ML17056B863
| ML17056B863 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 12/31/1991 |
| From: | Carrigg J NEW YORK STATE ELECTRIC & GAS CORP. |
| To: | |
| Shared Package | |
| ML17056B860 | List: |
| References | |
| NUDOCS 9205280199 | |
| Download: ML17056B863 (98) | |
Text
~ Burning Coal More Cleanly Reducing Demands on tbeEnvi>ament Eploring anAternaliaeFuel I I (I, I I
)ll I(,
] I I
BuildingOurNatural CasBuslness Reking New Opportunities
(-~9205ZEf0199 920520 PDR ADOCK 05000220 I
PDR i991 h'ew YorkStale8&ric 6 Cns Corale
1991 Pemn/Change ATDECENBER31 Total Assets (000)
Capitalization (000)
Capital Structure (includes current matufities):
Long-Term Deht Pfdemxl Stock Common Equity
$4,924,836
$3,463,112 52.2%
7.7%%do
$4,737,431
$3,291/01 54.2%
5.1%%uo 40.7%
(4) 51 0)
OPERATINGRESULTS(000)
Gfoss Operating Retinues Operating Expend Net Income Earnings forCommon Stock Retail Megawatt-Hour Sales Dekatherms ofNatural Gas Deliver
$ 1,555,sls
$ 1,244,040
$ 168,643
$ 148,313 13,107 41,79s
$ 1,496,780
$ 1,181,423
$ 158,013
$ 145,351 13,197 33,672 4
5 7
2 (1) 24 PER CONNONSHARE EamingS Dividends Book Value (ltear end)
Market Value (ltear end)
$2.36
$2.10
$22.16
$29.00
$2.48
$21.85
$26.00 (5) 2 1
12 OTHERINFOEMATION Common Stock Price Range Return on Avterage Equity Market-to-Book Ratio Average Common Shares Outstanding (000)
Common Shareholders (ltear end)
+-295/8 107%
131%
62,9o6 59,593
$213/8-29 1/4 11.4%
119%o 58,678 6o,5s5 DIVIDE.I1W'OLLAR J
PKR IkARE.
60 2.611 2~
202 2.06 2.10 tAtt.NlrtGf POLLARJ PKR /PAR.E 3.21o I 210'%+248 ~6 gc Exdnftng thc dfccts ofthe urttectf cfNhebttfe potnt 2 and J rntsport disalfoaed costs and an ccounettng change forIrexne taxes.
~ Exdehng the dfcct cfan hprtl 1Sgg adfusttncnt to the 19g7 Ntne MtfePoint 2 arttooK 1986 1987 1988 1989 1990 1991
~ Indoftng the dfcct ofa~
19g9 adjustrncnt to thc 1Ssff Ntne bttfe 1986 1987 1988 1989 1990 891 pet tgart~,earntngsacreggs3.
asset.'Ihere is a rene>>@i spirit and sense ofcommitment, and a realiza-tion thatwe all must work together as a team ifwe are to be successful.
To that end, we have hied a nationally-recognhxi finn to design and conduct a leadership and team-buildingprogram foremployees. This program helps each ofus unde(stud our role as a team member. Team-
>>ork is critical ifwe are to move forward in an ever more challenging and competitive environmen.
a)'el
Ã$EG's management team: (jam 1')Jerry Pulman, eecutiveassistant lo llxdwirntan, pmiitentand dn'eJ'eeculiceogicer,Jack Roskoz, swior viceprestctent-Btectrio Business Unit, Russ Fleming, senior vicepresictent-Gas Business Unil, Paul Komar, senior (nce pesuknt-Strateg(ohtanagetnent Business Unit,Jim Carr(gg dnirntan, presiitent anct dneJnnntive suer, Ben(ie Ria'er, senior viceperu&(t - Strategic Growlb Business Vnil, anctD('ck Fagan, senior vicepeiik(t-htanagen(cut Seruim Business Unit.
We are also faced withmany challenges. Foremost is the combination ofasluggish state economy and disturbing budgetnevvs fromAlbany. Simply put, the economic doldrums Although the impxtofour rene>>el spirit is dificultto measure, its results are appamnt. Here are a fmvexamples:
a Employers have begun to examine manyofour basic afect sales and the budget quandary signals an increased activities and processes. Wecall tliis effort ">>orksimplification" financial burden on thestate's businesses and midents. Among and the resultwill be lour operating costs, better use of resources and enhancedservice.
the tools we are using to meet these challenges are our pron.n economic devvlopmentprogram, a commitment to expand our o We ham placed newemphasison preparing acompre-natural gas business and increased interxtion with regulators, hensivestrategicplan forthe corporation andspecificplans for policy-makers, large customers and community leaders.
each business unit Part oftliispxkage is our vision, as shown on page 1ofthis Annual Report, and our enhanced mission statement, wltich is also included on page 1.
Anothersignificantchallenge is diversification. 2 dt'scttsst'0n ofdiversificalionbegittson page 14 We continue to believe that diversification into energy-related and environ-a NYSEG and the International Biotherhoodof Electrical mental seNicesbusinesseswill benefitourstockhoMeis and Workers have signed athiee-1m contrxt forthe first time ever. Itsets thestage forcontinuing dialogue and a successful partnership.
customers. Once we receive approval ofour plans from the PSC, which'xpect in the firstquarter of 1992, we willproceed withcaution and prudence.
Other issues which willcommand our attention in 1992 and beyond include:
independentlywwned utilityin 1949.
