILITY BRANCH 01G.
PLEASE DO NOT SEND DOCUMENTS CHARGED OUT THROUGH THE MAIL. REMOVALOF ANY PAGE(S)
FROM DOCUMENT FOR REPRODUCTION MUST BE REFERRED TO FILE PERSONNEL. ra/zr/ra DEADLINE RETURN DATE RECORDS FACILITYBRANCH OOORilQEIQOOO OCIO 0
OCIOQEICIEIOG OQQQEIEIEIDDO 000 DCJDQDQQQCIODO CIQQQElEIElEIOOOOOOOOCIOOEIQQOOOOCI EIQCIOQOQQQOEiICJDDOQQEIQEIQEICIQOOO OQCIOOOOCJQOOCJQOEICIQEIQEIEIOCIOOCJ 0
EICIOOODEIOQOQCIODDDQEIQQDCIOOOO 00 QOOOOOOOOOOOOQOQQQQQQOOOOOOOO 000 DDDDQDODDDDDQQGQDDDDDDDD 00 OOOOCIOOOCJOCIQOOQORl0000000 00 DCICICIOCIDCICIODCIDQDOCI00000000 OGOQOOOCI00000000000RilOOOGOCJOO WGE3QE3C30CIOOCJODCIOCIOOOCIOOOGCIODD OQQQBOOOOCJOCIOOOOOOOCJOOOQBGOO CIQQQti3QEIRJDOOCl00000000CIOEI000000 00000EIBOOCIOODDCIQCI00000000000CI 000000000000000QQQDOOOOOMOOO CJ CIDDDDOCIDQRIDCIOOOOCIOOMODOO CIOCIOOOOOGCIOOOOQOOOO 00000000CIOOOOOOOCI 000000CICIOOOOOOCIOCI 0000000000000000 000500000000000 OCI00000000 OCI00000 0000 OOCICI CIGOCI 0
00 0 DDCJ CIOO OQCJ OOO 0000 CIOOO CIOO0
8403290177 83123i PDR AJ3I3CK 05000220 I
o Serving Upstate NemYork Electric Service Area Spree
~
nese rs ~,
ool\\ovn orereown Opere F NEW YORK STATE Gas Service Area orerlown
~ovo pope
~n, es evw oron)fl
~~a ov +Oj So ~
eorreppe eV r
Conlonoe
~ I, 7
NEW YORK STATE Ranked as one ofthe most promi-nent investor-owned utilitics in the United States, Niagara Mohawk I'ower Corp. serves an area encom-passing morc titan halfthe land mass ofNew YorkState. Our elec-tric system extends from Lake Erie to Ncw England's borders, to Canada and Pennsylvania, and rnccts the diversified needs of nearly I 4 millioncustomers. Our natural gas system serves 433,000 customers in central, eastern and northern New York, nearly all within our electric territory. Two Canadian companies, St. Lawrence Power Co. and Canadian Niagara Power Company, Ltd. owned by our subsidiary, Opinac Investments, Ltd., provide energy to portions of Ontario. Other subsidiaries arc Hydra-Co Enterprises, Inc., N itrl Uranium, Inc, and Niagara Mohawk Finance, N.V. Our corporate head-quarters are 300 Erie Boulevard West, Syracuse, N.Y. 13202.
Contents Commitment to serve People in thc mainstream 10 14 Market price ofcommon stock 16 and related stockholder matters Management's discussion and 16 analysis offinancial condition Report ofmanagement and 20 independent accountants Financial statements Statistics Officers, directors 21 35 37 Cover Computer-styled map ofour service area depicts electric and gas systems in graphic design used in program to attract new business and industry to "Thc State ofNiagara Mohawk".
The Information In this report is not given In connection with the saic of, or oifer to buy, any security.
Prlnled in USA.
To our stockholders A year ofmomentum Research on technology's 8
cutting edge Investor notes Dividend Reinvestment Plan Stockholders participating in our Dividend Reinvestment and Stock Purchase Plan enjoy its tax-deferral and convenience features, while ncw capital is generated for the Company. Sce page 14 for details.
Telephone Inquiries We ntaintain a toll-free telephone inquiry service for stockholders.
Callers from outside Ncw York State may dial 1 + 800 + 448-5450.
The number for New'ork residents is I + 800 + 962-3236.
Annual Meeting The annual meeting ofstockholders willbe held iplay I, 1984 at the Company's main office in Syracuse.
Formal notices, proxy statements and forms willbe sent to holders of common stock in carly April.
Transfer Agents Preferred Stock anal Preference Stock:
Marine Midland Bank, N.A.
140 Broadway, New York, N.Y. 10015 ConInton Stock:
iVlorgan Guaranty Trust Company ofNew York 30 W'. Broadway, NcwYork, N.Y. 10015 Disbursing Agent Preferrefl, Preference and Co)n)non Stocks:
Niagara ttplohawk Power Corporation 300 Erie Boulevard West Syracuse, N.Y. 13202 StockExchanges Connnon and CertainPreferrertSeries)
Listed on New YorkStock Exchange Con))non Stock)
Also traded on Boston, Cincinnati, iblidwest, Pacific and Philadelphia stock exchanges.
Bonfls:
Traded on New York and Luxem-bourg stock exchanges.
Ticker symbol: NMK I'orm 10-K Report A copy ofthe Company's Form 10-K rcport filed annually with the Secu-rities and Exchange Commission is available after March 31, 1984 by writingJohn W. Powers, Vice Presi-dent-Treasurer, at 300 Erie Boule-vard West, Syracuse, N.Y. 13202:
1 Highlights of1983 Stock and dividend data 1983 1982
% Change
$2)632)315)000
$2,393,771,000 10 Total operating revenues Income available for common stockholders Earnings per common share Dividends per common share Common shares outstanding (average)
S 230,948,000 17
$2.64 5
$ 1.76 7
270,300,000
$2.77
$1.89 97,685,000 87,340,000 12
$5,516,532,000 691)464)000 594,469)000 16 Utilityplant (gross)
$6)165,711,000 Gross additions to utility plant
$2.64
$2.77
$2.00
$1.44
$2.35 Earnings
$1.87
$1.89
$1.76
'1,61
$1,50 Dividends Earnings and Dividends Paid per Common Share Kilowatt-hour sales Electric customers at end ofyear Electric peak load (Mlotvatts)
Natural gas sales (dettathenns)
Gas customers at end ofyear Maximum day gas sendout (dekathenns) 1,392,000 5,625,000 1,380,000 5,512,000 103,153,000 433)000 109,693,000 (6) 431,000 754,061 832,307 (9) 34,732,000,000 32,640,000,000 6
$ 15@
$ 15Va
$12%
$ 11 Vs
$12%
1979 1980 1981 1982 1983 Market Price ofCommon Stock at Year End The 1985 revenue dollar...
Residential customers 34'ommercial customers 31'ndustrial customers 22'II others 13'979 1980 1981 1982 1983 DivMcndpaid Price range 1983 pcr share 1 1lgh Low 1st Quarter
$.45
$ 171/8
$ 15>/8 2nd Quarter
.48 177/8 161/8 3rd Quarter
.48 17>/8 16 4th Quarter
.48 181/2 151/4 and where itwent 1982
$ 1.89 Fuel for tho production of electricity 34'nd electricity purchased Gas purchased 16C Income and other taxes 13'nterest and other costs-net 10'ages, salaries, employee benefits 104 Dividends to stockholders 9r.
Depreciation 5f.'etained in business 3g 1st Quarter
$.41 2nd Quarter
.45 3rd Quarter 45 4th Quarter
.45
$ 1.76
$ 13>/4
$ 1 17/8 147/8 127/8 167/8 1 3ys 161/2 143/4
TO Olli StOCkholdeirS John G. Hachl, Jr.
WilliamJ. Donlon Harnings for 1983 were $2.77 per share ofcom-mon stock, compared with S2.64 for 1982.
This 5% improvement resulted from a favor-able combination offactors, including an easing ofinflationary pressures, a 6% increase in total sales ofelectricity and rate adjustments effective in March 1982 and 1983. Hlectric sales to other utilitysystems climbed an impressive 34%.
Strict adherence to cost controls, productivity measures and innovation also contributed to our 1983 earnings performance. Natural gas sales decreased 6% because ofconservation by cus-tomers and competition withstable oil prices.
The N.Y. State Public Service Commission in March approved a 2.8% overall electric and gas tariffincrease and in late Aprilwe filed for a total 8.9% increase. Adecision on that request is ex-pected from the PSC in March 1984. As in previ-ous years, Niagara Mohawk's rates still are com-petitive when compared to those ofother utilities, both state and nationwide. This advan-tage has been an important influence in several major customer plant locations and expansions on our lines during the year.
Our service area is making a recovery from a very serious recession. Signs ofeconomic revival and technological transition are growing more pronounced as Upstate New York enters the mid-1980s, proof ofthe region's strength and resilience.
On February 9, 1984, Long Island Lighting Company, 18% owner in the Nine MilePoint Nuclear Unit No. 2 project, indicated itwillno longer fund its ownership share due to its own financial difficulties. This new development, to-gether with the multitude ofother recent nuclear-related news events, has caused uncer-tainties in the financial community which have had an adverse impact on our securities. We are certainly concerned about the dramatic drop in the market price ofour common stock shares and the reduction in our credit rating, which
nevertheless remains investment grade. In our view, these results do not fullytake into account our otherwise strong financial health.
'~Vithour partners in the project, we are exam-ining the alternatives relative to the funding of LILCO's share. Further, we are working dili-gently with our state government as we seek to shape the most feasible solutions. In the mean-time, Niagara Mohawk willtemporarily advance the shortfall in funding to allow construction to proceed unimpeded. Aplanned overall project cost re-estimate based on progress to date, which willinclude a re-assessment ofthe quan-tityofmaterial and labor hours necessary for completion ofthe unit, is currently under way and expected to be completed in the second quarter of 1984. The Company does not pres-ently expect the total project cost re-estimate to vary significantly from the $4.6-billion target completion cost established by the PSC in early 1982. Nor do we believe that the actions of LILCOwillhave a significant impact on the Company's 1984 construction budget or the amount ofexternal financing currently planned.
Construction progress at Nine Mile2 con-tinued at a steady pace throughout 1983. This 1.08-million kilowattpower plant a vital ele-ment ofthe New YorkState Energy Master Plan is four-fifthscomplete and has progressed from the bulk construction phase into the more exacting stage involvinginstallation ofcomplex controls and equipment and operating systems.
We continue to stress quality construction as we move toward completion ofthe project in late 1986. More detailed discussions ofthe Nine Mile2 project appear elsewhere in this report.
We are pleased to note the timely return of Nine Nile Point Nuclear Unit No.
1 to service in June, more than three months earlier than an-ticipated. An emergency drillat the site in Sep-tember was most successful and earned the Company high marks in evaluations by federal, state and local officials. Over its 15-year life, Nine Mile 1 production has saved consumers
$ 1.8-billion compared to the equivalent ofoil-fired generation at current oilprices.
The Company's external financing require-ments amounted to $575 millionin 1983 and are estimated at $500 millionin 1984 to fund our construction programs and to refund matur-ing securities.
In 1983, the Board ofDirectors declared a common stock dividend increase, to an an-nualized rate of $ 1.92 per share from the previ-ous $ 1.80. This increase reflects our commit-ment to provide a fair return to our existing shareholders and to enhance the attractiveness ofour securities as we compete for new capital in the financial markets.
The year also saw tangible advances in our corporate strategic planning process, an ongoing activity under the direction ofsenior executives and selected management people. Basically, their mission as a team is to strengthen the Company's abilities to cope successfully with all challenges we face in forthcoming years.
Our warmest regards and sincerest gratitude go to our stockholders and employees for their continuing loyalty and support during 1983 and through the years ahead.
John G. Hachl, Jr.
Chairman ofthe Board and Chief Executive OfHccr XvilliamJ. Donlon President February 24, 1984
Ayear of momeniurxx The past year was among the most eventful and productive ever experienced at our Nine Mile Point nuclear facilities.
Constant momentum prevailed throughout the Lake Ontario complex as Unit No. 1 was brought back on line and as construction ofthe adjacent Unit No. 2 continued at fullpace.
0 The 610,000-kilowatt Unit No. 1 returned to service inJune, a fullthree months ahead of schedule, after more than a year's shutdown.
During the outage, resourceful NM engineers, operating staff and the primary contractor applied highly specialized and automated machining and welding techniques, installing a new grade ofcorrosion-resistant stainless steel pipe. The same piping willbe employed at Unit No. 2. The U.S. Nuclear Regulatory Commission described our performance during this outage as "exemplary." Over its seven months ofservice in 1983 alone, Unit No. 1 had gcncrated some 2.8 billionkilowatt-hours ofenergy and achieved capacity and availability factors of86.8% and 97.9%, respectively.
In late summer, thc second full-scale emergency exercise was conducted at Unit No.
1 and nearby Oswego, with federal, state and local government agencies and key NMperson-nel all taking an active part. The realistic, day-long drill,mandated by the Nuclear Regulatory Commission for continuing the plant's operating license, received favorable comments and posi-tive grades from all regulators and community leaders involved.
0 Atthc Unit No. 2 site, all major construction milestones were achieved on or ahead of schedule, with vital components ofthe control room, reactor building and 115,000-volt switch-yard installed by year end. Thc scope ofwork activity has begun to shift from finishing the plant's fundamental bulk structures to installing thc refined mechanical and clcctrical systems, controls, safeguards and miles ofpiping. The project's cost estimate announced in 1983 will be updated in thc second quarter of 1984.
Again in 1983, a series ofinquiries and dc-vclopments surrounding Unit No. 2 served only to further strengthen our dctcrmination to bring the project on line in late 1986. The future pub-lic need for this essential energy cornerstone was also underscored in thc 1983 New York State Energy Master Plan. Further, late in 1983 the State Supreme Court Appellate Division unanimously rejected an appeal designed by op-ponents to force abandonment ofthe project. In early November a thorough economic re-evaluation study ofthe project presented to the Public Service Commission and similar to previ-ous evaluations by NM and thc PSC Staff re-emphasized the economic advantages for thc more than nine millionconsumers ofthe unit's five participating utilitics.
Niagara Mohawk is agent for construction and operation and principal partner with 41% own-ership ofNine Mile 2. The other utilitypartners include Long Island Lighting Co., 18% (see page 19); NcwYorkState Electric &Gas Corp., 18%;
Rochester Gas and Electric Corp., 14% and Cen-tral Hudson Gas and Electric Corp., 9%.
0 The signing into law ofthe Federal Nuclear Waste Policy Act in early 1983 was applauded by Niagara Mohawk and all others in the utilityin-dustry. This long-overdue legislation sets a firm course for the permanent disposal ofnuclear waste well into the decades ahead and resolves a previously growing concern.
0 Plans were rcvcaled late in 1983 for a multi-purpose training center adjacent to the power plants on the Nine MilePoint shoreline. Con-struction ofthe two-story stone and concrete building began in late 1983, with completion and occupancy anticipated in late 1984. The center willbe used for instructing personnel as-signed to our nearby nuclear units and as a tech-nical support facilityin case ofan emergency at Nine MilePoint. Precise computerized control room replicas full-size teaching aids to simu-late Units 1 and 2willbe the center's main feature. The building willalso contain class-rooms, laboratories, an emergency operations center and administrative office. An estimated 1,500 employees at all lcvcls willundergo in-struction each year. We expect this new addi-tion to earn widespread recognition over the years as a nuclear professional education and training showcase.
0 In spring 1983, the first hydroelectric project, part ofour long-term plan to enlarge or build new waterpower installations, went into full commercial operation on the Oswego River. The 10,000-kilowatt Granby Hydro redevelopment in Fulton incorporates state-of-the-art hydro technology. Its two 5,000-kilowatt units more than double the output ofthe original turn-of-the-century generators. By the year end, Granby produced 20 millionkilowatt-hours ofcconomi-
Only a pa'r6al impression ofits size is apparent in this viewwithinthe cooling tower at Nine MilePoint. Heat from Nu-clear UnitNo. 2 willdissipate constantly through natural draft upward inside this 540-foot-high concrete cylinder.
I'
~ ' ~
cal energy for our consumers, the same amount ofpower generated by more than 35,000 barrels ofimported oil. The plant's projected lifetime is 60 years or more.
The year also saw solid construction progress at the Trenton Falls hydro renovation site on the West Canada Creek near Utica. By late fall, nearly a halfmile of 14-foot diameter piping and tunnel linkingthe dam and powerhouse werc in place.
Redevelopment ofthis 83-year-old waterpower landmark willraise its generating output from 24,000 kilowatts to 30,000 kilowatts upon com-pletion in 1988.
Further plans for a 15,500-kilowatt hydro station at Glen Park on the Black River west of Watcrtown were approved in 1983 by the Fed-eral Energy Regulatory Commission (FERC).
However, extreme environmental stipulations in the license could well outweigh the economic and power reliabilitymerits justifyingsuch an undertaking by thc Company. Accordingly, we are reassessing the Glen Park proposal.