We also have bvo noteworthy personnel items to pass a Improving financial performance through such along. In Septembermmlcomed Paul Gioia to the Bowlof actions as aclheving our maximum demand management incentins, improvingeficiency tliroughworksimplification, Directors. Asenior vice president ofFiist Albany Corporation and former chairman ofthe PSC, Mr. Gioia is the 13th member establishing non-regulated subsidiaiies anddezloping growth ofthe BoanL Hehas avedth ofutilityknowledge and is very strategies forour coie businesses o Remolding our corporate culture through such familiarwith the challenges we face.
In Maywe were saddened by the death ofCharles Kennedy.
actions as improving internalcommunications and encourag-He was NYSEG's chairman andcltiefexecutiveo8icerfrom ing innovation o Complying with the Clean AirActAmend-1977 until he retinxi in 1983. Hewas a man ofgieatpersonal integrity and business acumen who contributed unselfishly to ments of1990 by implementing amulti-yearprogram to NYSEG throughout his 32-)eu career as a Board member reduce sulfur dioxide (SO,) and nitrogen oxides (NO) emissions from our coal-fired generating stations Adiscm&n ofourplans begirv onpage 6.
and oficer.
In closing, be mund that we aie steadfastly committed to providing the highest qualityseivice to our customeis and a Addressing the issue ofelectric and magnetic impronxi value to our stockholders.
fields (EMF) though the continuing support offuither study at the national level and being proactive in the communities weme Meanwhile, we continue to aggressively reduce our inteiestexpense. In November 1991, we issued )150 millionof 87/8percentseries fust mortgage bonds. The proceeds were used primarilyfor the redemption ofhighmupon debt which willsave approximately ]600,000 agar in interestexpense.
To further improv our financial condition, we also issued
$ 100 millionof895pereentpieferredstock in February 1991.
InMaxh 1992, we plan to sell up to 5 millionshares of common stock which willincrease our equity to approximately 42 percent oftotal capital, the highestsince NYSEG became an We sincerely appreciateyourconfidence in NYSEG.
For the Board ofDirectors,
~c-JamesA, Camgg Chairman, President and Chief Executive Oficer February 20, 1992 j1 i Y I j ~/
YEAR IN REVIEW
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'c Clwinnan and diiefeacutt'ce
'gicerJini Canigg dected prestd&tlfollowingItic rett'rwtwtofA1Nnttgh.
7bePublicServt'ce Commimon (PSC) approce'4.4 percerrl dedricaird 2.8perut ttnatural gas rale r'rt razmejedt'ceFebncary 1.
7heBoardof DiraJors wdorsesmartagernenl's recommertdatt'oct forII+
certtralimtttrrt oftdepl one oontactsuith acstorners and acstomer account maintettanm Bertefits willindudeaddedbouts ofavailabilityloaNeners and mluudcosts A mandated managernwt audit begins covering MSEG2000, cetstnccties, nalural gassupply and operations, and a7ual eniploymwt opportunity corrtplianu.
Jim Carriggis elactadto the Edt'son 8edriclnstilute CEO Policy Committee on Gouenunerital pat'rs. Heatso season Ihe CEOSieering Committee on lndicstry Stncdure(PURPA Reform and 7tunsrnt'ssr'on Acct') arrd the CEO Policy Conmiillae on Comrnunt'catiort, Ittarkelirrg, and Cicstomer and Erripicrtee Rdations.
FEBRUARY NSEGselts g100million ofacrnulatt'ce f25par valueprefened stock wttbafcvedannual dividend rate of895 percerit. 7hisis tttefirslsaleofMSEGpreferredstockst'itu 1983.
Somerset Station is rertameQllw F. IG'nttgh Station as a tribute to cItr. Iclnligh's atntributt'onsto completing Ibestatt'ott on Iimeand under budgel.
Amere tustonn teace'apprccvtmatdy 55000NSEGelectric acstomersin IlxHontdl, Gwecrt, Elmira, Plattsburgh and ttttaca dc'vt'sconswt'thout pouter. h'eariy80penwtoftttoseacsiomers hadpece restoredwttht'rt tuo days. Poue rsrestoredto allcrcstometsui%l'n onemek.
MSEG colrlplate thepurdtase ofColumbia Gas ofh'ew York, trtc arid as a rmcttincrease Iticnumber ofnalural gas cuslometsit serus by 69000.
Eall Gilmorir Allen Rtnttgh, AltonIttarshall and Robert Planeare ~lededto the Boardof Directors at(I@ Annualitteeling rut'th moral!an 86percerit ofthesttareseligibleto vote reprewted.
Nutigb Statcrm htwtbers ofthelirtencational Brottteritoodof8edrt'cal )Corkers (IBBQartdMSK'agree to a Ibm gnvr contract +WiveJrily 1, 1991.
MSK'announus that, asa restctt ofcorrtpetiliveMSingbegunin July 1990, ituillnegotiate contractsfor about 17 irtegauvttts(niw) in dwtartd manageiitwt projects but uilltrotatcnrd any contradsfor crew dedrt'c gweratt'on.
AUGUST
~ f ~
c ItlillikcrcSrcction MSEGtetchesagreerrtwtin prcrtccple with IticPSCstajf wtrt'ch willallowIhe Conipany to estabtt'sh one or nrore rlort-reglclatedstcbstdtaftes SEPltASER 7'fillikwStation Clavn Coal Demonstration Project r'sselededforftcndt'ng bythefederal Department ofEnergy.