Cl Niagara Mohawk's non-regulated, wholly owned subsidiary, Hydra-Co Enterprises, Inc., is moving ahead in joint ventures with three inde-pendent companies for development ofsites on Upstate NcwYork watcrways. Hydra-Co and these firms willown and co-manage all phases of planning, construction and operation ofseven small hydro projects by 1987. At the same time, Hydra-Co is pursuing fossil-fired co-generation projects as well as further waterpower part-nerships.
During the year, a geothermal property in Idaho was acquired by Hydra-Co for a proposed 5,000-kilowatt station using 300.degree water as a power source. This cntails selling thc energy to a local utilitywhen the station begins service in carly 1985.
ELECTRICITYGENERATED AND PURCMASED BYTYPE OF FUEL, 1983 Hydro 29/o Various sources 25%
Coal 21%
OII 11%
Nuclear 9%
Natural gas 5%
Apivotal decision in September by the FERC on hydro relicensing was welcomed by Niagara Mohawk and other U.S. investor-owned utilitics.
The Commission reversed a 1980 decision based on a 1920 provision givingpreference to government-owned entities when licenses for hydro plants come up for renewal. In effect, the 1980 FERC decision awarded a utilityowned and-operated hydro project to a governmental entity when the utility's term expired. With 35 of83 Niagara Mohawk hydro installations of many years up for relicensing through 1993, the Company viewed this as a threat to both our consumers and stockholders. While the recent interpretation is currently under appeal in the courts, we arc seeking Congressional action in 1984 to confirm FERC's decision, removing any further threat ofcapture to our long-standing hydroelectric resources.
0 Atour fossil-fired power stations, there were a number ofproductive accomplishments in 1983. Improvements made at coal-fueled units."'ncreased their total power generation capability over 1982. Further, Niagara Mohawk's standing for system heat rate (BTU/KW-HR)performance advanced from 47th to 28th in just one year, according to the annual survey ofthe 100 largest U.S. utilities published byLleelricLigJ>tand Power in 1983.
CI Looking ahead at power transmission and de-liveryin the Niagara Mohawk System and with neighboring utiliticsand energy networks, an automated and computerized master control center, under construction since 1982 in Syra-cuse, willserve as the heart ofour planned new Energy Managcmcnt System (EMS). While the advanced EMS concept, applying space satellites and fiber optics for communication purposes, willnot sce fullimplementation until the early 1990's, the ncw control center is slated for 1985 operation, replacing older System and Central Region power control operations. Employee occupancy ofthe modern two-story brick struc-ture willbegin in fall 1984, with computer hardware, transmission map boards and asso-ciated electronic equipment arriving early in 1985 for installation.
Contracts with neighboring Canadian electric power producers to obtain low-cost energy for Niagara Mohawk customers proved beneficial throughout another year. We shall continue to import 400,000 kilowatts ofmainly coal-
Welder strikes arc on strut innew steel penstock installed at Trenton Falls Hydro Station on West Canada Creek.
Renovation ofoctogenarian waterpower landmark willboost capacity by one-fourth to 30,000 kilowatts.
Rese +eb-on technology's cutting edge generated energy from Ontario Hydro under an agreement that extends through December 1986, withprovision for extension to December 1992. The present cost is 3.3 cents per kilowatt-hourabout halfthat ofoil-generated electricity. At the same time, steps were taken to increase an interruptible energy contract with Hydro Quebec from the previous 120,000 kilo-matts to 240,000 kilowatts. This solely hydro-electric energy willbe brought across the border from the Province ofQuebec to reduce the use ofmore expensive fossil fuels in our Sys-tem. These imports from Ontario and Quebec willsave our consumers many millions ofdollars through the 1980's.
0 Transmission system expansion consisted primarilyofplanning and constructing three vital circuits during the year. The halfway mark was reached in construction ofa 65-mile, 345,000-volt line to deliver energy from Nine MilePoint Unit No. 2 in Oswego County to Marcy Substation, near Utica. Work on a line of the same voltage extending nearly 10 miles from Unit No. 2 to Volney Substation, north ofSyra-cuse, is targeted for completion in early 1985.
The third project, also scheduled for 1985, is construction ofa 115-volt line through 30 miles ofrugged north-country terrain from Massena to Colton in St. Lawrence County. That linkwill serve as the main carrier ofimported Hydro
. Quebec pomer into our System. Each ofthese transmission additions is being built"in-house" by a work force made up solely ofNiagara Mohawk employees.
0 In carly autumn, Theodore Barry K Associates, an independent consulting firm, was selected by the Public Service Commission to perform a management study ofNiagara Mohawk. The review should require about eight months and is similar to mandated audits ofall the state's utilities conducted under Nem York 1am. We shall cooperate fullywith the project and look forward to any recommendations.
We embarked upon our second decade of creative energy research in 1983.
In 1983 alone, more than $36 millionin cost savings for our customers resulted directly from new and improved state-of-the-art methods de-veloped in various ventures. Similar reductions projected in 1984 willalso have positive impact on consumers'ills.
0 Technology at its highest was displayed by NM researchers in mid-year in a first-ever noise cancellation experiment that attracted interna-tional attention. In this scientific breakthrough, noise was successfully deployed to eliminate of-fending noise, a problem at some electric instal-lations. For the first time, combining sophisti-cated nem electronics mith arrays ofmicro-phones and speakers, the unwanted humming of a transformer was electronically processed and projected back to the source, simultaneously cancelling the noise in all directions.
Another RKDfirst by NM in 1983 was the laboratory creation ofa safe, environmentally harmless method ofdestroying toxic PCBs in oil used for cooling electric equipment. Our Re-search Department has applied for a patent in a process which blends PCB-contaminated oil with newly developed chemical components to yield a non-toxic chloride. In partnership with a Central New Yorktechnical engineering firm, NMplans to construct a small pilotplant to vali-date the process. Ifsuccessful, a large process plant millbe built, capable ofrecycling millions ofgallons ofoilyearly, with substantial dollar savings.
0 Foremost among Niagara Mohawk's $ 144.1 millionfive-year research commitment is partic-ipation in an advanced Flue Gas Desulfurization (FGD) prototype that went into test operation in the spring on a 100,000-kilowatt unit at our coal-fired Huntley Stcam Station near Buffalo. A cooperative venture costing up to $61 million, with NM's investment at $7.2 million,this proj-ect proved in 1983 that low-cost, high-sulfur Eastern coal can be burned at large power sta-tions withvirtuallyno effect on air, land or water quality.
The FGD unit removes 90 percent ofsulfur dioxide gas from stack emissions, converting the gas into a high-grade elemental sulfur as the sole by-product. Presently, the sulfur produced by the demonstrator is being sold to a Western New York chemical firmforprocessing and ultimate use foragricultural, community water-
Something extraterrestrial is suggested inview across vast interior ofnew rad-waste building at Nine MilePoint Nu-clear UnitNo. 1. Crane in distance travels along rails on walls to move plant's low-level radioactive wastes.
tr c w w
o e
purification and varied manufacturing purposes.
The FGD project's far-reaching pollution-control and environmental implications have earned it nationwide interest. As host utility,Niagara Mohawk is the manager. Frincipal sponsor is the Empire State Electric Energy Research Corp.
(ESEERCO), in partnership with other utilities and federal and state agencies. The demonstra-tion willcontinue through the mid-1980's.
H Late in 1983, NM announced a two-year ex-periment to convert flyash trapped by pollution controls at coal-fired power plants into efFicient, low-cost insulation for homes and other struc-tures. The Company is sponsoring and managing a pilotplant to recycle the gray, gritty ash into a marketable fiber material similar to conventional fiberglass "batts". The project promises to elimi-nate the considerable expense and environmen-
Commitment to setme tal problems ofthe present practice ofhandling large bulk quantities ofthis waste for disposal at diminishing landfillsites. Testing ofthe insula-tion product, marketing and sales studies are a part ofthe program.
0 More than a decade ofpioneering research activitywith low-temperature fuel cells, born of the U.S. space program, willadvance to the field phase in early 1984. NM and other utilities, workingwith United Technologies Corp., have sponsored efforts leading up to installation and tests ofa 4,800-kilowatt prototype fuel cell adja-cent to an oil-firedNew YorkCitypower station.
Similar in appearance to large batteries, but re-quiring no charging, these futuristic devices op-erate on lighthydrocarbon fuels without noise, pollution or vibration. Plans call for Niagara Mohawk to start its own trials in 1986, with the largest fuel cell ever built11,000 kilowatts-to be installed at one ofour generation sites. We willdevote extensive study to this attractive form ofsupplemental power generation well into the 1990's.
0 The Adirondack region in Niagara Mohawk's service area, a center for widespread concern over acid deposition, willbe the focus ofan NM-supported water-quality and fisherics study to start in spring 1984. Besides our role as host utilityin a joint three-year program, we are chairing the project's management committee.
This is the fourth scientific effort in the Adiron-dacks by Niagara Mohawk with other utilities and government agencies to better understand the acid rain phenomenon.
0 In autumn, a new magazine was co-produced and issued by our research and corporate com-munications staffs to promote practical applica-tion ofour research accomplishments. Next Generation, a semi-technical journal, is issued periodically to engineers, energy research cen-ters, technical educators, college and university libraries, manufacturers and others with access to the marketplace.
Thc resounding readership response to the premier edition confirmed its effectivenes as a two-way communications bridge between Niagara Mohawk and these individuals and organizations.
The past year has sharpened Niagara Mohawk's awareness ofdramatic economic and industrial transformation taking place in our service terri-tory and the entire Northeast as well.
No longer do the traditional heavy industries steel and automotive are leading examples upon which thousands relied for their liveli-hood, appear as Upstate New York's basic economic backbone. Pronounced shifts from these and other "smokestack" industries to manufacturing and commerce in the categories ofhigh technology, computer and related software, electronic information and services, are altering the economic complexion ofour service area. Revitalized employmcnt and mar-ket horizons, with attractive new investment opportunities, arc emerging in this transition.
0 Closely tracking all economic trends, Niagara Mohawk has strengthened its commitment to attracting and helping to expand business and industry in the region served. Our Economic Development Department has undertaken a nationwide "Discover the State ofNiagara Mohawk" communications campaign. This promotional effor is geared to acquainting U.S.
business and industrial leaders with the area's natural and energy resources, its quality work force and many other diverse assets available for new plant investment, profitpotential and, in particular, hi-tech and automation opportunities.
This concerted drive alone prompted hun-dreds ofactive inquiries to Niagara Mohawk in 1983, and each was followed up individuallyby our Economic Development staff. Thc staff directly assisted 75 businesses and local com-munities with development and expansion ac-tivities, while confidence in Upstate New York was further demonstrated by announced plans for the addition ofone millionsquare feet of industrial and business space during the year.
Such ongoing strategies by the Company to per-form plant location studies and provide the latest information on market, raw materials, in-dustrial sites, labor and available financing are being intcnsiflied to meet the economic chal-lenges ofthe 1980's.
0 Services and supportive functions for con-sumers received more attention and emphasis than ever in 1983. Several were either cxpandcd or undertaken for the first time. Asampling of programs follows:
~ Home Insulation and Energy Conservation Analysis. Through "Operation Sunflake", more
Thrusting skyward nearly 200 feet, tower for345,000-volt transmission line extending from Oswego County to MohawkValleyis a study in steel. Line willdeliver power from Nine MilePoint to Eastern energy systems.
MONTHLYRESIDENTIALELECTRIC COST FOR 500 KILOWATT-HOURS New YorkCity NYState Avg. (not including NM)'56.66
$78.19 Boston, MA Newark, NJ Philadelphia, PA
$55.30
, $5375
, $50.13 Hartford, CT
$47.'43 Cleveland, OH
$41.01 National Avg.-
$38.10 Los Angeles, CA
$37.43 Portland, M
$35.89 Niagara Mohawk'$32.26 Includes fuel and PASNY credit adjustments as applicable.
'NM Rate Oepartment as of 12-1.83
- '6.6.I. report with rates elfective 7.1-83 Allothers supplied by local utilities, rates effective 12-1.83.
than 18,000 consumers received free cus-tomized home energy audits during the year.
Financial assistance and low-interest loans from lending institutions totaled 82.2 million in 1983 for qualified persons to help imple-ment conservation measures such as insula-tion and storm windows.
~ Energy Conservation Bank. Aspecial program for the needy and senior citizens in coopera-tion with county offices ofthe aging through-out our service area. Special grants and loan-principal reductions of $870,000 were offered to NM customers through the State Energy Office and administered by the Company in connection with our program ofenergy audits.
~ Home Energy Level Payment Plan. Designed to help consumers manage winter's higher energy costs. More than 122,000 customers now have their estimated annual costs divided into 12 level payments.'
Deferred Payment Plan. For customers who have severe financial problems. Allowsfor a combination ofdown payment and as many as 48 equal monthly payments to clear the balance.
Closely allied with energy conservation and consumer relations, the second annual Summer
'IVeatherization Program generated 121 jobs for inner-city youngsters and senior citizens who were specially trained to winterize homes ofthe elderly and disadvantaged. Sponsored by Niagara Mohawk in conjunction with many local com-munity agencies across the System, the program resulted in weatherizing some 1,500 low-income residences in our service area.
Q To keep the Company informed as to what consumers are thinking about NM, a residential customer survey was conducted across the ser-vice area in 1983 by an independent opinion-research consulting firm. Findings showed im-provement over data gathered in a similar 1982 survey. Consumers also gave NM an 89 percent favorable rating for courtesy, 85 percent for ser-vice reliabilityand 83 percent for knowledgea-bility.We attribute much ofthis improvement to our consumer services programs and our con-tinuing "1IVe're with you!" communications campaign, launched by Public AC'airs and Corpo-rate Communications in 1982 to assure con-sumers ofour willingness to assist them with their personal energy problems and concerns.
Q Niagara Mohawk's Educational Services Pro-gram, firstformed in 1972, established a new performance record in 1983. Aseven-member Educational Advisory Council, comprised ofpro-fessional teachers and school administrators within the NMservice area, was organized dur-ing the year to make recommendations and re-view instructional materials provided by the Company to schools. More that 78,000 students viewed films loaned by our circulating film library while another 332,000 received NM energy publications in 1983.
The Energy Information Center at Nine Mile Point has also been undergoing renewal and re-vitalization. Jointly sponsored by Niagara Mohawk and the New YorkPower Authority, the Center is reaching out to area schools, organiza-tions and the general public, offering audiences factual information on nuclear energy, fossil generation and alternate energy sources. The year 1983 saw attendance at the Center in-creased by 20 percent over 1982. Since 1967, when the facilityfirst opened, it has served more than a halfmillionvisitors from across the United States and around the world.
~
~
High-tech Qrms are finding Upstate New Yorkthe ideal home. American Com-puter Assembly, Inc., manufacturer ofprinted circuitboards, settled in Ogdensburg in 1982 and employs a skilled workforce of150.
- .~~.~P' I
Q:s-,-
(a1 I
Wy I I
'E (2
People in the iream*
An Investor and Financial Relations Department was established in 1983 in response to clear signals from stockholders and finance profes-sionals oftheir particular need for a specialized source ofinformation on Niagara Mohawk.
The new, Syracuse-based Department is re-sponsible for timely investor and financial com--
munications while also working closely'wjth NM senior officers in analyzing and implementing major financing strategies and programs. Its main objective is to develop, through com-prehensive and up-to-date communications, a
well-informed financial and inv'estor community.
Staff assignmcnts include, in addition to respond-ing to inquiries, involvement in such publica-tions as iriterimreports, an In-the-Know bulletin for stockholders and the quartcrlyNMKDigest, a newsletter for security analysts and others in the financial community.
The new Department is scheduling prcscnta-tions to analysts and broker organizations and stepping-up direct personal contacts with in-stitutional investors, rating agencies and others in the field offinance. These activities are founded on the belief that an informed securities market willhelp insure that a consistently fair value willbe placed on NMsecurities. Stock-holders are encouraged to contact the Depart-ment for information about Niagara Mohawk's programs and plans.
Q Participation in the Company's Dividend Reinvestment and Common Stock Purchase Plan was more active than ever in 1983, with mem-bers representing more than 32 percent ofNM's shareholders at the year end.
The Plan offers significant tax incentives and investment opportunities and provides the Company with a valued source ofcapital, generating some
$ 51 millionand representing 30 percent ofcommon equity requirements in 1983. Recent improvements allowstockholders to join whose shares are held by certain brokers or nominees. Further, participants may elect to partially reinvest dividends in the Company's shares. These new fcaturcs permit participants to manage and maximize their investments more effectivel.
Since thc Plan qualifies for tax-deferred treat-ment under existing tax legislation, members are allowed to exclude up to $750 ($ 1,500 for a joint return) ofdividend income for federal in-come tax purposes on rcinvested dividends.
When these shares are sold, the dividends ex-eluded from income may be taxed as a capital gain, rather than ordinary income, ifthe shares were held for a year or morc.