OCTOBER MSEGfilesa nquest withIticPSCfor a 10.8perceittincreasein etedric rates and 134perur itincrease irinatural gas rates eg&iveAugtcst 1, 1992.
Paul Gioia, swior vt'upesttter ttofFirstAlbany Cepornlion and former dtairrnan ofthe PSC is dededto IheBoardofDinctots.
.IIII
~~ItvI Cotumbicc GncAatuNlion NSEG yonsorsa ttcvt-day natuml gas c~econferwcein Binghamton. il/orethan 300jleet operators cetdorsand srcppliersattwd.
NOVE4BER Snttgh Statt'on setsa nero record of322 cetseactt'ce days ofcontimious operatt'ort. 7lxstatiort'sprevtous nmrd ups 246dags.
MSEGsells g150million of8 7/8perurttfirst mortgage bonds Ihe largestsalein IticCompany'shi'story.
7btst'sthe lou@@
corcpon ratefor30ywr bondsissuedby a BBB+ ratarl combination utt'litlin Ilxtast 10ywrs.
Jennt'son Gwerating Station completes t'ts secondsucmfful test buni of tired>ig mhelwitlicoat. 7ttefirst testbunt took plauin lt1ay.
jcruciccmSrcccton'secereiustorm ieace 23500MSKeladrt'ccuslomersuitttoutpouer.
HankslhitisttteLiberty Dt'vr'st'ort. Ittorethan90percertl ofthe acstenersbacellxirporte restoreduithin 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
ELECTRIC OPERATIONS INNOVATIVESCEUBBEETAP COEAKRSTONE OE CLQNAIRCOAPLIANCE 6
0 yl>e Clean AirActAme>idmwtsof 1990is one oftbe n>ost compret>e>>-
sir>epack>gesof en>>>ro>>>ne>>tal legislation er>er wadrdin tt>e US.
'the niostsignf>>'cantpart oftbis legislation to coal-bur>u>>g ulilities such asN1SEG
>'s ?illelVofthe Ameiid>nenes ukicb callsfor nod>'onsin suflur d>'c>ride($0,) and nitrogw oxides (cVO) em>'ss>'ons Our conipliance plan is an ader'on ofour conmiitniwtto safegrrardall oftt>e w>>r'ron>ne>>t-air, rr>ater and land.
c3
)
YSEG's generating system relies on coal.
In 1991, we burned 6.3 milliontons ofcoal ation generatingstations account-ing forover 90pement ofthe electricity we produce.
Coal is an abundant domestic resoutce, so reliance on itcan help spare the nation fromtll prioe and supply whims ofthe Organization of Petroleum Exporting Countries (OPEC).
Unfortunately, burning coal produces SO, which contributes to acid rain. We have manyenviron-mental protection systems already in place, includingelectmt<c ptecipitatois at all ofour coal-fired stations, a coal cleaning plant at Homer CityStation and an SO, removal system at Kintigh Station-the only such@stem in tliestate.
Homer, the Clean AirActAmendments of 1990 willstillhave a significant impact on our generating system.
Specifically, both generating units at Milliken Station and one unit at Greenidge Station willbe affected by the requitments to rnluce SO, and NO emissions under Phase I oftllAmendments, which takes effect on January I, 1995. Allother fossil-fuel generating units willbe affected by Phase II,which takes effectJanuary 1,2000. In all, we are required to reduce SO, emissions by 47 percent and NOemissions by 20 to 50 percent depending on the generating unit.
We began analyzing how we would meet the new emissions limitsin late summer 1990. The process invohel assessment of32 emissions control technologies forour 14 generating units, or 264 options. Technologies included wet and dry limestoneqstems forSO, removal, svitching to lowsulfur coal or natural gas, changingboilen to newcombustion technologies and the possibilityofretiring generating units. Next, the listwas nanoviel to the 30 most costeffective strategies.
Phase I compliance focuses on two stations The final anal@is ofthose
conibine Cera~nand US. iecbnoiogier. Amealuliinproivvnenisaitheplanl willmiliice(he eniiMon ofniirogen acta.
from approximately 85 percent to 95 percent, teplacement ofcoal burners on all remaining boilers and evaluation ofemission control options forHomer Cityin conjunction with Pennsylvania Electric Company, theat>>Mr and operator ofthe facility.
'"Ihroughout the entire process we includel consideration ofthe known and potential impacts ofour demand management program and independentpo>>erpnxlucets, and what Clean Air ActemLsslon allowances might be>>'orth, DeAngelo said.
Atpresent pri05 the cost ofcompliance will be approximately $252 millionbet>>e'en now and 2020.'his includes planned capital expenditutes of$232 million,"Dehngelo said. 11>is willmean an estimated increase in electric rates ofapproxi-mately 1 peKent in Phase I and another I percent in Phase II.
30 strategies yielded the followingcompliance measures forPhase I: construction ofan SO, removal system at MillikenStation, addition of natural gas co-firingcapability on one boiler at Gteenidge Station and replacement ofcoal burners on both generating units at Millikenand one unit at Greenidge to reduce NO, emissions.
"InSeptember we learned that the fnleral Department ofEnergy(DOE) had selected tlte Millikenproject forfunding," said Joe DeAngelo, Clean AirActprogram manager. 'll>at news reinfotoxl our recommendations." Whileour application to DOE requested approximately
$65 million,the exact amount offunding we willreceive for the $ 159 millionproject is still being negotiated.