0 Our work force totaled about 10,600 at the year end. Approximately 8100 or 76 percent of our employees arc members of 12 locals ofthe International Brotherhood ofElectrical Workers (AFL-CIO)which constitute System Council U-11. Our two-year collective bargaining agree-ment expires on May 31, 1984 and negotiations for a new agreement commenced early in 1984.
About 7500 or 79 percent ofall eligible cmployces subscribe to the Employee Savings Fund Plan, in which 2 to 6 percent ofwages werc allocated for common stock or U.S. Gov-ernment Bonds in 1983. At the year-end 1983, the Plan held about 10.6 millionshares or 10 percent ofthc outstanding comon stock.
0 Starting January 1984, the Employee Savings Fund Plan for non-represented employees was modified to take advantage ofInternal Revenue Service provisions which willencourage retire-ment savings and achieve other long-term finan-cial goals. The improved version allows con-tributions ofup to 10 percent ofgross pay using pre-tax dollars. Moreocvcr, itnow offers two added investment options, including a fixed in-come fund and an index fund ofmixed common stocks. The attractive new Plan was greeted en-thusiastically by cligiblc employees.
~
~
Heart ofour growing computer and telecommunications functions is this new Network Control Center console, latest in state-of-the-art. Compact unit was installed in 1983 to manage complex data and information systems.
ggTROL CERATE"
~~yyP44 +
~ ~ ~ ~ ~ ~ y ~ ~
4+4'
~ ~
~ ~ ~ ~ s ~ o ~
P ~
1 1 1 1 1I1, l ill lift t~r r il'I"("i>
~~
EIF"
~Ilk gi 1
.vy flI
~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ I ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~
0 ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~
w
%~A~ pe y'g p f
- qP
.r +.
1~
0-
Market for the registrant's common stock and related security'holder matteis 1st Quarter
$.45 2nd Quarter
.48 3rd Quarter
.48 4th Quarter
.48
$1.89 1982
$17~/e
$15%
177/e 16'/8 173k 16 18~/g 15 ~/4 1st Quarter
$.41
$133/4
$11r/8 2nd Quarter
.45 147/s 12'/8 3rd Quarter
.45 16'/s 13~/8 4th Quarter
.45 16~/z 143/4
$1.76 Preferred and common stock div-idends.were paid on March 31, June 30, September 30 and December
- 31. The Company presently estimates that all of the March 1983 common dividend is taxable and between 25-35/o of the re-maining 1983 and about 30'/o of the The Com'pany's common stock and cer-tain of its preferred series are listed on the New York Stock Exchange.
The common stock is also traded on the Boston, Cincinnati, Midwest, Pacific and Philadelphia stock exchanges.
The ticker symbol is "NMK".
The table below shows dividends per share for our common stock and quoted market prices:
Dividend paid Price range 1983 per share High Low 1982 common stock dividends are a re-turn of capital and therefore are not taxable as dividend income for income tax purposes.
The remaining percen-tage of common dividends and 100/o of preferred stock dividends are taxable as dividend income.
While the Company intends to con-tinue the practice of paying cash div-idends quarterly, declarations of future dividends are necessarily dependent upon future earnings, financial re-quirements and other factors, including restrictions in governing instruments.
The holders of common stock are en-titled to one vote per share and may cumulate their votes for the election of Directors. Whenever dividends of pre-ferred stock are in default in an amount equivalent to four full quarterly div-idends and thereafter until all dividends thereon are paid or declared and set aside for payment, the holders of such stock can elect a majority of the Board of Directors. Whenever dividends on any issued preference stock are in de-fault in an amount equivalent to six full quarterly dividends and thereafter until all dividends thereon are paid or de-clared and set apart for payment, the holders of such stock can elect two members of the Board of Directors. No such dividends are now in arrears.
Upon any dissolution, liquidation or winding up of the Company's business, the holders of common stock are enti-tled to receive pro rata all of the Com-pany's assets remaining and available for distribution after the full amounts to which holders of preferred and prefer-ence stock are entitled have been satisfied.
The indenture securing the Com-pany's mortgage debt provides that surplus shall be reserved and held un-available for the payment of dividends on common stock to the extent that ex-penditures for maintenance and repairs plus provisions for depreciation do not equal 2.25'/o of depreciable property as defined. Such provisions have never re-stricted the Company's surplus.
At year end, over 209,000 stock-holders owned common shares of Niagara Mohawk and 10,000 held pre-ferred and preference stock. The chart below summarizes common stock-holder ownership by size of holding:
Size of holding Total Total shares (Shares) stockholders held
1 to 99 57,241 1,894,436 100 to 999 142,690 34,767,328 1,000 or more 9,457 67,348,239 209,388 104,010,003 Management's discussion and analysis of financial condition and results of operations Results of operations. Earnings in 1983 were $2.77 per share, up $.13 from 1982,
$.42 above 1981 and $.90 above 1980 earnings, with fewer shares outstanding in each of the earlier years.
The improvement in the Company's earnings per share for 1983 over 1982 resulted primarily from higher electric sales, rate relief granted in March 1982 and 1983 and management's efforts to control costs wherever possible.
Elec-tric and gas revenues increased 8.8%%d and 14.2'/o, respectively, from the prior year. The increase in electric revenues is principally due to higher rates and in-creased sales to other electric systems.
Gas revenues increased primarily from recovery of increased purchased gas costs through the gas adjustment clause.
- However, operation and 16 maintenance
- expenses, including de-preciation and amortization, increased 10/0, Federal income and other taxes increased 8'/0 and interest charges were 10'/o higher, reducing the impact of the increase in revenues.
EARNED RATE OF RETURN ON COMMON EQUITY 14 7o/
15.(P/o 13 So/o 11.4/o 10 So/
1979 1980 1981 1982 1983 The Company's rate of return on common equity rose to 15.0'/o in 1983 from 14.7'/0 in 1982 and 13.5'/o in 1981.
This earned return on common'equity reflects an improvement from prior years and compares favorably to the 15.4'/o currently approved by the New York State Public Service Commission (PSC) for the rate year ending March 1984.
The followingdiscussion and analysis highlights items having a significant ef-fect on operations during the three-year period ended December 31, 1983, but may not be indicative of future opera-tions or earnings. It should be read in conjunction with the Notes to Consoli-dated Financial Statements and other financial and statistical information ap-pearing elsewhere in this report.
~
~
4 Electric revenues increased
$630.3 million or 45.2% over the three-year period.
This increase is largely attributable to increased base rates, recovery of increased fuel and purchased power costs and increased sales to other electric systems, as indicated in the table below:
Increase (decrease) from prior year ln millionsofdollars 1983 1982 1981 Total ELECTRIC SALES Millionsof Kw.-hrs.
34,732 33,315 32 566 32,690 32 640 Increase in base rates Fuel and purchased power cost increases Sales to ultimate consumers............
Sales to other electric systems..........
Miscellaneous operating revenues......
$ 68.5
$128.8
$115.2 2.6 (1.9) 141.5 21.0 (21.9) 27.1 63.7 34.2 30.9 7.3 1.5 11.8
$163.1
$140.7
$326.5
$312.5 142.2 26.2 128.8 20.6
$630.3 Class of service Electric kilowatt-hour sales were 34.7 billion in 1983, an increase of 6.4% from 1982, reflecting the effects of the improved economy in the Company's service area and increased sales to other electric systems (see Electric and Gas Statistics Electric Sales appearing on page 36). Details of the changes in our electric rev-enues and kilowatt-hour sales by customer group are highlighted in the table below:
1983
% Increase (decrease) from prioryear
%of
, Electqic 1983
- 1982 f1981 Reventes Revenues Sales Revenues Sales Revenues Sales 1979 1980 1981 1982 1983 GAS SALES Millionsof dekafherrns 109.8 1 09.7 103.2 966 Residential.......
Commercial......
Industrial.........
Municipal service 288%
82/o 1 2%
11 5%
P2%
195o/o 1 5%
32.6 4.8 0.6 8.7 (0.9) 24.8 0.6 21.8 3.7 4.8 (1.1)
(10.9) 24.9 (0.6) 1.8 4.5 (2.3) 11.6 (3.4) 15.2 (2.6) 1979 1980 1981 1982 1983 Total to ultimate consumers...........
85.0 5.7 2.3 6.9 (4.5) 22.9 0.4 Other electric systems...
11.6 37.1 34.3 24.9 35.4 29.0 6.5 Miscellaneous..........
3.4 12.0
2.5
24.8 Total
'1 P Q.P%
8.8%
6.4%
8.2%
(P.8)%
23.4%
P.9%
Gas revenues Increase (decrease) from prior year ln millionsofdollars 1983 1982 1981 Total Increase in base rates........
Purchased gas cost increases Gas sales....................
$ 10.3
$ 17.8
?9.2 74.1 (14.0) 10.4
$ 75.5
$102.3
$11.0
$ 39.1 4.8 158.1 31.3 27.7
$47.1
$224.9 Gas revenues increased
$224.9 million or 58.6% over the three-year period. As shown by the table below, this rise is primarily from increased costs of purchased gas which are recovered from customers through the purchased gas adjustment clause.
In summary, total operating revenues increased
$855.2 million, or 48.1% over the three-year period, largely represent-ing recoveries of higher energy and purchased gas costs through electric and gas adjustment clauses and in-creased rates.
TOTALELECTRIC ANDGAS OPERATING REVENUES Millionsof dollars 2.632 2,394 2,151
...:;4 "'
1,777 J
1,517 Class of service Residential Commercial..
Industrial....
Total to ultimate consumers.......
Other gas systems..
Miscellaneous.....
Total 1983
% Increase (decrease) from prioryear
%of Gas 1983 1982 1981 Revenues Revenues SaIes Revenues Sales Revenues SaIes 5Q.0%
14.9%
(8.'1)%
I9.1%
(1.3)%
6.1%
25.6 13.7 (6.1) 33.5 8.8 15.3 10.5 21.2 14.6 (1.1) 26.0 (3.0) 28.5 23.9 96.8 14.5 (5.9) 24.2 0.8 12.6 8.6 2.6 2.4 (8.7) 1 1.8 (18.7) 2.5 3.6 0.6 14.2
23.6
21.2 1PP Q%
14.2/o (6.Q)%
23.8%
(P.1)% 12.3%
8.3%
Gas sales were 103.2 milliondekatherms in 1983, a 6.0% decrease from 1982 (see Electric and Gas Statistics Gas Sales appearing on page 36). The decrease for 1983 reflects reduced sales in all classes of service, resulting from customer con-servation in response to rising gas prices, partly offset by colder weather, and competition with stabilized oil prices. Changes in gas revenues and dekatherm sales by customer group are detailed in the table below:
1979 1980 1981 1982 1983 On March 24, 1983, the PSC approved rate increases to provide the Company additional annual revenues of
$56,383,000 (3.3%) for electric and
$11,009,000 (1.6%) for natural gas.
These new rates became effective March 28, 1983. In March 1982, the PSC had approved rate increases providing additional annual revenues of
$142,519,000 (7.9%) for electric and
$17,143,000 (3.3%) for natural gas.
Further rate action, made necessary by the lingering effects of inflation, con-tinued relatively high financing costs 17
and the need to increase cash flow, was requested on April 29, 1983 when the Company filed for an annual increase of
$211.3 million, including $196.2 million (11.5/o) electric and $ 1 5.1 million (2.2/o) gas.
In December 1983, PSC Adminis-trative Law Judges recommended rate increases of $67.9 million (3.3'/o) electric and
$8.8 million (1.3%) gas or about 36'/o of the original request. The Com-pany and other parties have filed exceptions to many of the Judges'ec-ommendations.
The PSC's opinion is expected in March 1984 with new rates to be effective promptly thereafter.
Recent rate awards have not adequately provided for steadily in-creasing costs and the Company ex-pects to continue filingannual petitions for rate increases.
In 1983, electric fuel and purchased power costs increased to $883 million from $815 million in 1982 after having decreased from $840 million in 1981.
The major portion of the 1983 increase arose from a 7'/o increase in amounts generated and purchased to meet cus-tomer requirements.
Increased nuclear generation and low cost purchases from Ontario Hydro and Hydro Quebec enabled the Company to satisfy cus-tomer needs and still reduce generation from stations using higher cost oil and natural gas as fuel. Fuel and purchased power costs also increased as a result of unusually high fuel costs which were deferred in 1982 being recognized and recovered through the fuel adjustment clause in 1983 (see Electric and Gas Statistics Electricity Generated and Purchased appearing on page 36.)
AVERAGECOST OF ATON OF COAL ANDA BARREL OF OIL BURNED 7.44
$41.9 Ton of coal
$30,64
$29 6~$ 30.67
$23.72
$16.34 Barrel of oil 1979 1980 1981 1982 1983 Nine Mile Point Nuclear Station Unit No.
1 returned to service in June 1983 after having been out of service since March 1982 for replacement of recircu-lation piping. Since returning to service, the unit has operated at an 87'/o capac-ity factor and has generated 2.8 billion kilowatt-hours of electricity at a fuel cost averaging about one-sixth that of 18 fossil fuels. Nuclear fuel costs per kilo-watt hour of generation were reduced as a result of reduced fuel disposal costs as provided in the Nuclear Waste Policy Act of 1982 (see Note 10 of Notes to Consolidated Financial Statements).
The total cost of gas purchased, net of refunds from the Company's supplier, rose 15/o in 1983, 29%%d in 1982, and 6/o in 1981. These increases are primarily the result of gradual deregula-tion of gas prices at the wellhead. The Company's net cost per dekatherm pur-chased has increased to $4.06 in 1983 from $3.39 in 1982 and $2.64 in 1981.
Through the energy and purchased gas adjustment
- clauses, costs ot fuel, purchased power and gas purchased, above or below the levels allowed in ap-proved rate schedules, are billed or credited to customers.
The Company has filed revisions to its fuel adjustment clause consistent with PSC directives, which essentially provide for partial pass-through of fuel cost fluctuations from those forecast in rate proceedings with the. Company absorbing a specific portion of increases or retaining a por-tion of decreases to a maximum of $15 million (see Note 1 of Notes to Consoli-dated Financial Statements).
Other operation and maintenance ex-penses increased 10.4'/o in 1983, 11.3/o in 1982 and 16.8'/o in 1981, primarily as a result of increases in wages and as-sociated benefits and higher costs charged by suppliers. In June 1982, the Company entered a two-year labor agreement providing for increased wages of 9.5/o in the first year and 9.0%%d in the second year. The increase in other operation and maintenance ex-penses in 1981 was also attributable, in part, to the refueling of Nine Mile Point Nuclear Station Unit No. 1. The next re-fueling outage for this unit is presently scheduled for the spring ot 1984.
MAINTENANCEANDOTHER OPERATION EXPENSE Millionsof dollars 462.4 416.9 376.4 300.6 3223 Other operation 118 3 128 8 136.3 gg.g 100.4 Maintenance 1979 1980 1981 1982 1983 Depreciation and amortization ex-pense for 1983 increased,4.9'/o over 1982 principally from normal plant 211 188 243 1979 1980 1981 1982 1983 The $23.1 million increase in total Allowance for Funds Used During Con-struction (AFC) for 1983 results from in-creased overall levels of plant under construction, principally Nine Mile Point Nuclear Unit No. 2, partially offset by lower AFC rates.
The Company's revenues and costs of operation over the past three years show substantial increases in several
- respects, due primarily to the effect of general inflation and higher tuel costs.
The Company is especially sensitive to inflation because of the large amount of capital it must raise to finance its con-struction program and because its prices are regulated using a rate base that reflects the historical cost of utility plant. Inflation information in Note 12 of the Notes to Consolidated Financial Statements indicates the approximate effect of inflation on certain aspects of the Company's operations and financial position.
Financial position, liquidityand capital resources.
Financial resources pro-vided from operations consist of net in-come adjusted for non-cash
- expenses, such as depreciation, amortization of nuclear fuel and deferred income taxes, growth. During 1981, the Company con-verted its Albany Steam Station to burn natural gas as well as oil to enable utili-zation of lowest cost fuel supplies. The cost of this conversion (about
$7,900,000) was charged to deprecia-tion on an accelerated basis in 1981 and 1982.
Federal and foreign income taxes rose in 1983, 1982 and 1981 as a result of increased income, including an in-crease in the amounts on which de-ferred taxes are provided. The increase in taxes other than income taxes in these same thiee years is due princi-pally to higher property taxes resulting from property additions and higher state and local gross income taxes re-sulting from increased revenues.
TOTALTAXES INCLUDING INCOME TAXES Millionsof dollars 342 317
~
~
\\
and hon-cash income, such as AFC.
AFC represents the financing costs of the Company's construction program And is added to the cost of construction until such time as a capital project is
'completed, and is then recovered through depreciation included in rates charged to customers.
Internal funds from operations are insufficient to meet the Company"s capital requirements, therefore, large amounts of new capital from external sources are necessary.
External capital needs are first met through utilization ot short-term bor-rowing arrangements, including bank lines of credit and commercial paper.
These short-term borrowings are refi-nanced on a continuing basis through the issuance of securities, consisting of intermediate and long-term debt, pre-ferred and preference stock and com-mon stock.
Capital resources consisting of both internal and external sources are used to pay for the Company's construction program, working capital needs, matur-ing debt issues and sinking fund provi-sions on outstanding debt and pre-ferred stocks. Sources and uses of funds during the past three years are reported in the Consolidated Statement of Changes in Financial Position at page 23.
Capital needs.
During the period 1981-83, expenditures for construction and nuclear fuel, including related AFC and overheads capitalized, have in-creased from $457.4 million to $594.5 million to $691.5 million. Total capital requirements, including debt and pre-ferred stock redemptions and working capital, have also increased.
The 1984 estimate for construction additions and'uclear fuel, including AFC and over-heads capitalized, is $754 million. Debt and preferred stock retirements and other requirements will add approx-imately another $71 million to the Com-pany's capital requirements.
This upward trend in capital require-ments is a result ot increasing construc-tion expenditures and relatively high capital costs.
The principal project presently under construction is Nine Mile Point Unit No. 2 (Unit), scheduled for completion in late 1986. The Com-pany is a 41/o owner and had invested about $1.1 billion, including AFC and overheads capitalized, in the project through December 31, 1983. Expendi-tures for construction of this plant have averaged approximately 40% of total construction requirements during the period 1981-1983. During 1983, such expenditures were approximately 45%%d of requirements.
On February 9, 1984, the Long Island Lighting Company (LILCO), an 18/o owner of the Unit, notified the Company and the other Co-tenants of LILCO's intention to cease participation in the funding of the con-struction costs of the Unit and failed to make a required payment.
During the remainder of 1984, construction fund-ing for LILCO's 18/o interest in the plant is expected to average approximately $9 million per month. Various arrange-ments are being investigated for the funding of LILCO's remaining interest in the plant. On a temporary basis, the Company will advance funds as neces-sary for that portion of construction costs not being paid by LILCO. The Company does not believe that the ac-tions of LILCO will have a signiticant impact on the Company's 1984 con-struction budget or the amount of ex-ternal financing currently anticipated.
Future requirements for capital could be affected by changes in construction costs, inflation, financing costs, regula-tory requirements and other factors.
Liquidity and resources.
The Com-pany's long-term financial plan is de-signed to improve the percentage of in-ternal cash generation and to strengthen its capital structure. With regard to the latter, the proportion of long-term debt to total capitalization has decreased from 48.6/o at the end of 1980 to 45.3%%d at the end of 1983 while common equity as a percent of total capitalization has increased from 38.9/o to 42.1'/o during the same period. The Company will endeavor to turther strengthen these capitalization ratios in 1984. The trend in the percentage of in-ternally generated
- cash, however, has been less controllable. The PSC has not provided the necessary increases in cash flow to stabilize and enhance in-ternally generated funds. Thus, while overall levels of earnings have in-creased, a substantial portion of this in-crease represents non-cash earnings in the form of AFC. AFC for the year 1983 CAPITALIZATIONRATIOS Percent 12 8o/o 12 5o/o 12 9/o 11 So/o 12 6o/o
. Preferred..
37 5oj<
38.9/o 40 7o/o 41.0 /o 42 fo/o 1979 1980 1981 1982 1983 During 1983, the Company raised approximately
$575,000,000 through external
- sources, consisting of ANNUALEXTERNALFINANCING BYTYPE Millionsof dollars 583.1 Debt Common Preferred 424.9 346.0 Common equity 47 5/o 45 3O/
251.6 I
48.6'/0 46 40/
Long-term debt 306.9 1p 1 3 145.2 93.8 75.3 58.0 20.0 171,3 1979 1980 1981 1982 1983 1979 1980 1981 1982 1983 19 amounted to 43.6% of the balance available for common stock. The Com-pany has attempted to control costs where possible and has adopted strin-gent budgets for 1984 and beyond and will continue to file for appropriate rate improvements, including those which will increase cash flow in a timely and adequate manner.
During the period 1981-1983, the Company generated
$514,000,000 (35%%d of its construction requirements, excluding AFC) from internal sources, the remainder being funded through a mix of security issuances, bank and commercial paper borrowings. During
- 1983, the Company generated
$182,000,000 (32'/o of construction re-quirements, excluding AFC) from inter-nal sources.
The remainder was ob-tained initiallyfrom short-term bank and commercial paper borrowings (see Note 4 of Notes to Consolidated Financial Statements) which were later substan-tially refunded with permanent securi-ties or bank revolving credit borrow-ings.
SOURCE OF CAPITAL FOR CONSTRUCTION PROGRAM Millionsof dollars 573.7 4997
/
37oo 385.5 316 9 319 7 38 o 68/o 40/,
fnternalI 63o/-
62'/o 67/. ---6~/-
External 120.0
$200,000,000 of mortgage
- bonds,
$120,000,000 of preferred
- stock,
$83,900,000 of intermediate term bank revolving credit obligations, and
$171,269,000 of common stock from the issuance of 10,177,852 shares through a combination of public sales and its Div-idend Reinvestment, Employee Savings Fund and Employee Stock Ownership Plans. The Company also completed
$15,135,000 of lease financing. Approx-imately $210 millionof the total 1983 ex-ternal financing was used for debt and preferred stock refunding and retire-ment and reductions of short-term debt.
Of this amount,
$118.4 million repre-sented early redemption of certain high coupon debt in order to reduce interest costs.
External financing for 1984 is ex-pected to approximate
$500 million, excluding lease financing. The Com-
~ pany expects to secure the majority of I its capital needs from traditional financ-ing sources, however, it willcontinue to explore and utilize, as appropriate, other methods of financing. At De-cember 1983, construction related short-term debt was $41,763,000 and obligations under bankers acceptances for fuel oil inventory financing were
$43,000,000, for a total of $84,763,000.
In general, construction related short-term borrowings are refunded with permanent securities on a continu-ing basis. Bank credit arrangements of
$345 million, in addition to a $100 mil-lion Bankers Acceptance Facility Agreement, are available to the Com-pany to enhance flexibilityas to the type and timing of these security sales. Also, the Company expects to add $100 mil-lion of committed bank credit arrange-ments in early 1984.
During 1983, the unsecured debt limi-tation imposed by the Company's Char-ter was increased to $700 million. Earn-ings coverage of interest charges has been well in excess of mortgage inden-ture restrictions for the issuance of first mortgage bonds. Also, approximately
$1.1 billion 'of property is 'available to support the issuance of first mortgage bonds.
In general, the Company has a rela-tively strong capital structure, a high degree of short and intermediate term borrowing capability and a degree of ll
~
~
1f flexibilityin its access to the pern>anent capital markets. The Company is, how-ever, unable to predict the ultimate im-pact of the actions of LILCO on the Company's flexibilityin accessing vari-ous permanent capital markets.
In addition, in recent months, several utilities have made announcements concerning the licensing and/or cancel-lation of unfinished nuclear plants which, absent regulatory recognition, could result in substantial write-offs and dividend reductions. Also, regulatory agencies nationwide are reviewing vari-ous plans for the moderation of the rate impact of placing major generating facilities in service. These factors have had an adverse impact on utility stock prices and bond ratings, including those of the Company. Additionally, the cost and availability of external sources of funds will be affected by the mainte-jnance of',adequate credit ratings 'and
'eneral conditions in the financial mar-kets. Adverse changes in any of these
- factors could have an effect on the Company's ability to fullyimplement its intended construction and financing programs.
Report of management The consolidated financial statements of Niagara Mohawk Power Corporation and subsidiary companies were prepared by and are the responsibility of management.
Financial infor-mation contained elsewhere in this Annual Report is consistent with that in the financial statements.
To meet its responsibilities with respect to financial informa-tion, management maintains and enforces a system of internal accounting controls, which is designed to provide reasonable assurance, on a cost effective basis, as to the integrity, objec-tivity and reliability of the financial records and protection of assets.
This system includes communication through written policies and procedures, an organizational structure that pro-vides for appropriate division of responsibility and the training of personnel. This system is also tested by a comprehensive internal audit program. In addition, the Company has a Code of Conduct which requires all employees to maintain the highest level of ethical standards and requires key management employees to formally affirm their compliance with the Code.
The financial statements have been examined by Price Waterhouse, the Company's independent accountants, in'ccordance with generally accepted auditing standards.
As part of their examination, they made a study and evaluation of the Company's system of internal accounting control. The pur-pose of such study was to establish a basis for reliance thereon in determining the nature, timing and extent of other auditing procedures that were necessary for expressing an opinion as to whether the financial statements are presented fairly. Their examination resulted in the expression of their opinion which follows this report. The independent accountants'xamination does not limit in any way management's responsibility for the fair presentation of the financial statements and all other in-formation, whether audited or unaudited, in this Annual Report.
20 The Audit Committee of the Board of Directors, consisting of three directors who are not employees, meets regularly with management, internal auditors and Price Waterhouse to review and discuss internal accounting controls, audit examinations and financial reporting matters.
Price Waterhouse and the Company's internal auditors have free access to meet indi-vidually with the Audit Committee at any time, without man-agement present.
Report of independent accountants To the Stockholders and the Board of Directors of Niagara Mohawk Power Corporation In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income and retained earnings and of changes in financial position present fairlythe financial position of Niagara Mohawk Power Corpora-tion and its subsidiaries at December 31, 1983 and 1982, and the results of their operations and the changes in their finan-cial position for each of the three years in the period ended December 31, 1983, in conformity with generally accepted ac-counting principles consistently applied. Our examinations of these statements were made in accordance with generally ac-cepted auditing standards and accordingly included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.
Syracuse, New York January 25, 1984, except as to Note 10 which is as of February 9, 1984
~
~
Consolidate'd statement of income and retained earnings NIAGARAMOHAWKPOWER CORPORATION ANDSUBSIDIARYCOMPANIES Operating revenues:
Electric Gas For the year ended December 31 ~
1983
$2,023,728 608,587 2,632,315 In thousands of dollars 1982
$1,860,649 533,122 2,393,771 1981
$1,719,933 430,785 2,150,718 Operating expenses:
Operation:
Fuel forelectric generation Electricity purchased Gas purchased Other operation expenses Maintenance Depreciation and amortization (Note 2).....
Federal and foreign income taxes (Note 9)..
Othertaxes............................
Operating income Other Income and deductions:
Allowance for other funds used during construction (Note 1)
Federal income tax credits (Note 1)
Other items (net)
Income before interest charges Interest charges:
Interest on long-term debt Other interest Allowance for borrowed funds used during construction (Note 1)
. Net Income Dividends on preferred stock Balance available for common stock Dividends on common stock Retained earnings forthe year Retained earnings at beginning of year..
Retained earnings at end of year 501,328 381,703 432,898 326,057 136,338 127,390 117,089 254,797 2,277,600 354,715 85I350 31,511 9,994 126,855 481,570 189,006 12,598 (32,443) 169,161 312,409 42,109 270,300 185,642 84,658 566,023 650,681 502,491 312,451 377,596 290,091 128,801 121,422 109,519 235,615 2,077,986 315,785 69,195 26,390 10,557 106,142 421,927 156,133 22,801 (25,541) 153,393 268,534 37,586 230,948 153,681 77,267 488,756 566,023 582,033 257,788 292,863 258,124 118,331 102,536 53,043 214,624 1,879,342 271,376 48,281 19,548 9,598 77,427 348,803 131,146 20,623 (23,609) 128,160 220,643 34,285 186,358 127,781 58,577 430,179 488,756 Average number of shares of common stock outstanding (in thousands)
Balance available per average share of common stock Dividends per average share of common stock
() Denotes deduction 97,685 2.77 1.89 87,340 2.64 1.76 79,204 2.35 1.61 21
Consolidated balance sheet NIAGARAMOHAWKPOWER CORPORATION ANDSUBSIDIARYCOMPANIES At December 31, ln thousands ol dollars 1983 1982 22 ASSETS Utilityplant, at original cost (Notes 1 and 3)
Less accumulated depreciation and amortization (Note 2)
Net utilityplant Other property and Investments (Note 7)
Current assets:
Cash, including time deposits of $4,521'and $4,216, respectively (Note 4)
Accounts receivable (less allowance for doubtful accounts of $3,600 and $3,200, respectively)
Materials and supplies, at average cost:
Coal and oil for production of electricity.
Other Prepayments Deferred debits:
Unamortized debt expense Deferred recoverable energy costs Extraordinary property losses(Note10)
Unamortized debt reacquisition expense(Note 7)
Other CAPITALIZATIONAND LIABILITIES Capitalization (Note 7):
Common stockholders'quity:
Common stock, issued 104,010,003 and 93,832,151 shares, respectively Capital stock premium and expense Retained earnings.
Non-redeemable preferred stock Redeemable preferred stock Long-term debt Total capitalization Current liabilities:
Short-term debt (Note 4)
Long-term debt due within one year Sinking fund requirements on redeemable preferred and preference stock (Note 7)
Accounts payable Payable on outstanding bank checks Customers'eposits Accrued taxes Accrued interest Accrued vacation pay Gas supplier refunds payable to customers..
Other Deferred credits:
Income tax refunds (Note 9)
Mandated refunds to customers (Note 9)
Accumulated deferred Federal income taxes (Note 9)
Other Commitments and contingencies (Notes 3 and 10)
() Denotes deduction
$6,165,711 1,486,196 4,679,515 85,602 31,199 274,076 95,910 56,254 17,498 474,937 22,109 25,733 14,875 22,421 32,380 117,518
$5,357,572 104,010 1,174,382 650,681 1,929>073 210,000 368,474 2,048,548 4,556,095 84,763 30,152 11,950 185,252 76,471 5,727 15,773 46,494 22)657 15,233 22,905 517,377 3I244 259,816 21,040 284,100
$5,357,572
$5,516,532 1,389,112 4,127,420 63,751 19,383 229,249 142,153 54,106 10,260 455,151 22,268 73,293 21,233 18,651 135,445
$4,781,767 93,832 1,020,795 566,023 1,680,650 210,000.-
262,792 1,881,441 4,034,883 92,000 69,500 9,950 177,751 60,915 5,049 22,132 47,497 20,519 13,299 15,671 534,283 9,943 4,065 178,580 20,013 212,601
$4,781,767
Consolidated statement of changes in financial position NIAGARAMOHAWKPOWER CORPORATION AND SUBSIDIARYCOMPANIES For the year ended December 31, FINANCIALRESOURCES WERE PROVIDED BY:
Operations:
Net income Charges (credits) to income not requiring (not providing) working capital Depreciation and amortization Allowance forfunds used during construction.....
Amortization of nuclear fuel Provision for deferred Federal income taxes (net)..
Other Outside financing:
Sale of common stock Sale of preferred stock Sale of mortgage bonds Issuance of other long-term debt Net borrowings under revolving credit facilities (Note 7)
Increase (decrease) in short-term debt.................
Other sources:
Deferred recoverable energy costs.......
Mandated refunds to customers (Note 9)
Unamortized debt reacquisition expense Income tax refund Other investments Sale of utilityplant Unamortized debt expense (Increase) decrease in working capital other than short-term debt (see befow)
Miscellaneous (net)
Total resources provided FINANCIALRESOURCES WERE USED FOR:
Construction additions Nuclear fuel Allowance forfunds used during construction Net additions...
Reduction of long-term debt.
Reduction of preferred and preference stock (Note 7)
Dividends Total resources used (Increase) decrease in working capital other than short-term debt:
Cash Accounts receivable Coal and oil for production of electricity Other materials and supplies Long-term debt due within one year Accounts payable Payable on outstanding bank checks Accrued taxes and interest Gas supplier refunds due customers Other (net) 1983
$312)409 127,390 (11'7,793) 11)856 80,850 (4,972) 409,740 171,269 120,000 200,000 15,135 83,900 (7,237) 583,067 47,560 (5,793)
(22,421)
(22,670) 159 (29,455)
(1 3,618)
(46,238)
$946,569
$6771155 14,309 (117,793) 573,671 130,829 14,318 227,751
$946,569
$ (11,816)
(44)827) 46,243 (2,148)
(39)348) 7,501 15,556 (7, 362) 1,934 4,812
$ (29,455) ln thovsands ofdollars 1982
$268,534 121,422 (94,736) 12,967 68,900 377,087 145,194 20,000 330,000 (55,330)
(15,000) 424,864 (22,816)
(8,416)
(1 9,999) 13,316 (6,239) 29,693 (28,016)
(42,477)
$759,474
$562,749 31,720 (94,736) 499,733 56,518 11,956 191,267
$759,474
$ (11,124)
(33,292) 6,949 (2,364) 43,920 12,397 10,557 9,946 (20,781) 13,485
$ 29,693 1981
$220,643 102,536 (71,890) 37,427 19,734 308,450 101,313 58,000 113,650 67,000 5,350 680 345,993 11,362 (10,445) 9,943 (23,349)
(1,988)
(75,599) 1,280 (88,796)
$565,647
$439,418 17,997 (71,890) 385,525 8,880 9,176 162,066
$565,647 5,570 2,193 (41,594)
(3,567)
(133,900) 20,478 50,358 (972) 23,644 2,191
$ (75,599) 23
Notes to consolidated financial statements Electric plant...................
Nuclear fuel (Note 3)............