Compliance measures forPhase IIinclude Improiement ofthe SO, removal rate at Kintigh Burning tire chips solves local landfilldilemma In May and Nomnber, >>e completed test burns oftire dups mixed withcoal in one ofJennison Station's stoker-ape boilers.
Emissions monitoring conducted during the tests, which consumed 300,000 tires, many from a nearby landfill,sho>>txl no increase over normal emissions. Once>>e receive approval from thestate 7
Department ofEnvironmental Conservation, we willbum tired>ips on a regular basis atJennison, thus decreasing coal use and reducing the number oftires that are sent to landfills.
Generating system elllciency remains high In the lgPP8aclricligbt 6 Pouter magazine iankings, the most recent wtuch are complete, NYSEG's generating system ranked fintin New YorkState and sixth in the nation in eiTiciency. Kintighwas the snenth most eficient generating station in the country as itregistered its best heat rate eser. In 1991, we pushed our fossil-fuel 5g heat rate down to 9,$8 British thermal units/
kilowatt-hour, the lomst rate rpraciice willniean reduml Eii l
if~~
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~-
(->>'-(gh gP,',
~
1
~f Sumufiiliesl barer ofiimd)iver niildwd%coal aijennimn Siaiion, iibenpui inio regula coal iiseandeiiniinalion ofiiiousandcoflimibal uouldo(lxrioiseend iipina landfill.
ELECTRIC OPERATIONS DE5$53&MGEUENTCA4VGLVGTAEEACEOETAEELECTNCJ3USNESS 8
0 0
Publicpol cyis dynamic ttdrangesas rue acrluire neru knoruiedge anddeuelopneru tedrnologr'es Some of the most recent dranges ajf'edr'ng tire eledrr'c brrsinessinuolue a new uocabulary that indudes sud) terrrrsas "demand nranagerrrerrt," "r'rrde~rdentpmrer producers" and "rxrmpeliliuebuSing"for rreru generalln.
Aside becrrmeintr'rrratdyfamiliarwilblime nerupublicpolicyinitr'atr'ues ue recogrrizejusl bow mudr tire business r'singing andhow interrse tire focrrsison sauing tire enur'mnmerrt.
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erhaps )uu rmember when utilitiessuch as NYSEG concentrated solely on selling more and more electricity.
Increased sales meant increased mmues, yowth and prosperity. Ihose days are history.
Today the electric business is much more complex Public policystrongly encourages the eficient use ofelectricity and that makes sense.
E6iciency willreduce the amount ofelectricity utilities must generate, thus sparing our natural resources and tllenvironment.
"Recent actions by the Public Service Commission have tmowl the penalty that detemxl electric utilitiesfrom promoting conservat-ionn," said Jack Roskoz, senior vice piesident-Electric Business Unit. These initiatives allow us to recover the direct costs ofdemand management, including rebates and administrative costs, and ofset lost sales. We also recover a percentage ofthe savings from demand management projects tluough an incentive program.
Evidence ofour earlysuccess is already in. In 1991, our demand management programs sanxl approximately 82,000 megawatt-houmof electricity and contributed significantly to earnings. Thanks to a concerted efortby NYSEG marketing reptesentatins across the state, we surpassed our 1991 incentive goal of$ 10 millionby )2.9 million.
NYSEG spent approximately $26 millionon demand management programs in 1991, the largest percentage ofwhidiwas forrebates to large commercial or industrial customers who installed energyWicient lighting and moton.'ihe demand management efort also includes free energy sung'nd rebates on the puKhase of specific energy equipment formidential and ayicultural customen.
Programs increase prices 1he near-term impact ofdemand management programs willbe increased prices. "From a cost standpoint it is expected that, over the longru, conservation
Replacizzg izzeazzdescent ligbtz'ng zeitb longer-lasting energpegident Jluoresoent ligbiingizz residential, ooznnzezcz'al, inrlustrialand agrihzl!ural settz'zzgsismntribuling to a redzzdionin deznand forelectriMy.
programs are less expensive than building new generating facilities," Roskoz said.
Achanging public policy's impact on the electric business does notend there. Utilitiesate tequinxl by the federal Public UtilityRegulatory Policies Act to buy power from qualified indepen-dent pomr producers (IPP). KevYorkState also requires us to paya minimum amount forthe pomr fmm many ofthese IPPs.
Approximately 126 megevatts (mw) ofIPP
" power is aheady on line, another 260 mw is under construction and an additional 39tI mw is
'nder contracL
'"Ihe expectation, again, is that over the life ofthese contracts, which vary from 1$ to 30 or more >@us, there willbe a significant net benefit to our ratepa>e5," Roskozsid.
Utilitiesin New Yorkand many other states are nev also required to seek bids foradditional electric generation needs or demand management projects to satisfy foisted electric demand requirements.
First round ofcompetitive bidding complete InJuly 1990, NYSEG requestel bids for 100 mwofsupply side capacity and 30 mwof demand management.
)Ve recei>el bids inJanuaty 1991. InJuly, after we examined our fotecast of load grwth and IPP construction, itwas determinal that we would not need additional generating capacity until"mllbeyond therm 2000," according to Roskoz, and that awarding the bids would needlessly add to our customers'ost of electricity.'SVe are, heieer, negotiatingcontracts for 17 megmvatts ofcost&ective demand management projects," he said.