Gas plant Common plant, Including equipment leased under capital leases................
Construction work in ro ress...
$3>636>374 293>973 473,757 106,144 1,455,463 62
$3,598,488 5
279,738 8
449,398 2
78,347 23 1,110.561 Total utilityplant
$6,165,711 100
$5,516,532 Allowance for Funds Used During Construction: The Com-pany capitalizes AFC in amounts equivalent to the cost of funds devoted to plant under construction. AFC rates are de-termined in accordance with FERC and PSC regulations. As a result of rate proceedings, the Company began computing AFC at a rate which is reduced to reflect the income tax effect of the borrowed funds component of AFC for its Nine Mile Point Nuclear Station Unit No. 2 in 1976, for the capitalized costs associated with its investment in N M Uranium, lnc. in 1978 (see Note 3) and for all additions to electric utility plant beginning in 1982. The AFC rates in effect December 31, 1983 were 11.75% and, net of tax, 9.50%. AFC is segregated into its two components, borrowed funds and other funds, and is re-flected in the Interest Charges section and the Other Income and Deductions section, respectively, ot the Consolidated Statement of Income.
Depreciation, Amortization and Nuclear Generating Plant Decommissioning Costs: For accounting purposes, deprecia-tion is computed on the straight-line basis using the average or 24 NOTE 1. Summary of Significant Accounting Policies The Company is subject to regulation by the New York State Public Service Commission (PSC) and the Federal Energy Regulatory Commission (FERC) with respect to its rates for service and the maintenance of its accounting records. The Company's accounting policies conform to generally accepted accounting principles, as applied to regulated public utilities, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities.
Principles of Consolidation:
The consolidated financial statements include the Company and its four wholly-owned subsidiaries. All significant intercompany balances and trans-actions have been eliminated. Assets and liabilities of foreign subsidiaries are translated into U.S. dollars at the exchange rate in effect at the balance sheet date. Revenue and expense accounts are translated at the average exchange rate in effect during the year. Currency translation adjustments are recorded as a component of equity and do not have a significant impact on financial condition.
UtilityPlant: The cost of additions to utility plant and of re-placements of retirement units ot property is capitalized. Cost includes direct material, labor, overhead and an allowance for funds used during construction (AFC). In accordance with Statement ot Financial Accounting Standards No. 71, capital leases executed in 1983 have been capitalized and in accor-dance with the transition rules included therein, leases exe-cuted prior to 1983 amounting to approximately $20,000,000 at December 31, 1983, have not been capitalized. The cost of current repairs and maintenance is charged to expense.
Whenever utilityplant is retired, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. The following table summarizes the components of UtilityPlant:
In thousands ofdollars At December 31, 1963 1982 remaining service lives by classes of depreciable property. In addition, certain costs associated with the discontinued Ster-ling Nuclear Station (see Notes 2 and 10) are being amortized over shorter periods as approved by the PSC. For Federal in-come tax purposes, the Company computes depreciation using accelerated methods and shorter allowable depreciable lives.
Estimated decommissioning costs (costs to remove the plant from service in the future) of the Company's Nine Mile Point Nuclear Station Unit No.
1 are recovered in rates through an annual allowance and charged to operations through depre-ciation charges.
The cost of decommissioning, which is ex-pected to begin in the year 2005, is estimated to be approxi-mately $278,000,000 at that time ($70,600,000 in 1983 dollars).
Through December 31, 1983, the Company has recovered
$12,700,000 of decommissioning costs in rates. There is no assurance that the decommissioning allowance willultimately aggregate a sutficient amount to decommission the plant. The Company believes that decommissioning costs, if higher than currently provided, will ultimately be recovered in the rate process, although no such assurance can be given.
Amortization of Nuclear Fuel: Amortization of-the cost of nuclear fuel is determined on the basis of the quantity of heat produced for the generation of electric energy. The cost of disposal of nuclear fuel, which presently is $.001 per kilowatt-hour of generation, is based upon a contract with the Depart-ment of Energy (DOE). These costs, which are associated with generation at Nine Mile Point Unit No. 1, are charged to operat-ing expense and recovered from customers through base rates or through the fuel adjustment clause (see Note 10).
Revenues:
Revenues are based on cycle billings rendered to certain customers monthly and others bi-monthly. The Com-pany does not accrue revenues for energy consumed and not billed at the end of any fiscal period. The Company's tariffs include electric and gas adjustment clauses under which energy and purchased gas costs, respectively, above or below the levels allowed in approved rate schedules, are billed or credited to customers.
The Company, as authorized by the PSC, charges operations for energy and purchased gas cost increases in the period of recovery. The PSC has periodically authorized the Company to make changes in the level of al-lowed energy and purchased gas costs included in approved rate schedules. As a result of such periodic changes, a portion of energy costs deferred at the time of change would not be recovered under the normal operation of the electric adjust-ment clause.
However, the Company has been permitted to amortize and billsuch portions to customers, through the elec-tric adjustment clause, over 36 months from the effective date of each change. The Company has filed proposed revisions to its fuel adjustment clause consistent with the PSC's Opinion in a proceeding which reviewed the Company's electric fuel ad-justment clause. The revisions are being reviewed in the Com-pany's current rate proceeding and implementation is ex-pected to coincide with the rate year beginning April 1984. The revisions essentially provide for partial pass-through of fuel cost fluctuations from those forecast in rate proceedings with the Company absorbing a specific portion of increases or re-taining a portion of decreases to a maximum of $15 million.
The revisions are not expected to materially impact the finan-cial condition or results of operation of the Company..
Federal Income Taxes:
ln accordance with PSC require-ments, unless otherwise authorized, the tax effect of timing differences between book and taxable income is flowed
through, that is, only income taxes currently payable are re-corded. However, as authorized by the PSC, deferred taxes are provided on benefits realized from the class life system of de-preciation permitted under the Revenue Act of 1971 (shorter depreciable lives, repair allowance and cost of removal), on Accelerated Cost Recovery System (ACRS) tax depreciation in excess of book depreciation, calculated on tax basis, as a re-sult of the Economic Recovery Tax Act of 1981 (ERTA), on deferred energy and purchased gas costs, on nuclear fuel dis-posal costs accrued prior to April 7, 1983, on nuclear generat-ing plant decommissioning costs and on certain"'other items (see Note 9). The Company has not provided deferred taxes on approximately $1.3 billion of various other tax deductions and depreciation method differences for property placed in service prior to 1981 which, in conformity with the ratemaking prac-tices of the PSC, have been flowed through. These various other flow-through tax deductions, which are deductible cur-rently for tax purposes but capitalized for accounting and ratemaking purposes, include certain taxes, a portion of AFC, pensions and certain other employee benefits.
The benefits resulting from an increase in the investment tax credit from 4'/o to 10'/0 and from the change in the limitation on the amount of credit which may be claimed in any year for property additions prior to January 1, 1981 have been deferred and are being amortized over the book life of the property which gives rise to such credits. One-half of the 4/o investment tax credits realized have been allocated to Other Income and Deductions, consistent with PSC directives. As a result of ERTA, all investment tax credits on property additions sub-sequent to December 31, 1980 are being deferred and amor-tized over the book life of the property which gives rise to such credit. In accordance with the provisions of the Tax Equity and Fiscal Responsibility Act of 1982, the Company claims the full 10'/o investment tax credit and, for purposes of computing cap-ital cost recovery deductions and normalization, is reducing the asset basis by one-half of the credit claimed. For the proj-ects specified in the AFC section above, the imputed tax ben-efit of the borrowed funds component of AFC has been cred-ited to Other Income and Deductions.
Amortization of Debt Issue Costs: The premium or discount on long-term debt issues is amortized ratably over the lives of the issues (see Note 7).
Pension Plans: The cost of pension plans is based upon cur-rent costs, amortization of unfunded past service benefits over periods ranging from 15 to 40 years and amortization over 15 years of unfunded past service benefits arising from plan amendments.
The Company's policy is to fund pension costs accrued (see Note 8).
Statement of Financial Accounting Standards No. 71 "Ac-counting for the Effects of Certain Types of Regulation": The Company has adopted the provisions of this statement in 1983.
The adoption of this statement did not have a significant effect on the results of operations or financial position of the Company.
NOTE 2. Depreciation and Amortization The total provision for depreciation and amortization, includ-ing amounts charged to clearing accounts, was $128,976,000 for 1983, $123,104,000 for 1982 and $104,252,000 for 1981. The 1983 and 1982 provisions include approximately $9,200,000 and $6,700,000, respectively, resulting from the PSC allowed recovery of the amortization of costs associated with the dis-continued Sterling Nuclear Station (see Note 10). The 1982 and 1981 provisions also include approximately $6,400,000 and
$900,000, respectively, resulting from the PSC allowed accel-crated recovery of the costs to modify the Company's Albany Steam Station to burn natural gas as a fuel. The percentage relationship between the total provision for depreciation and average depreciable property was 2.8/o in 1983, 2.9'k in 1982 and 2.8/o in 1981. The Company makes depreciation studies on a continuing basis and, upon approval by the PSC, periodically adjusts the rates of its various classes of depreciable property.
NOTE 3. N M Uranium, Inc.
During 1976, through a wholly-owned subsidiary, N M Uranium, Inc. (NMU), the Company purchased a 50 percent undivided interest in uranium deposits and associated mining equipment to be held by a jointly-owned mining venture. Ac-quisition of this interest was made primarily to provide a more assured future supply of nuclear fuel. The investment in the subsidiary, which includes costs incurred since acquisition and AFC accrued through March 31, 1981, has been reduced by the proceeds from the sale of uranium, net of tax, and trans-fers to the Company and is included in the consolidated finan-cial statements as part of the nuclear fuel component of utility plant (see Note 1). Such investment (including inventory with a spot market value of approximately
$28,300,000 and
$18,300,000 at January 1, 1984 and 1983, respectively) totaled
$86,300,000 at December 31, 1983 and
$83,000,000 at December 31, 1982.
In 1978, the PSC issued an order approving the Company's investment in NMU. This approval was subject to the condition that rates which the PSC willapprove in the future will reflect the cost of NMU uranium at the lower of cost or the'market price. The PSC also stated that the reasonableness of the Company's future uranium costs will be judged with reference to costs of uranium under "currently" available long-term con-tracts and in the spot market. Subject to PSC approval, the comparison of cost to market will be on an aggregate basis over the life of the project.
Because of unsettled conditions in the uranium industry, the spot market price of uranium continues to be depressed below levels anticipated by the Company at the time of its investment.
The spot market price of uranium was $22.00 per lb. at January 1, 1984 and $20.25 per lb. at January 1, 1983 as compared to approximately $43.00 per lb. during 1979. However, in Sep-tember 1983 the DOE reported that the average United States delivery price for all uranium during 1982, including long-term contracts and spot market price settlements, was $38.37 per lb.
Due to regulatory restrictions on the extent to which the costs of uranium produced by this mining operation may be allowed in future rates and considering current market price levels, a portion of the Company's investment may not be re-coverable. Accordingly, the Company suspended accruing AFC on this investment as of April 1, 1981. Due to the uncer-tainty of future uranium market prices during the period of utilization of the mine's output and of operating costs over the remaining productive life of the mine, the potential unrecover-able portion of the Company's investment, if any, cannot be reasonably estimated.
Management is continually evaluating the status of this mining operation to assure maximum recov-ery of the Company's investment.
Based upon current fore-casts of market prices and the Company's uranium require-ments through 1991, it is presently anticipated that the mining process will be completed and all production utilized.
In connection with the Company's current rate proceeding, the PSC is reviewing the cost of NMU uranium to be utilized in the next reload of the Company's Nine Mile Point Nuclear Unit-No. 1. The Company is unable to predict the outcome of this review.
25
NOTE 4. Bank Credit Arrangements and Compensating Balances At December 31, 1983, the Company had $445 million of bank credit arrangements, including the Oswego Facilities Trust, with 43 banks. These credit arrangements consisted of
$230 million in long-term commitments under Revolving Credit and Term Loan Agreements,
$70 million in short-term com-mitments under Credit Agreements, $45 millionof lines of cred-it and
$100,million under a Bankers Acceptance Facility Agreement. The Revolving Credit and Term Loan Agreements are seven-year commitments and were all renegotiated in 1983.
At the option of the Company, the interest rate on 'these agreements is based on the prime rate or interest rates appli-cable to certificates of deposit or eurodollar deposits. Allof the other bank credit arrangements are subject to review on an annual basis with interest rates negotiated at the time of use.
The Company also issues commercial paper.
Unused bank credit facilities are held available to support the amount of commercial paper outstanding.
The Company pays fees for the unused portion of the Revolv-ing Credit and Term Loan Agreements, the Oswego Facilities Trust and certain of its lines of credit. The Credit Agreements and other lines of credit require the Company to pay a combi-nation of fees and compensating balances.
Cash representing compensating balance requirements was not significant at De-cember 31, 1983. The Bankers Acceptance Facility Agreement, which is used to finance the fuel oil inventory for one of the Company's generating stations, provides for the payment of fees only upon the issuance of each acceptance.
Amounts outstanding under the Revolving Credit and Term Loan Agreements, including the Oswego Facilities Trust, are recorded as long-term debt and totaled
$68,900,000 at De-cember 31, 1983 (see Note 7).
The following table summarizes additional information applicable to short-term debt:
In thousands ofdollars 1983 1982 In thousands ofdollars Construction Percentage UtilityAccumulated work in ownershl lant de reciation ro ress Roseton Steam Station Units No.1and2(a)......
25 S 80,039
$21,087 S
1,732 Oswego Steam Station Unit No. 6(b).............
76
$262,736
$25,535 2,050 Nine MilePoint Nuclear Station UnitNo. 2(c)(d)....
41
$1,091,190 (a) The remaining ownership interests are Central Hudson Gas and Electric Corporation, the operator of the plant (35/o) and Consoli-dated Edison Company of New York, Inc. (40/o).
(b) The Company is the operator. The remaining ownership interest is Rochester Gas and Electric Corporation (24/o).
(c) The remaining ownership interests are Long Island Lighting Corn-pany (18/o), New York State Electric and Gas Corporation (18/o),
Rochester Gas and Electric Corporation (14/o), and Central Hud-son Gas and Electric Corporation (9/o) (see Note 10).
(d) Excludes amounts spent for nuclear fuel.
Operating revenues:
Electric...........
Gas Total
$2,023,728
$1,860,649
$1,719,933 608,587 533,122 430,785
$2,632,315
$2,393,771
$2,150,718 NOTE 6. Information Regarding the Electric and Gas Businesses The Company is engaged in the electric and natural gas util-ity businesses.
Certain information regarding these segments is set forth in the following table. General corporate expenses, property common to both segments and depreciation of such common property have been allocated to the segments in ac-cordance with practice established for regulatory purposes.
Identifiable assets include net utility plant, materials and supplies and deferred recoverable energy costs. Corporate as-sets consist of other property and investments, cash, accounts receivable, prepayments, unamortized debt expense and other deferred debits.
In thousands ofdollars 1983 1982 1981 AtDecember 31:
Short-term debt:
Commercial paper....
Notes payable Bankers acceptances Weighted average interest rate (a)..
S 37,100 41663 43,000 S 44,000 48,000 S 84,763
$ 92,000 9.60'/o 9.76'/o Total S
471,804 S
425,304 S
324,419 Pretax operating Income, including AFC:
Electric...................
S 538,097 S
476,006 S
360,580 Gas 51,500 44,034 35,729 Operating Income before taxes:
Electric...................
420,600 S
381,378 S
288,990 Gas
- 51,204 43,926 35,429 For year ended December 3 1:
Dallyaverage outstanding......
Dailyweighted average interest rate(a)
Maximum amount outstandin
$1191981
$147,910 9.01y/o 13.03 /o
$232,160
$260,890 (a) Excluding compensating balances and fees.
Net income Depreciation:
Electric.....
Gas S
312,409 S
268,534 S
220,643 115,075 109,215 S
91,571 12,315 12,207 10,965 Total...................
589,597 520,040 396,309 Income taxes................
117,089 109,519 53,043 Other income and deductions 41,505 36,947 29,146 Interest char es.............
201,604 178,934 151,769 Total 127,390 121,422 S
102,536 NOTE 5. Jointly-Owned Generating Facilities The following table reflects the Company's share of jointly-owned generating facilities at December 31, 1983. The Com-pany is required to provide financing for the unit in process of construction and for any additions to the units in service. The Company's share of expenses associated with the Roseton units and Oswego Steam Station Unit No. 6 are included in the appropriate operating expenses in the Consolidated Statement of Income.
26 Total Identifiable assets:
Electric...........
Gas Total........
Corporate assets Total assets S
691,464 S
594,469 S
457,415
$4>443y1 54
$4 01 1 265
$3 561 592 429,133 406,940 370,608 4,872,287 4,418,205 3,932,200 485,285 363,562 288,034
$5,357,572
$4,781,767
$4,220,234 Construction expenditures (including nuclear fuel):
Electric...................