Whiledemand management, independent power produce5 and competitive bidding are now reality in the electric business, the issue of transmission access may present the next challenge.
"Transmission access, as generally under-stood, could make the electric transmission system a common carrier," Roskoz sitL "Acomparison has been made to long distance telephone lines or natural gas transmission. 1l>ose comparisons are questionable, he~mr, because it is much more di6icult to contzul pomr flevon an interconnected, altemating current electric transmission system."
Debate continues in the U.S. Congtess.
9 0
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Fluorescent bulbs last as muebas 10 times longer and zzse up to 75penezzt lessened tban tlzeinrandesrent bulbsttzat baoebeen azoundsizzce
'thomas &/imn'slime.
NATURALGAS OPERATIONS OUREOlENDEVEI,OPAKNTOEALTEITIVEEUELSZ4RESEOOT p/
~
jjjj jib j I j itallstartedin California h~eir uritb inipelusfiom tirefederal Clean~'r Act Pnendinentsof 1990, more and morestates, indudingheur YorL, are strongly corrsikring lougber irelrr'de emiMonsstandards.
IVebelieire natural gasis one oflbe alternate fuelslbal iuillcontribute to rediiobig tire irrijractofirelrr'des ori tire erirrr'rorirnent.
,(o l1
) IlsIlgggg='!IgyI "I~IIIIIIII Sdool biisesandottrer fteetstbatdlrartfrom and retuni to ttresame facilityeactr day are primary targets ofour initialnatqral gas vdn'de rnargeting program.
s recently as January 1991, NYSEG's corporate natural gas marketing organization was in its infancy. Just one
>mr before that theie was littletechnical training and no sales training program forour natural gas representatins across the state. Quite frankly, committing the resources needed forour natural gas business to grow was not very important to us.
Anatural gas-po>>etedmhiclepmgramwas furthest fmm our minds.
Oh,>>hat a difference a }ear can make.
"Ijoined tlte Gas Business Unit inJanuary 1991 and I had ne~er heud ofnatural gas vehicles," st Bob Paglia, vice president-gas marketing and sales. "Having litigated the potential market for natural gas mhicles, >>e now have a full-fledged marketing program. We entered the field late, but>>e're catching up inahuriy."
~
Why is compressed natural gas an attractive alternative fuel for icicles?
Primarilybecause it burns much cleaner than gasoline. Compared to a gasoline-po>>ered chicle, amhicle opentingon natural gasemits up to 82 percent less carbon monoxide and up to 86 peKent less fNctlvehpfmcaibons wlilcllcause smog. '"Ihe Clean AirActAmendments of 1990 require that tailpipe emissions be reduced," Paglia said. "Use of alternative fuels is one important way
'jl"ggg<fjjpjgg)f 6)'IHi
'ast October MSRlgensorert atray naluraigas uettide conferencein Bingfzvnton-aflrsl for ulililj'.htoretban 300fteet operators uendors andsuppliers attendedfrom ttnougttout tie US. and several foreigii countries that's going to happen."
We belike natural gas is the safest and most promising alternative fuel because o Maintenance costs fornatural gas >ehicies are markedly lo>>er than those forsehicles with engines that bum otlter fuels.
n Itis abundant and appmximately 95 percent ofthe natural gas we use comes fmm North America. More than halfofthe oil and gaso! ine we use is imported.
o The fuel itselfis less expensive than gasoline.
o Comeision fmm a gasoline-Io>>ered icicle to a vehicle that is upable ofrunning on either gasoline or natural gas is relatively simple, and the vehicle then operates pntctically as itdid before the conversion.
Market has sign16cant potential In addition to all these advantages, we are especially interested in the market because itcould increase our natural gas load by 15 peKent. What makes tliatlllclNscd !031 0'M more attractive Is tllat itwould occur over the entire Iear, not just during the heating smson.
Given all these advantages, why hasn' there been a rapid gmwth in tlie number of natunl gas vehicles? Largely because conveision ofvehicles and compressing naturd gas for refueling are currently expensive. Increasingly stringent vehicle emissionsstandanls and active inmhement of local natural gas distribution companies, such as NYSEG, willbe the catalyst forthosecosts to decline. The market willthen open up.
'Ve have to make sure tliatconveision
~ ~o@~l ~a ISIS fir w
g stations ate in place and that conversion is reasonably priced. We can provide expertise to make those things happen," Paglia st. '"Ihe otlierthing we are trying to do right now is to drive down the cost ofcompression. The reason that itis so expensive is because there is very little competition out them. We don'twant tobe in the business ofdispensingcompressed natural gas by ourselves. Ho>>ver, we do want to spur interest among station owners and major supplie5."
Interest is growing While having a 0
natural gas pump at aery comer gas station or a refueling compressor ately home is hard to imagine, itcould happen in the future. In tlie meantime, conversion of~led "homing pigeon" fleets-icicles that depart from and return to these facilityeach day-has already begun. As an example, United PaKel Service has announced plans to convert its 2,700 deliveiy vehicles in the lmAngeles area to natural gas.
Closer to home, Bmome Transit in Binghamton willbe operating three natural gas-po>>ered buses on a daily basis and we are actively discussing conversion withschool bus and other fleet operators.
We saw further evidence ofthat increasing interest in October when we held the first utility-sponsoied conference on natural gas vehicles.
'lIiebottom line is that there has tobe a price advantage to make conversions happen,"
Paglia said. '%With the reasonable cost ofnatural gas and our determination to reduce the cost of conversion and compression, we expect to deliver that cost advantage."
NATURAL GAS OPERATIONS HPANSIONSANDACQU1SITIONSEIIYTONATURAL GASBUS NISS GROWlF IVilbllznalion's economy incbing lewrdraney, a!lofthe elenients arein placeforgroivtb in if@ natural gas biisiness 7be AnIeriian CPSA59MtlOn estimates tlere I'sa50gear supply (14$ing convenllonal fecovery mellods) in the conlinenlai US.
alone. II vast transtnissionand distribution netivorkisin place, and nalural gasis reasonably
@md. IVeare commitledlo lookingal everyopporlunily, induding additional acriuiMlions lo takeadvanlage os/xm develqoing nrarket condilions
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Holein One Bagel in Breiester is now baking bagetsin natural gas oveiis Breiuler h one of24neivfrancbise areas uvre ueare installing natural gasdistribution slstenis n last)eu's Letter to Stockholders, we outlined brieflythe focus foreach of NYSEG's fivebusiness units. Perhaps the moststrikingchallenge mentioned was for the Gas Business Unitto triple the size ofits business. Ben with the addition of69,000 and roximatel
$32 millionof rati customers app y
ope ng rmmues fornine montl5 in 1991, as the Rsult ofour purchase ofColumbia Gas ofNev York, Inc., the challenge oftriplingnet income by the end ofthe decade remains formidable.
We have made gmtstndes in the last)nr, esped allyin establishing an outstanding organization and training our people and our trade allies, such as appliance dealers and plumbing and heating contnctors," said Russ Fleming, senior vice ptesident-Gas Business Unit. 'Most things have mo~el faster and only a fewslower than I had hoped. We Imevour plan is stillvalid and being able to meetmenl challenges is stillessential to our success."
First among those challenges is the exploration of additional friendly acquisitions. Although the Public Service Commission (PSC) is stilldetermining exactly
how cost savings from acquisitions willbe treated, we remain actin "Itis certainly not deterring us from talking actively withother companies, but it's aslowprocess," Flemingsaid. "Before we willeon consider an acquisition we have to be certain that itwilladd to shareholder value. Otherwise the talks go no further."
Encouraging existing customers to oonvert their space heating and water heating to natural gas, cost-elfective expansions ofour existingdistribution system and evaluation ofpotential nev franchise areas am also critical to gtowth ofthe Gas Business Unit. "We have now identified all large boilets in our service area that do not currently use natural gas and we have completed asumy ofeety house on or near our natural gas mains to determine what the heat souKe is," Fleming said. We are also working in hie dozen nev franchise areas and are evaluating at least 30 more.
Amidthis expansion, we must also focus on improving our load factor. 'AVe are continuing to look at ways to reduce our peak requirements, so that our pipeline charges are spread over a more appropriate average demand on an annual basis," Fleming said.
There are bm main wa>s to do that. Either you bring up the summer natural gas demand orpu reduce the winterpeak" Natural gas air conditioning is one way to increase summer demand, but the reliabilityofsupport services for the equipment that is now available has been uncertain, but is now Improving, according to Fleming.
Conversion ofequipment that can be switched from one fuel to another, such as industrial boilers, and the use of natural gas for generation ofelectricity are other options. 'We ate workingwith the Electric Business Unitand cogenerators," Fleming said. "Cogenerators, forexample, can often increase our load factor during tlte non-winter months and then evitch to number 2 fuel oilduring the winter."
When itcomes to storage, we are innstigatingsevral options. "Storage is important because p>u don' necesmly have to produce natural gas out ofthe ground when pu need it;pu can take itout ofstorage instead.
Storage eliminates some ofthe risk ofproduction," Fleming said.
~ /
I'e~'i P/
u From the mid1800sto le mid 19', gas uns manufacturedbybeatt'ng anlin huge brick ooens One of llew by-productsoftlxs pnxes uas coal far, rebicb uvssoften buriedor leJ?in undergroundtanksat tbe manufacturingshte.
Caal tar is now an environmental andbeattb concern. 1Vearean& tdushy ieaderini~wesligating and darning up sita. One site mtder inoestigation is near this teettandin Outgojust urn( ofBingbamton.
Our natural gas iducleprogram also has excellent potential. Diivrsityoftransportation fuel reduces the risk posed by reliance on imported oiland makes economic sense. '"Ihe largest single user ofthe oilwe import is the transportation sector. Even with the relatively low price ofoil, a significant portion ofour national trade deficit is attributable to imported oil,"Fleming said. In addition, natural gas is environmentally-friendly and reduoes~eu and tear on vehicles.
We are now also looking at integrated resource planning and we want to be a leader in that," Flemingsaid. "Integrated resource planning simply means the capability to integrate the least'upply while managing demand.'Ibis helps the customer by lowering natural gas bills and the shareholder byproviding NYSEG greater market potential."
Ifwe are to reach our goal oftriplingNYSEG's natural gas business, we willhave to evaluate eeryopportunity forgt0wth and quickly take advantage ofthose we belim ate most promising. "It'sgoing to be asttetch, but withsome good planning, proper implementation and the abilityto complete the right acquisitions, we willachieve it,"Fleming said.