S 654,020 562,047 424,596 Gas 37,444 32,422 32,819
~
~
NOTE 7. Capitalization CAPITALSTOCK The following table summarizes the shares of capital stock authorized, issued and outstanding:
At December 31 ~
1983 1982 1981 Common stock, $1 par value:
Authorized..................
Issued &outstandin Preferred stock, $100 par value:
Authorized...................
Issued 8 outstandin Preferred stock, $25 par value:
Authorized...................
Issued &outstandin Preference stock, $25 par value:
Authorized...................
Issued &outstandin 125,000,000 104,010,003 3,400,000 3,370,240 9,600,000 9,376,000 4,000>000 760,000 125,000,000 93,832,151 3,400,000 3,161,920 9,600,000 5,742,000 4,000,000 920,000 125,000,000 83,973,252 3,400,000 3,199,980 9,600,000 5,008,000 4,000,000 1,080,000 The table below summarizes changes in capital accounts for 1981, 1982 and 1983:
Common stock
($ 1 par value)
Non.redeemable preferred stock
($100 par value)
Redeemable preferred stock
($100 par value)
Redeemable preferred stock
($25 par value)
Capital stock premium and expense (net)
Shares Amount'hares Amount*
Shares Amount'hares Amount Amount'alance January 1, 1981 Salesin1981............
Issued to stock purchase plans in 1981...........
Redem tions............
75,231,144
$75,231 2,100,000
$210,000 885,240
$88,524(a) 4,974,000
$124,350(a)
$792,591 5,000,000 5,000 250,000 25,000 1,320,000 33,000 51,706 3,742,108 3,742 40,049 35,260,526 206,000 5,150 859 Balance December 31,1981 Sales in1982.............
Issued to stock purchase plans in 1982............
Redem tions.............
83,973,252 5,000,000 4,858,899 83,973 2,100,000 210,000 1,099,980 5,000 4,859 38,060 109,998(a) 6,088,000 152,200(a) 800,000 20,000 885,205 70,705 64,285
,806 226,000 5,650) 600 Balance December 31,1982 Salesin1983.............
Issued to stock purchase plansin1983............
Redemptions.............
Foreign currency translation ad ustment....
93,832,151 5,000,000 5,177,852 5,178 (41,680)
(4,168)
(326,000)
(8,150) 80,465 607 6,114) 93,832 2,100,000 210,000 1,061,920 106,192(a) 6,662,000 166,550(a) 1,020,795 5,000 250,000 25,000 3,800,000 95,000 78,629 Balance December 31,1983 104,010,003
$104,010 2,100,000
$210,000 1,270,240
$127,024(s)10,136,000
$253,400(a)
$1,174,382
- Inthousands of dollars (a) Includes sinking fund requirements due withinone year NON-REDEEMABLE PREFERRED STOCK (Optionally Redeemable)
The Company has certain issues of preferred stock which provide for optional redemption as follows:
At December 31 ~
Redemption price per share (Before adding accumulated dividends) in thousands ol dollars Eventual 1983 1982 1981 December 31, 1983 minimum Preferred $100 par value:
3.40% Series; 200,000 shares...
3.60% Series; 350,000 shares...
3.90% Series; 240,000 shares...
4.10% Series; 210,000 shares...
4.85% Series; 250,000 shares...
5.25% Series; 200,000 shares...
6.10% Series; 250,000 shares...
7.72% Series; 400,000 shares...
$ 20>000 35,000 24>000 21,000 25,000 20,000 25>000 40,000
$ 20,000 35,000 24,000 21,000 25,000 20,000 25,000 40,000
$ 20,000 35,000 24,000 21,000 25,000 20,000 25,000 40,000
$103.50 104.85 106.00 102.00 102.00 102.00 101.00 105.44
$103.50 104.85 106.00 102.00 102.00 102.00 101.00 102.36
$210,000
$210,000
$210,000 27
MANDATORILYREDEEMABLE PREFERRED STOCK The Company has certain issues of preferred and preference stock which provide for mandatory and optional redemption as follows:
At December 31, Redemption price per share (Before adding accumulated dividends)
In thousands of dollars Eventual 1983 1982 1981 December 31, 1983 minimum Preferred $100 par value:
7.45'/o Series; 474,000, 492,000 and 510,000 shares....
10.13/o Series; 250,000 shares........................
10.60/o Series; 296,240, 319,920 and 339,980 shares....
12.75/o Series; 250,000 shares.
Preferred $25 par value:
8.375/o Series; 1,500,000 and 1,600,000 shares..........
9.75/o Series;936,000, 1,002,000and1,068,000shares...
9.75 /o Series (second); 1,020,000 shares................
10.13'/o Series; 1,000,000 shares 10.75'/o Series; 1,600,000 shares 12.25'/o Series; 700,000 shares 12.50/o Series; 620,000 shares 15.00/o Series; 800,000shares.
Adjustable Rate Series A; 1,200,000 shares................
Preference $25 par value:
7.75'/o Series; 760,000, 920,000 and 1,080,000 shares...
Less slnkin fund re uirements
$ 47,400 25,000 29,624 25,000 37>500 23,400 25,500 25,000 40,000 17,500 15,500 20,000 30,000 19,000 380,424 11,950
$ 49,200 31,992 25,000 40,000 25,050 25,500 17,500 15,500 20,000 23,000 272,742 9,950
$ 51,000 33,998 25,000 40,000 26,700 25,500 17,500 15,500 27,000 262,198 7,450
$105.05 (a) 110.60
(>)
26.54 26.545 27.44 (a)
(a)
(c)
(c) 28.59 (a) 25.28
$100.00 100.00 102.65
(>)
25.00 25.00 25.00 25.00 25.00 25.00 25.00 25.00 25.00 25.00 (a) Not redeemable until 1988.
(b) Entire issue to be redeemed at par value June 30, 1991.
(c) Not redeemable until 1991.
$368,474
$262,792
$254,748 These series require mandatory sinking funds for annual redemption and provide optional sinking funds through which the Company may redeem, at par, a like amount of additional shares (limited to 120,000 shares of the 7.45'/o series and 300,000 shares of the 9.75'/0 series). The option to redeem additional amounts is not cumulative.
The Company's five-year mandatory sinking fund redemption requirements for preferred and preference stock are as follows:
In thousands ofdollars No. of shares Commencing 1984 1985 1986 1987 1988 Preferred $100 par value:
7.45'/o Series..........
10.60/o Series..........
10.13/o Series..........
18,000 20,000 25,000 6f30/77 3/31/80 12/31/87
$1,800
$ 1,800
$ 1,800
$ 1,800
$ 1,800 (a) 1,624(a) 2,000 2,000 2,000 2,500 2,500 Preferred $25 par value:
9.75/o Series.........
8.375/o Series.........
9.75/o Second Series 10.13/o Series.........
12.25/o Series.........
12.50/o Series.........
15.00/o Series.........
66,000 100,000 204,000 100,000 43,060 38,139 40,000 10/1/80 4/1/83 4/1/86 12/31/87 3/31/87 3/31/87 3/31/87 1,650 2,500 1,650 2,500 1,650 2,500 5,100 1,650 2,500 5,100 2,500 1,077 953 1,000 1,650 2,500 5,100 2,500 1,076 954 1,000 Preference $25 par value:
7.75/o Series...........
240,00 b
9/30/80 6,000 13,000
$11,950
$20,574
$13,050
$21,080
$21,080 (a) Requirements, or a portion thereof, have been met by advance purchases.
(b) The balance of the issue is to be redeemed September 30, 1985.
LONG-TERM DEBT Long-term debt and long-term debt due within one year are detailed in the table on the following page.
The 13~/z'/o First Mortgage Bonds and the $56,000,000 Ad-justable Rate Pollution Control Notes are both tax-exempt and were issued to secure a like amount of Revenue Bonds and Notes issued by the New York State Energy Research and De-velopment Authority (NYSERDA). Pursuant to agreements be-28 tween NYSERDA and the Company, trust funds have been es-tablished with the proceeds from the bond and note issues.
Such proceeds are to be used for the purpose of constructing certain pollution control facilities at the Company's generating facilities. Unexpended proceeds in the trust funds amounted to
$29,769,000 at December 31, 1983 and are recorded in Other Property and Investments.
J '
~
Notes Payable include $47,800,000 Eurodollar Guaranteed Notes issued by the Company's subsidiary Niagara Mohawk Finance, N.V. and guaranteed by Credit Lyonnais. In connec-tion with the formation and capitalization of this subsidiary, the Company also issued a $17,000,000 note payable which bears interest at the London Interbank Offered Rate (LIBOR), cur-rently set at 10.5/o through March 15, 1984.
The arrangements with Oswego Facilities Trust (Trust) pro-vide financing for the first construction phase of a new energy management system. The Trust has a $40,000,000 Direct Pay Letter of Credit Facility and Revolving Credit Agreement which is available through December 31, 1990, and is used to support its commercial paper obligations. All such obligations are se-cured by certain assets held by the Trust. The Company is required to purchase, or otherwise arrange for, the disposition of the Trust assets upon the termination of the Trust. The Letter In thousands ofdollars At December 31, 1983 1982 of Credit Facility and Revolving Credit Agreement of the Trust requires payment of fees which are based upon the amount of commercial paper outstanding.
Other long-term debt consists of obligations under capital leases of $15,135,000 and the liabilityfor nuclear fuel disposal of $45,472,000 (see Note 10).
During 1983, the Company reacquired $98,004,000 of its out-standing long-term debt prior to maturity. The refunding pre-mium, commissions and expenses paid upon reacquisition and the unamortized debt expense associated with the reacquired debt, amounting to $22,421,000, is recorded in "Deferred deb-its: Unamortized debt reacquisition expense". The Company has requested approval from the PSC to amortize these costs over subsequent periods and believes these costs will be re-
. coverable in future rates.
In thousands ofdollars At December 31, 1983 1982 First mortgage bonds:
3Vz /o Series due February 1 ~ 1983....
3V4/oSeriesdueOctober1,1983 3VS%SeriesdueAugust1
~ 1984.....
10VS/o Series due September 1, 1985..
AS'/o Series due May 1, 1986........
4r/e'/o Series due September 1
~ 1987..
3r/s/o Series due June 1,1988.......
14r/8/o Series due August 11, 1988....
474'/o Series due April1, 1990........
15/o Series due March 1, 1991......
4>/z'/o Series due November 1, 1991 15Vz /o Series due March 1, 1992......
1574'/o Series due June 1,1992.......
11'/o Series due May 1,1993........
45@/o Series due December 1, 1994..
5r/8'/oSeriesdueNovember1,1996 6>/4/o Series due August 1, 1997.....
6>/z/o Series due August 1, 1998.....
9>/8/o Series due December 1, 1999..
12.95'/o Series due October 1, 2000...
7% /o Series due February 1, 2001....
7rri>'/o Series due February 1, 2002....
7@4'/o Series due August 1,2002.....
8>/4/o Series due December 1, 2003..
9/o Series due December 1, 2003..
9.95'/o Series due September 1, 2004..
10.2'/oSeriesdue March1,2005......
8.35'/o Series due August 1,2007.....
878/oSeriesdue December1,2007 25,000 47,000 30,000 50>000 50,000 50,000 50,000 38,650 40,000 50,000 62>500 50,000 40,000 45,000 40,000 60>000 75,000 80>000 65,000 80>000 80>000 80,000 50,000 100>000 37,887 71,800 48,000
$ 25,000 40,000 25,000 47,000 30,000 50,000 50,000 50,000 50,000 50,000 40,000 50,000 75,000 40,000 45,000 40,000 60,000 75,000 80,000 65,000 80,000 80,000 80,000 50,000 100,000 38,935 72,800 50,000 13Vz
/o Series due April 1 ~ 2012...........
16 lo Series due August 1 ~ 2012........
12r/8'/o Series due November 1, 2012.....
12r/8'/o Series due March 1,2013.........
12Vz'/oSeriesdue June15,2013.........
Paul Smith's Electric Light&Power &
Railroad Company first mortgage bonds:
5Vz/o Series due May 1, 1985...........
PromIssory notes:
8/oSeriesAdue June1,2004..........
Notes payable:
Adjustable Rate Pollution Control Notes 17/o Eurodollar Guaranteed Notes due September15,1989..............
10.5/o Adjustable London Interbank Offered Rate due September15,1989 Prime rate plus Vz'/o (not to exceed 7>/z/o) due in equal quarterly install-ments through April1, 1984...........
Revolving credit end term loan agreements Revolving credit agreement, Oswego Facilities Trust..............
Other Unamortized premIum TOTALLONG-TERM DEBT.............
Less lon -term debt due within one year 30,000 3,046 100,000 100,000 50>000 30,000 75,000 100,000 450 450 46,600 46,600 56,000 47>800 17,000 50,000 17,000 625 50,000 18,900 60,607 1,835 3,750 35,000 6,000 45,472 2,934 2,078,700 1,950,941 30,152 69,500
$2,048,548
$1,881,441 Certain of the Company's First Mortgage Bonds provide for a mandatory sinking fund for annual redemption. The Company's five-year mandatory sinking fund redemption requirements for First Mortgage Bonds are as follows:
Principal In thousands ofdollars amount Commencing 1984 1985 1986 1987 1988 10.20/o Series due March 1 ~ 2005......
8.35'/o Series due August 1, 2007.....
8V>>'/o Series due December 1, 2007...
9.95/o Series due September 1, 2004 14r/s% Series due August 11, 1988.....
12.95/o Series due October 1, 2000....
9'/o Series due December1,2003...
$1,500 750 2,000 5,000 16,000 5,333 2,941 3/1/78 8/1/82 12/1/83 9/1/85 8/11/86 10/1/86 12/1/87
$ (e)
(e) 2,000
$ 1,387(a)
(e) 2,000 5,000
$ 1,500 550(e) 2,000 5,000
'6,000 5,333
$ 1,500 750 2,000 5,000 17,000
~ 5,333 2,941
$ 1,500 750 2,000 5,000 17,000 5,333 2,941
$ 2,000
$ 8,387
$30,383
$34,524
$34,524 (a) Requirements, or a portion thereof, have been met by advance purchases.
29
Additionally, certain other series of mortgage bonds provide for a debt retirement fund whereby payment requirements may be met, in lieu of cash, by the certification of additional prop-erty, the waiver of the issuance of additional bonds or the re-tirement of outstanding bonds.
The 1983 requirements for these series were satisfied by the certification of additional property. The Company anticipates that the 1984 requirements for these series willbe satisfied by other than payment in cash.
Total annual debt retirement fund requirements for these series, based upon mortgage bonds outstanding December 31, 1983, are $7,850,000.
NOTE 8. Pension Plans The Company and its subsidiaries have non-contributory pension plans covering substantially all their employees.
The total pension cost was $40,000,000 for 1983, $38,000,000 for 1982 and $34,100,000 for 1981 (of which $12,200,000 for 1983,
$11,000,000 for 1982 and $9,300,000 for 1981 was related to construction labor and, accordingly, was charged to construc-tion projects).
Studies indicate that the accumulated plan benefits, as de-termined by consulting actuaries, and plan net assets for the Total
$348,000
$320,000 Net assets available for plan benefits.....
$408,000
$341,000 The weighted average assumed rate of return used in deter-mining the actuarial present value of accumulated plan ben-efits was 7% in each year.
The above table summarizes accumulated plan benefits at-tributable to employee wage levels and service rendered through December 31, 1983 and 1982. These amounts do not take into consideration expected future service, wage in-creases and associated actuarial assumptions.
These addi-tional factors and assumptions are considered in determining the funding requirements of the Company's ongoing pension plans, based upon an approved actuarial cost method, and are in conformity with generally accepted actuarial principles and practices.
Company's plans at December 31, 1983 and 1982'are as follows:
In thousands ofdollars 1983 1982 Actuarial present value of accumulated benefits:
Vested
$328,000
$302,000 Non-vested 20,000 18,000 NOTE 9. Federal and Foreign Income Taxes Income Tax Refund:
In September 1981, the Company re-ceived a refund of Federal income tax, including interest thereon, amounting to $9,943,000, net of Federal income taxes on the interest portion of the refund. The refund resulted from the allowance of certain deductions for the loss of water rights at Niagara Falls in connection with the redevelopment of Niag-ara power by the Power Authority of the State of New York. As part of a March 1983 rate decision, the PSC ordered that one-half of the refund be passed on to ratepayers over a two-year period and the remaining one-half be retained by the Com-pany. Accordingly, one-half of the amount has been recorded in "Deferred Credits: Mandated refunds to customers", and is being amortized over two years. The remaining one-half is in-cluded in the Consolidated Statement of Income. In both Summary Analyslsr 1963 In thousands oldollars 1982 1981 Components of Federal and foreign income taxes:
Current tax expense: Federal.
Forei n
Deferred Federal income tax ex ense Income taxes included in Operating Expenses..........,.......
Federal income tax credits included in Other Income and Deductions...
Total.
Components of deferred Federal Income taxes(Note 1)r Depreciation Cost of removal of property Investment tax credit Recoverable energy and purchased gas costs Necessity certificates Nuclear fuel disposal cost.