DI VF RS IF I CATION PiYOGRESSHASBEENSLOW, BUTOLÃPMVSTODIVERSIFYEQQNEL@f Q
I
)w( />~
o 7g)
><Ii I,S~
).,
/I]I)i--
lip]
'~I 'IIII gIII Il'lip i'll
)IIii n~~ iL(7'ost utililiasacrosst/)e counlry /)a) lestruggle(
w)t/)t/)e dile)nn)a of needing logrow and prayerin a regulated e)lv)ron)ne)lt
)),bereallN)ef relur))
on co))v))on @u)tyis co))trollad. @any
/)ave concluded l/Ntt/)e solution is to operate businessesoutsuleof t/)at regu/ated env)ron)nent. lee agree, but we a/so believe//)at lo be sumoful)veneedto slick lo)v/)atunknow best-energy and environn)ental serv)ces Our investiga-tion ofopporlunilies cont)nues
'thefirstlargeinttependentpoue pr0ttucer pPP) locomeon linein ourseruiceareaisoperatedly Intteck Energy Services. Itsuppliessteam to hforttnt Saltin Silt,e Springs, irear Hornett, andueincy Ibeeledricityilgenerates. Our diumifuationplans callforusto tbor0ugblyinieligate llxOpportunitytopartictpatein lielPP market.
otal shmholder retum-the sum ofdividend yield and appreciation in the market price of shares-is one standard against which we willjudge our progiess in becoming a top utilityby the end ofthe decade. Our challenge is to impiom that return in the face ofamak economy, limited allo>>el return and a low-gmwth service area.
An aggressive stance in natural gas system expansion and additional natural gas acquisitions willhelp, as willthe Electric Business Unit's success in earning demand management incentives.
Hovteer, it is our diversification p!ans that will provide the catalyst forsuccess.
In hlaxh 1990, we flledtw petitions with the Public Service Commission (PSC) asking for permission to inst 360 millionin one or more non-regulated, energy-related and environmental seMoes subsidiaries.
PSC nearing decision on modified petitions Securing approval ofour plans is taking longer than~ but we belike that a revised petition willbe approiei by the PSC in the firstquarter of 1992. This willallow us to move ahead. The anticipated action by the PSC folios an August 1991 agieement in principle with the PSC staff that would allow us to inst approximately (173 million-based on five peKent ofour capitalization-in thesubsidiaries.
'"ihe agimnent also identifies some activities that we can and cannot get into. For example, we cannot get into natunl gas exploration unless it' incidental to the main activityofthesubsidiary,"
said Bernie Rider, senior vice president-Stntegic Growth Business Unit "Italso includes provisions for a positive benefit payment to ntepa)ers based on our level ofinmstment in the subsidiaries."
We willconcentrate on three fields Although our timetable has dtanged, our plans for unregulated subsidiaries have not. We willstillfocus on environments laboratory and consulting services, nonutilitygeneration ofelectricity and emissions management.
Business plans for these three opportunities ate being cuefully revieiel to determine iftheir strategies ate stillappropriate in lightof recent market changes.
An example ofsuch a market change is evident in emissions management. We had anticipated coal-burning electric utilitiesscnm-bling to install flue g@desulfurization sIstems, or scrubbeis, to meet the requirements ofthe Clean 15 AirActAmendments of 1990. Some scrubbe am under construction; homer, many ofthe affected utilities ate planning to switdt to lowsulfurcoal.
"Ilave we missal some opportunities? Yes, we ham," Rider said. "Hmmr, we ate actively discussing opportunities withenvironments labs and the independent power producer market.
Although the emissions management market has not dnvloped as quickly as we had envisioned, it maybe a veiy interesting market later in the '90s."
Once we secure PSC approval ofour plans, we must return to the NYSEG Bowlof Directom to request permission to prmed. The groundwork is in place forthe organization that willmake unregulated subsidiaries a reality, but significant work f6llalns.
'WVe are using a search firmto identify candidates forpositions that we belike need to be filledfrom outside the Company, and we expect to dnw some tedinical expertise from NYSEG," Rider said. "1992 willbe a very exciting>eu."
l1 If lVYSEG,BOARD OiF P:IRECTORS First)ear elededbi parentheses l
)
~
Former Chairman and CIdefErteeuttte~ioer of the Ceporalion Bingbamlon, hY Eisserr A. Cmice (19SO)
Former Chairman ofthe Board and CbtefEreetake +iotr
?behatteral Bartband Pusl Company ofhbrukb h'orukb hY ME. Lrsus (19S7)
Prost'deril Kfndester Optteal Company (Planufadurer ofb)egtasm)
Fjmira, hY i~
mA.ceus i6r3i Chairmarr, Prestdertt andChkfEreeutrl e
, Ogxer ofibe Ceporatrbrt Bingbamtei, hY Pus L Gioss (1991)
Senor 1icePre&&it FirsthlbanyCorporattet Albany, hY Asses G. blosisiu. (1971)
Settlor Fellee h0son A, Rodefeiier brstrtute ofCoiernment Albany, hY Dam LNesaxis (1979)
AusoM P. Gsem (1979)
Dean ofthe Graduate
- Sdooi, Contell Iirrttersity ithaca, hY
)arN bl. Kmn (19S9) hianaging Partrrer Il&tman,Iiourtrd8 IItadi (Attorrtersal Lau)
Bingbamion, hY Former Preddertt and s3tefErteuttre Ogioer BuffaloForge Company (h!anufadurerof Iteating, VerNlatirrgand Air Ceulitioning Btiurpment)
Buffalo,hY Eam D.