Sterling abandonment Other
$ (4,566) 9,294 4>728 112,361 117,089 (31,511)
$65,578
$22>185 2,479 51,163 (22,523)
(700) 20,746 188 7,312
$ 4,860 9,369 14,229 95,290 109,519 26,390)
$83,129
$26,842 5,930 21,859 24,307 (700)
(9,940)
(908) 1,510
$ 6,996 6,765 13,761 39,282 53,043 19,548)
$33,495
$12,533 193 21,501 (1,811)
(700)
(12,224) 2,018 1,776)
Deferred Federal income taxes net Reconciliation between Federal and foreign Income taxes and the tax computed at prevailing U.S. statutory rate on Income before income taxes:
Computed tax
$60,850
$68,900
$19,734
$116,904 30 Reduction attributable to flow-through of certain tax adjustments:
Depreciation.
Allowance forfunds used during construction Taxes, pensions and employee benefits capitalized foraccounting purposes..
Real estate taxes on an'assessment date basis Investment tax credit Deferred taxes provided at other than the statutory rate Other Federal and forei n income taxes
$183,074 (6,431) 54,185 22,376 3,590 9,269 14,507 97,496
$65,578
$161,765 796 43,579 19,092 4,282 7,861 1,598 1,428 78,636
$83,129 9,422 33,069 12,515 3,086 12,354 7,424 5,539 83,409
$33,495
cases, the tax portion of the refund has served to reduce cur-rent tax expense. In July 1983, the Company filed a suit seeking to annul the PSC's decision to share the refund with ratepayers. A decision from the Appellate Division of the State Supreme Court is expected in 1984. The Company is unable to predict the ultimate disposition of this refund.
Investment Tax Credits: The Company deferred the net ben-efit of investment tax credits of approximately
$51,200,000
($.52 per share), $21,900,000 ($.25 per share) and $21,500,000
($:27 per share) for the years ended December 31, 1983, 1982 and 1981, respectively, in accordance with the general policy as stated in Note 1. The Company has unused credits at De-cember 31, 1983 of approximately $5,800,000, which may be utilized to reduce current tax expense in subsequent years.
Such credits, if unused, expire in 1998.
United States and foreign components ofincome before income taxes:
ln thousands ofdollars 1983 1982 1981 United States................
$386,051
$341,962
$247,374 Foreign.....
19,989 20,906 14,175 Consolidatin eliminations....
(10,053) 11,207,411 Income before income taxes
$397,967
$351,663
$254,138 NOTE 10. Commitments and Contingencies Construction Program: At December 31, 1983, substantial construction commitments existed, including those for the Company's share of Unit No. 2 at the Nine Mile Point Nuclear Station. The Company presently estimates that the construc-tion program for the years 1984 through 1988 will require ap-proximately $1,804 million, excluding AFC and certain over-heads capitalized. By years the estimates are $505 million,$345 million, $300 million, $301 million and $353 million, respec-tively (see "Nine MilePoint Nuclear Station Unit No. 2" below).
Nine Mile Point Nuclear Station Unit No. 2: Nine Mile Point Nuclear Station Unit No. 2 (Unit), a nuclear power plant being constructed by the Company and shared with other utilities, is the only major generating facility currently under construction by the Company. Ownership is shared by the Company (41%),
Long Island Lighting Company (18%), New York State Electric 8 Gas Corporation (18%), Rochester Gas and Electric Corpora-tion (14%), and Central Hudson Gas 8 Electric Corporation (9%). Output of the Unit, which will have a projected capability of 1,084,000 kw., will be shared in the same proportions as the Co-tenants'espective ownership interests.
Commercial operation of the Unit is scheduled for late 1986 at a cost, as estimated in January 1983, of $4.2 billion (com-prised of construction costs of $2.65 billion and AFC of $1.55 billion). The Company's share of the total estimate is approxi-mately $1.7 billion.
In September 1981, the Staff of the PSC issued a report on a comparative analysis of the economic and financial feasibility of the Unit versus coal alternatives. This report concluded that completion of the Unit is warranted. Also in September
- 1981, the PSC ordered a public proceeding to inquire into the finan-cial and economic cost implications of completing the Unit.
In an opinion and order issued on April 16, 1982 (Order), the PSC affirmed that completion of the Unit is warranted and in-dicated its intention to closely monitor construction activities.
In addition, the PSC adopted an incentive rate of return (IROR) program in connection with the remaining construction costs of the Unit. The purpose of this program is to reward savings in construction costs and penalize cost overruns based on a "sharing factor" of 20% of the variation in revenue require-ments from a target completion cost of $4.6 billion (including AFC) as apportioned to each Co-tenant. The PSC stated that adjustments to this target cost may be permitted should ex-traordinary events beyond the control of the Co-tenants occur, or if differing regulatory treatment than that assumed in deter-mining the target cost is adopted by the PSC in future rate proceedings. Under the IROR program, 20% of the variation in revenue requirements caused by construction cost overruns would penalize, and those caused by underruns would reward stockholders.
Any IROR-induced reduction in the return on equity may not exceed one-half of the normal unadjusted equity return on the applicable investment in the Unit. The IROR program will be implemented as part of the first rate proceeding involving each Co-tenant that considers rate rec-ognition of the Unit's completion cost.
In May 1982, various parties including the New York State Attorney General and the New York State Consumer Protection Board (CPB), petitioned the PSC to reconsider the Order. The PSC denied the petition and in December 1982, several parties, including the CPB and the Attorney General of the State of New York, filed a petition to appeal the PSC's decision. In November 1983, the Supreme Court Appellate Division,Third Department, affirmed the PSC's decision and the time for further appeal has expired.
In 1983, the Staff of the Nuclear Regulatory Commission (NRC), in accordance with their procedures for regular review, conducted assessments of the Unit's overall construction pro-gram.
In connection with these assessments, the NRC in-formed the Company that, in its opinion, management's atten-tion to certain aspects of the Unit's construction program should be increased. The Company is in the process of review-ing the NRC's recommendations and implementing corrective action, as appropriate.
A planned overall project cost re-estimate based on progress to date, which will include a re-assessment of the quantity of material and labor hours necessary for completion of the Unit, is currently in process and is expected to be completed in the second quarter of 1984. The Company does not presently ex-pect the total project cost re-estimate to vary significantly from the target completion cost established by the PSC in the IROR program.
The Co-tenants have completed a re-estimate of the project cost to be incurred in 1984 resulting in an increase in 1984 construction costs to approximately $579 million, representing a $189 million increase, excluding in both cases AFC and cer-tain overheads capitalized. The Company's 1984 estimate of its construction program expenditures, as presented above under "Construction Program", has been increased by $77 million to reflect the Company's 41% share of the aforementioned change. Estimates for the years 1985 and 1986 will be revised, as necessary, upon completion of the overall project cost re-estimate.
On February 9, 1984, the Long Island Lighting Company (LILCO)notified the other Co-tenants of its intention to cease participation in the funding of the construction costs of the Unit and failed to make a required payment. During 1984, con-struction funding for LILCO's 18% interest is expected to aver-age approximately $9 million per month.
The non-defaulting Co-tenants have stated they will take all appropriate steps to preserve their legal and regulatory rights with respect to the actions taken by LILCO. Various arrange-ments are being investigated for the funding of LILCO's re-maining interest in the Unit which, based upon the January 1983 cost estimate revised for increases in costs for the 1984 Unit work plan, amounts to approximately $150 million, exclu-31
Facility Expiration Purchased Estimated date of capacity annual contract in kw.
capacity cost PASNY St. Lawrence hydroelectric project....
Niagara hydroelectric project....
Blenheim-Gilboa-pumped storage generating station....
FitzPatricknuclear plan 1985 115,000
$ 1,360,000 1990 1,118,332 13,420,000 550,000 12,540,000 139,000 15,346,000 2002 t..
year-to-year basis 1986 400,000 39,200,000 2,322,332
$61,666,000 Ontario Hydro
'121,000 kw. for winter of 1984-85.
The purchase capacities shown above are based on the con-tracts currently in effect. The estimated annual capacity costs are subject to price escalation and are exclusive of applicable energy charges. In October 1982, FERC issued an order requir-ing the Company to negotiate reformation of its present con-tracts with PASNY for Niagara Project power such that prefer-ence be given to municipal electric utilities along with rights to interconnections and/or wheeling service. The Company and PASNY have appealed this order and the appeal is expected to be heard in early 1984. The Company is unable to predict the outcome of this proceeding.
Litigation: In 1978, several electric customers brought suit against the Company and PASNY requesting that certain 32 sive of AFC. On a temporary basis, the Company will advance funds as necessary for that portion of construction costs not being paid by LILCO. Although the Company believes that the actions of LILCO will not significantly affect the present schedule and ultimate cost of the Unit, no such assurance can be given.
A number of nuclear power plant construction projects in the United States have recently encountered substantial
- delays, licensing difficulties and cost escalation due to a variety of factors. Although the outcome of the remaining regulatory licensing proceedings relating to the completion of the Unit cannot be predicted with certainty, the Co-tenants believe an
- operating license will be issued upon completion of construc-tion since the Unit is being designed to meet applicable regula-tory requirements.
It is possible that completion of the Unit consistent with its present schedule and cost estimate and the issuance of an operating license could be adversely affected by the aforemen-tioned and other factors. Also, if all requisite governmental approvals are not received, or if governmental restrictions or prohibitions as to the use of nuclear power develop which af-fect this Unit, the Company's investment in the Unit ($1,091.2 million,including AFC and overheads capitalized, at December 31, 1983) may have to be written off, and in certain cir-cumstances, the Company could incur substantial cancellation charges. Although the Company believes that it would be per-mitted to amortize its investment in this project and any related cancellation charges against income and to recover such in-
- vestment, cancellation charges and related carrying costs through rates over a period of years, no such assurance can be given.
Long-term Contracts for the Purchase of Electric Power: At January 1, 1984 the Company had contracts to purchase elec-tric power from the following generating facilities owned by the Power Authority of the State of New York (PASNY) and from Ontario Hydro of Canada:
power purchased from PASNY be allocated exclusively'for their benefit and asking monetary damages for the difference between rates charged by the Company and rates that would otherwise have been charged if this power had been furnished to them since the initiation of the suit in 1978 and for the six years prior thereto. A settlement was reached in January 1982 wherein these electric customers will receive an initial alloca-tion of power and thereafter an increased allocation (through December 31, 1987) when their proposed plant expansion ac-tivities are completed. No monetary damages were awarded. In February 1982, certain other parties that did not join in the original litigation commenced litigation which sought to set aside the January 1982 settlement. This litigation is continuing and the Company is unable at this time to predict the ultimate outcome of these proceedings.
In the opinion of management, the ultimate disposition of this matter will not materially affect the Consolidated Financial Statements of the Company.
In October 1982, the CPB petitioned the PSC to exclude the Nine Mile Point Nuclear Station Unit No. 1 from rate base for the duration of the outage which occurred from March 1982 through June 1983. In addition, the CPB requested evidentiary hearings to determine whether imprudence played a role in either the cause or the duration of the outage. In November 1982, the PSC rejected the CPB petition, but did announce it would conduct a formal investigation into the cause and dura-tion of the outage after completion of repairs to the unit. Ac-cordingly, in July 1983 the PSC issued an order instituting such a proceeding. The Company is unable to predict the outcome of this proceeding.
In August 1983, the PSC instituted a proceeding to investi-gate the Company's operating practices and certain other mat-ters that it is alleged may have resulted, among other things, in excessive fuel adjustment charges in previous periods; and, further, to determine whether and to what extent remedial ac-tion with respect to any such matters is proper under the PSC's regulations or otherwise. Although the Company believes it has acted properly, it cannot predict to what extent, if any, adjustment of previous collections under the fuel adjustment clause may be required.
FERC Audit: As a result of an audit conducted by the Federal Energy Regulatory Commission (FERC) for the years 1973 through 1978, the FERC proposed certain adjustments con-cerning the base cost of nuclear fuel on which AFC should be applied. Resolution of this matter has been deferred by FERC pending their development of generic rulemakings concerning accounting for nuclear fuel. If these recommended adjust-ments are sustained by FERC, the resulting reduction in re-tained earnings would approximate $26,000,000 through 1983.
The Company believes that the adjustments are not justified and is contesting them. At present, the Company is unable to predict the outcome of this matter.
Sterling Nuclear Station: The PSC granted the Company permission to recover over a three-year period, commencing in 1982, its costs, together with carrying charges on the unrecov-ered balance, of the abandoned Sterling Nuclear Station. Ac-cordingly, the investment is recorded in "Deferred debits: Ex-traordinary property loss" and is being amortized. Such amor-tization is included in depreciation and amortization in the Consolidated Statement of Income. In September 1982, the At-torney General of, the State of New York commenced a pro-ceeding challenging the prudence of the PSC decision which permitted the Co-tenants to recover their costs and carrying charges associated with the project. A motion by the Co-tenants to dismiss the Attorney General's petition was denied and the Co-tenants appealed that denial. In July 1983, the Sup-
NOTE 11. Quarterly Financial Data (Unaudited)
Operating revenues, operating income, net income and earn-ings per common share by quarters for 1983, 1982 and 1981 are shown in the following table. The Company, in its opinion, has included all adjustments necessary for a fair presentation of the results of operations for the quarters. Due to the seasonal nature of the utilitybusiness, the annual amounts are not gen-erated evenly by quarter during the year.
ln thousands ofdollars Operating Operating Net Earnings per Quarters ended revenues income income common share December 31 1983 1982 1981 September 30 1983 1982 1981
$658,733 608,939 529,844
$562,707 510,983 481,377
$76>824 66,325 63,879
$72>309 63,981 60,831
$64,081
$.52 54,621
.49 52,063
.52
$62>376
$.52 52,699
.50 48,500
.48 June 30 1983 1982 1981
$651>487 587,350 528,216
$92,286 85,745 69,303
$79,027
$.72 73,271
.75 55,696
.61 March 31 1983 1982 1981
$759,388
$113,296 686,499 99,734 611,281 77,363
$106,925
$1.03 87,943
.94 64,384
.76 o
~
rerge Court, Appellate Division, in a unanimous decision, dis-missed the Attorney General's petition. The decision was af-firmed by the New York Court of Appeals in January 1984.
Nuclear Fue/ Disposal Costs: In January 1983, the Nuclear Waste Policy Act (Act) was enacted. Among other things, the Act provided for a determination of the liabilityto the Depart-ment of Energy (DOE) for the disposal of nuclear fuel irradiated prior to 1983, and three payment options for liquidating such liability. The Company's liability to the DOE associated with generation at its Nine Mile Point Unit No. 1 prior to 1983, is approximately $45,500,000. Based upon an optio'n;for payment in 1998, the year in which the Company first plans to ship irradiated fuel to an approved DOE disposal facility, it is esti-mated that the cost of such disposal will be approximately
$177,000,000, including interest charges as prescribed in the Act.
The Company, through ratemaking methodology approved by the PSC, has collected in rates approximately $145,800,000 for the disposal of nuclear fuel irradiated prior to 1983. Of this amount, $45,500,000, representing the liability to the DOE, is reflected in long-term debt and the remaining portion is in-cluded in accumulated depreciation and amortization. In con-nection with the Act and current PSC policy, the Company has petitioned the Commission for future ratemaking considera-tion of the ultimate future nuclear fuel disposal cost in relation to amounts previously collected. Such petition has been incor-porated into the Company's current rate proceeding and is being opp'osed by the Staff of the PSC in favor of a five-year refund of amounts collected in excess of the DOE contracted liabilityof $45,500,000. The Company is unable to predict the ratemaking treatment that will ultimately be prescribed by the PSC.
NOTE 12. Supplementary Information to Disclose the Effects of Changing Prices (Unaudited)
While much reduced from levels experienced in 198041, in-flation, resulting in a decline in the purchasing power of the dollar, remains one of our nation's concerns.
The threat of inflation and its negative impact on all sectors of the economy continues.
'he Company's consolidated financial statements are based on historical events and transactions when the purchasing power of the dollar was substantially different from the pres-ent. The effects of inflation on most utilities, including Niagara Mohawk, are most significant in the areas of depreciation and utilityplant and amounts owed on borrowed funds.
In recognition of the fact that users of financial reports need to have an understanding of the effects of inflation on a busi-ness enterprise, the following supplementary information is supplied for the purpose of providing certain information about the effects of both general inflation and changes in specific prices. It should be viewed as an estimate of the ap-proximate effect of inflation, rather than as a precise measure.
Constant dollar amounts attempt to adjust for general infla-tion and 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 utilityplant net of accumulated deprecia-tion and amortization, represents the eslimated cost of replac-ing existing plant assets in kind. Since existing utilityplant is not expected to be replaced precisely in kind due to technolog-ical changes, current cost does not necessarily represent the replacement cost of the Company's utilityplant. The portion of the accumulated amortization relating to disposal costs of nu-clear fuel was not used in the calculation of current costs but rather reclassified to a monetary liability. In most cases, cur-rent costs were determined by indexing surviving plant dollars by the Handy-Whitman Index of Public Utility Construction Costs. However, when an account could not be indexed by Handy-Whitman, other appropriate indices were used. The cur-"
rent year's provision for depreciation and amortization on the constant dollar and current cost amounts of utility plant was determined by applying the Company's average annual depre-ciation rates to the indexed plant amounts.
Fuel inventories, the cost of fuel used in generation, and electricity and gas purchased have not been restated from their historical cost in nominal dollars. The recovery of energy and purchased gas costs are limited to historical costs through the operation of the'ompany's electric and gas adjustment clauses. For this reason fuel inventories and deferred recover-able energy costs are effectively monetary assets.
Income taxes have not been adjusted.
The Company is subject to the jurisdiction of regulatory commissions in the determination of a fair rate of return on its investment. Current ratemaking policy provides for the recov-ery of historical costs. Therefore, any difference between the historical cost of utilityplant stated in terms of constant dollars or current cost not presently includible in rates as deprecia-tion, is reflected as an increase (reduction) to net recoverable cost. While the ratemaking process gives no recognition to the current cost of replacing utilityplant, based on past practices, the Company believes it will be allowed to earn on the in-creased cost of its net investment when replacement of facilities actually occurs.
33
To properly reflect the economics of rate regulation in the Statement of Income from Continuing Operations, the increase (reduction) of net utilityplant to net recoverable cost should be adjusted by the gain from the decline in purchasing power of net amounts owed on borrowed funds. During a period of in-flation, holders of monetary assets suffer a loss of general purchasing power while holders of monetary liabilities ex-C'erience a gain. The gain from the decline in purchasing gower of net amounts owed is primarily attributable to the substantial amount of debt which has been used to finance utility plant.
Since the depreciation on this plant is limited to the recovery of historical costs, the Company does not have the opportunity to realize a holding gain on debt and is limited to recovery only of the embedded cost of debt capital.
Statement ofincome from continuing operations adjusted forchanging prices forthe year ended December 31, 1983 In thousands ofdollars Conventional Constant dollar Current cost historical cost average 1983 dollars average 1983 dollars Operatin revenues
$2,632,315
$2,632,315
$2,632,315 Fuel for electric generation Electricity purchased Gas purchased.
Depreciation and amortization Other operating and maintenance expenses Federal and foreign income taxes Interest charges.
Other income and deductions net.
501,328 381,703 432,898 127,390 717,192 117,089 169,161 126.855 501,328 381,703 432,898 289,112 717,192 117,089 169,161 126,855 501,328 381,703 432,898 361,003 717,192 117,089 169,161 126,855)
Income from continuing operations (excluding adjustment to net recoverable cost 2,319,906 2,481.628 2,553,519 312 409 150 687*
78,796 Increase in specific prices (current cost) of utilityplant held during year"..
Adjustment to net recoverable cost Effect of increase in eneral price level.
Excess of Increase in specific prices over Increase in general price level after adjustment to net recoverable cost.
Gain from decline in urchasin power of net amountsowed...........
Net (17,364) 89,805 S
72,441 151,052 340,979-437,504) 54,527 89,805 S
144,332
- Including the adjustment to net recoverable cost, the income from continuing operations on a constant dollar basis would have been $ 133,323 for 1983.
- At December 31, 1983, current cost of utility plant. net of accumulated depreciation, was $9,249,935 while historical cost or net cost recoverable through depreciation was $4,779,783.
Five year comparison of selected supplementary financial data adjusted for effects of changing prices.
0 eratin revenues In thousands of average 1983 dollars For the year ended December 31, 1983 1982 1981 1980 1979
$2,632,315
$2,470,850
$2,355,896
$2,148,710
$2,081,552 Historical cost Information adjusted for general Inflation:
Income from continuing operations (excluding adjustment to net recoverable cost)
S 150,687 136,569 81,452 Income (loss) per common share (after dividend requirements on preferred stock and excluding adjustment to net recoverable cost) 1.11 S
1.11 S
.56 Net assets at ear end at net recoverable cost....................
$2,147,836
$1.929.503
$1.767.992 28,980 73,861 S
(.10)
.56
$1,745,526
$1,79'l,146 Current cost information:
Income (loss) from continuing operations (excluding adjustment to net recoverable cost)
Income (loss) per common share (after dividendrequirements on preferred stock and excluding adjustment to net recoverable cost)
Excess (deficiency) of increase in general price level over increase in specific prices after adjustment to net recoverable cost..........
Net assets at ear end at net recoverable cost General Information:
Gain from decline in purchasing power of net amounts owed.
Cash dividends declared per common share Market price per common share at year end Avera e consumer price index 78,796 80,307 S
20,967 S
(37,337)
(2,764)
.38
.47
(.21)
S (1.03)
S
(.65)
S (54,527)
(36,802) 140,293 S
242,359 S
346,907
$2,147,836
$1,929,503
$1,767,992
$1,745,526
$1,791
~146 S
89,805 S
83,147 189,251 S
253,362 291,905 1.89 1.82 S
1.76 S
1.81 S
1.98 S
15.75 S
16.13 13.56 13.45 17.33 298.4 289.1 272.4 246.8 217.4
4
~ o
~
0 v
Selected financial data 1983 1982 1981 1980 1979 Operations: (000's)
Operating revenues.
Net income
$2,632,315
$2,393,771
$2,150,718
$1,777,115
$1,516,503 312,409 268,534 220,643 162,639 156,030 Common stock data:
Book value per share at year end Market price at year end Ratio of market price to book value at year end Dividend yield at year end Earnings per average common share..
Rate of return on common equity Dividends paid per common share....
Dividend payout ratio
$18.55 153/4 84.P/o 12.2Yo
$ 2.77 15 IF/o
$ 1.89 68.2Yo
$17.91 15%
87.P/o 11.5%
$ 2.64 14 7%
$ 1.76 66.T/o
$17.36 12%
71.PYo 13.P/o
$ 2.35 13 5%
$ 1.61 68.5%
$17.25 11V8 64 13.T/o
$ 1.87 10.8o/o
$ 1.50 80.P/o
$17.33 125/8 72.9o/o 11.4%
$ 2.00 11.4%
$ 1.44 72.(F/o Capitalization: (000's)
Common equity Non-redeemable preferred stock Redeemable preferred stock Long-term debt
$1)929) 073 210,000 368,474 2,048,548
$1,680,650
$1,457,934
$1,298,001
$1,177,725 210,000 210,000 210,000 210,000 262,792 254,748 205,924 189,650 1,881,441 1,663,671 1,484,535 1,479,294 Total First mortgage bonds maturing within one year 4,556,095 4,034,883 3,586,353 25,000 65,000 3,198,460 3,056,669 140,000 80,000 Total
$4,581,095
$4,099,883
$3,586,353
$3,338,460
$3,136,669 Capitalization ratios: (inciuding first mortgage bonds maturing within one year):
Common stock equity.
Preferred stock.
Long-term debt 42.1%
12.6 45.3 41.IF/o 11.5 47.5 40.T/o 12.9 46.4 38.9o/o 12.5 48.6 37.5%
12.8 49.7 Financial ratios:
Ratio of earnings to fixed charges Ratio of earnings to fixed charges without AFC...
Ratio of AFC to balance available for common stock Ratio of earnings to fixed charges and preferred stock dividends Other ratios-% of operating revenues:
Fuel, purchased power and purchased gas Maintenance and depreciation Total taxes Operating income Balance available for common stock..........
43.6o/o 41.P/o 2.35 2.32 50.IF/o 10.0 13.0 13.5 10.3 49.PYo 10.5 13.2 13.2 9.6 2.98 2.95 2.40 2.42 2.63 2.16 38.6o/o 2.10 52.7%
10.3 11.2 12.6 8.7 2.43 2.61 1.99 2.09 44.P/o 44.PYo 1.93 2.03 51.8%
48.6o/o 10.8 12.1 11.9 12.4 11.9 12.8 7.5
8.5 Miscellaneous
(000's)
Gross additions to utilityplant Total utilityplant Accumulated depreciation and amortization..
Total assets 691,464 594,469 457,415 378,503 374,530 6,165,711 5,516,532 4,985,315 4,563,309 4,218,528 1,486,196 1,389,112 1,304,436 1,191,747 1,074,325 5,357,572 4,781,767 4,220,234 3,849,747 3,565,175 35
Electric and gas statistics ELECTRIC CAPABILITY Thousands ofkilowatts AtJanuary 1, 1984 1983 1982 ELECTRIC STATISTICS 1983 1982
~>
0 ~
1981 Thermal:
Coai fuel Huntley, Niagara River..
Dunkirk, Lake Erie.....
Total coal luei..
Residual oiifuel Albany, Hudson River"......
Oswego, Lake Ontario.......
Roseton, Hudson River.. z...
Middle distillate oiifuei 20 Combustion turbine and diesel units.............
Total oiifuel Nuclear fuel Nine Mile Point, Lake Ontario....
Purchased firmcontract Power Authority FitzPatrick, Lake Ontario......
Total nuclear fuel Total thermal sources..
715 9
705" 705 550 7
540 540 1,265 16 1,245 1,245 400 5
400 400 1,736 23 1,723 1,736 300 4
300 358 310 4
310
.310 2,746 36 2,733 2,804 610 8
610 610 139 2
118 116 749 10 728 726 4,760 62 4,706 4,775 Hydro:
Owned and leased hydro stations (83).
695 9
685 650 Purchased -firmcontracts PowerAuthority-NiagaraRiver....
1,118 15 1,122 1,122 Power Authority-St. Lawrence River..............
115 1
115 115 Power Authority Blenheim-Gilboa Pumped Storage Plant...........
550 7
550 550 Other 63 1
64 67 Electric sales(Millions ofkw-hrs.)
Residential................
Commercial...............
Industrial..................
Municipal service..........
Other electric s stems......
8,578 9,387 10,860 251 5,656 34,732 8,475 9,330 10,366 257 4,212 32,640 8,459 9,418 11,636 266 3,111 32,890 539,317 628,601 425,331 34,907 171,597 60,896 483,852 578,186 429,870 31,274 137,341 59,410
$2,023,728
$1,860,649
$1,719,933 Electric customers(Average)
Residential................
Commercial...............
Industrial..................
Other.................=....
Residential(Average)
Annual kw-hr. use per customer............
Cost to customer per kw-hr..
Annual revenue per customer............
1,245,590 131,803 2>594 3,257 1,383,244 6>887 6.800
$468.57 1,232,164 130,872 2,686 3,260 1,368,982 6,878 6.36tf
$437.70 1,223,484 131,119 2,807 3.232 1,360,642 6,914 5.72If
$395.47 Electric revenues(Thousands ofdollars)
Residential................
583,645 Commercial...............
658,960 Industrial..................
441,219 Municipal service..........
36,466 Other electric systems......
235,257 Miscellaneous.............
68,181 Total hydro sources..
Other purchases..
Totalcapability',541 33 2,536 2,504 400 5
400 7;701 100 7,642 7,279 GAS STATISTICS Electric peak load during year..
1983 5,625 1982 1981 5,512 5,616 ELECTRICITYGENERATED AND PURCHASED(Millionsofkw hrs )
1983 1982 1981 Thermal:
Generated Coal...........
Oil.............
Nuclear........
Natural gas.....
Purchased Nuclear from Power Authorit Total thermal Hydro:
Generated........
Purchased from Power Authorit Total hydro...
7,873 21 7,897 22 7,046 20 4>313 11 4 892 14 7 044 19 2,802 7
1,135 3
3,270 9
1>839 5
1,999 6
681 2
790 2
768 2
690 2
17,617 46 16,691 47 18,731 52 3,527 9
3,575 10 3,703 10 7,587 20 8,000 22 8,522 24 11,114 29 11,575 32 12,225 34 Other purchased power-varlous sources...... ',621 25 7,621 21 4,907 14 Total generated and purchased 38,352 100 35,887 100 35,863 100 Available capability can be increased during heavy load periods by purchases from neighboring interconnected systems.
Hydro station capability is based on average December stream-flow conditions.
-Has capability to burn natural gas tas well as oil) as a fuel.
V 1982 51,019 28,672 26,026 3,976 1981 51,701 26,342 26,826 4,889 103,153 109,693 109,758 Gas revenues(Thousands ofdollars)
Residential................
$304,157 Commercial...............
155,858 Industrial..................
129,056 Other gas systems..........
15,783 Miscellaneous.............
3,733
$608,587
$264,747 137,105 112,582 15,418 3,270
$533,122
$222,280 102,727 89,337 13,795 2,646
$430,785 Gas customers(Average)
Residential...............
Commercial..............
Industrial.................
Other....................
, Residential (Average)
Annual dekatherm uso per customer....
Cost to customer per dekatherm...
398,597 31>697 524 2
430>820 117.6
$6.49 396,729 31,188 534 2
428,453 128.6
$5.19 393,182 30,564 530 2
424,278 131.5
$4.30 Annual revenue per customer........
Maximum day gas sendout dekaiherms
$763.07
$667.32
$565.34 754,061 832,307 824,777 1983 Gas sales(Thousands ofdekatherms)
Residential................
46,865 Commercial............'...
26,921 Industrial..................
25,736 Other ass stems..........
3,631
Directors Officers James Bartlett Consultant (formerly Executive Vice President)
Syra'cuse Ednfund M. Davis fa, a, AJ Partner, Iiiscock, Lcc, Rogers, lienley Z. Barclay, attornc> s at.law Syracuse WilliamJ. Donlon Prcsidcnt Syracuse Edward W. Duffy(cy Former Chairman ofthc Board and Chief Executive OAiccr, Marine Midland Banks, Inc.,
a bank holding company Buffalo John G. Haehl,Jr.(.tJ Cltairman ofthc Hoard and Chief Executive OAicer Syracuse Edwin F. Jaeckle f.f,aJ Senior Partner,Jacckfc, Flcischmann tk iifugcf, at torncys-at-faw Buffalo Lauman iXIartin Consultant (formerlySenior Vice President and General Counsel)
Syracuse Baldwin Maull(it,IIJ Director ofvarious corporations New York Martha Hancock Northrup (DJ flomcmakcr, former President, Crousc-Irving i~fcmoriaf liospital Board Syracuse
'rank P. Piskor (.t, c, DJ President Emeritus St. Lawrcncc University Canton Donald B. RicflerfsJ Chairman, Sources and Uses of Funds Comnlittcc, Morgan Guaranty Trust Compan> of NcivYork New York Lewis A. Sivyer ps, c, a)
President, LA.Swyer Company, Inc., builders and construction ntanagcrs Albany John G. WickfD,O Cox, Barrcll, Wafsh, Grace 8:
Roberts, at tom cys-at-law Buffalo John G. Haehl,Jr.
Chairman ofthc Board and Chief Executive Officer WilliamJ. Donlon Prcsidci1t Richard C. Clancy Senior Vice President John M. Endrics Senior Vice President John M. I-Iayncs Senior Vice President John P. Hennessey Senior Vice Prcsidcnt James J. Miller Senior Vice President Gerald K. Rhode Senior Vice President John H. Terry Senior Vice President General Counsel and Secretary Richard I'. Torrcy Senior Vice Prcsidcnt Anthony J. Baratta,Jr.
Vice Prcsidcnt-Controller Robert M. Cleary Vice Prcsidcnt-Rcgional Operations Charles V. Mangan Vice President-Nuclear Engineering and Licensing Samuel I'. Manno Vice Prcsidcnt-Nuclear Construction Eugene J. iVIorel Vice Prcsidcnt-Risk hfanagcmcnt James F. iblorrell Vice President-Corporatc Planning John W. Powers Vice President-Trcasurcr Michael P. Ranalli Vice Prcsidcnt-Engineering (Non nuclear)
Kenneth A. Tramutola Vice Prcsident-Gas and Consumer Services Perry B. Woods,Jr.
Vice Presidcnt-Employee Ifelations Edward P. Gueth,Jr.
Assistant General Counsel Herman B. Noll Assistant General Counsel Nicholas L Prioletti,Jr.
Assistant Controller rf. ilfcmbcrofthc Executive Committee B. Mcmbcr ofthc Compensation Committee C. Member ofthe Audit Committcc D. i~fcmber ofthe Committec on Corporate IhtbffcPolicy I.'. Member ofthc Finance Committee Donald P. Disc Vice Prcsidcnt-Quality Assurance William C. Franklin Vice Prcsidcnt Purcltasing Kermit E. Hill Vice President-Public Affairs and Corporate Communications Raymond Kolarz Vice Prcsident-Rcgional Operations Thomas E. Lcmpges Vice Prcsident-Nuclcar Operations Adam F. ShaQ'cr Assistant Controller Henry B. Wightman,Jr.
Assistant Controller Harold J. Bogan Assistant Secretary Joseph F. Cleary Assistant Secretary Frederick C. McCall,Jr.
Assistant Secretary Richard N. Wescott Assistant Treasurer Donald L. MacVittie Vice President-Fossil Generation 37
N1 V NIAGARA lM0 MOHAWK 300 Erie Boulevard W.
Syracuse, NY 13202 Night settles in northern Adirondacks, finding Niagara Mohawk crew finishing cmcrgcncy repairs against wilderness backdrop.
i>>
J Q
j7 I A