Diaz'1971-1975; 19S3)
Former Free Iartee BeeromicReseardrer Brairiard, hY Auns E Ke~ (1987)
Former President and Cbief~ating /)O'er ofthe Ceporatr'orr Bingbamton, hY c.
Rorarr A. Pire (1)
Pressed NÃlsCogege Aurora, hY CONNITTEES OF THE BOARD Cbatrperser listedjirst Audilehretteomb, Dt'dtt'ruet, Kvler, PIane Eveculiee and Financer Allen, Camgg, Casarett, Cilmottr, Nnttgb, hetteomb, Siuarl
&ecullre Compensallon and Succession:
Gilmour, Allen, Casardl, htnligb, hreueomb, Siuarl Pension: hlarsball, Rseier, L)stcb, Plane Public AJIalrsr Dickinson, Ciokr, Lyttcb, hlarsball, Sluarl hlr. Camggis an tot oculo member oflbe Pertslon and PublicAj@irs coinmiitees.
C. Wiusw Sssier (197!)
Chairman and Cbief&ecutite+~
C W. Stuart B Co., Ine.
(Interstate 7)rtdrirtg Concern) h'eurtrk, hY
'FFICERS
/
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.:'IIINISVCIALSECTION, i
A 1
C Nanagements5tscttsst'onandAnaly8
- ofFinancial Condilion and Resuitsof Operalions,......,.. 18 Consoit'dated2utementsoflnconte
........;...............',...,.23 CNtsoit'datedBalarice Street.........<<....................,...24 CotmlidatedStatementsof Cash Floras.........<<.......,..;....26
~
Consolt'datedStatementsof Ckrnges
=
in Common Stock Equily..,
27 I
'otesto.Conmit'datedFinandalStatemenls
................-.28 h
R~ofNanagement...h..........'..38 Reportof1ndependentAccountants....,........;
.....i..........38
'SelectedFinancial Data............,
r
..39 l
Clossar)t i
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x
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i 39
......4'0
'4l FinancialandOPeralirig Stalislics...:.....
Finaitct'al2alislics.:
It Elbert'cSaiesStatt'stt'cs.
~
42 h
8actric Ceneralion-Stalislia g3 ~
44, Natural,CasSaiesStalislics.
~Relimletlecttre
, Dece<<nber31, 1991.'burtesB.
- DfckNn, Bingbamttm Otifsfon manager<<gus~
ifcepreskbit-etttonat @is operations
't tbePnuap3, 1992 meetfntt oftbe BeardofOtnctNa E,
/
t,g Rec3cjedPaper
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and>evsafseiifceasofttece<<<<iber31, 1991 inparentbeses James A. Canigg (58, 33),
'- Chairman, Pnridentand CbfefEcecutiI<<eotllcer Gerald F Putman ()1,21)
EucutiirAssfstantlo tbeChairman,'nrident and CbfefEcecutiee Oflicer Dolores R IHx (60, 33)
Assistantlo tbe Cbairman, President and CbfefEcecuticu Opiner' Assistantsecretary
'I EISCTRICBUSINESS UiVIT Jack II. Roskoz (53, 29)
Senior VicePesfdent James A. Ackemian (63, 39)
Vice resident '- East Region EAeric Operateis John J. Bodhn (46, 23)
VicePesffdk-Electric yinnsmfssfon aiutlfstribution WilliamG. hicCann (44, 22) ~
VicePesident - IVestRegfNi Bectrfc Operations Vincent W. Rider (60, 33)
Vice President- &ieratei Irene hi. Stillings (52, 15)
VicePest'dent - Electri'c hlarkel&ig Michael J. Turkotic (59, 36)
Vice ~
- Purchasing andAdmfnfstratei Dcnis F Wickham (42, 19)
VicePesfdent Electric R rourcePlanning
'John L Fiala (55,33)
Assistant VePnrfdent <<Pknit Operatei's
)ohn V. Kutz (57,35)
Assistant VicePresident - yiansmisset and KWbutet Operateis GASBUSlhESS UNIT Russell HomingJr. (53, I)
Senior ViceAefdent I 4 Orlin W. Darrach (63, 33)
'ice Pnsident-Regeiat GasOperateis
. '*Rob'crt A. Paglia (54, 26)
C VicePnridenl - Gashfarketiiig and sales IIIANAGEhIENTSERVICESBUSINESS UNIT Richard P. Pagan (50,'20)
Senior Vicepiefdent Daniel W. FarIcy (36, 10)
, IycePresident and Secretary Carl F.Johnson (49, 25)
VicePresideiit-Consumer Sen<<fcesand Communfcatioris Richard W. Page (56, 33)
VicePrestdent - Iluman Resources Shensood J. Rafeity (44; 11)
ViuPresident and yhmurer (CbiefFinancial Ojilcer)
Everctt A, Robinson (48, 18)
Vicehekknt and amtrotter (CbtefAccounting Ojfim)
John D<<Scott (53, 28)
'ice Pesfdent - Economics.
Roy Hogben (52r34)
Assistaiit Conhrofter-
- J~cshl.nicfc (61,'P6)
Assistant Secretary Robert T. Pochily (42, 20)
Assistant Treasurer Gary J. Turton (44, 19)
Assistant Controller SIRITEGIC GROIITHBUSINESS UNIT-Bernard h1 Rider (60, 31)
Senior VicePest'detu STRATEGICIIIANAGE<<IIENTBUSINESS UNIT Paul Komar (53, 22)
, Senior VicePnridenl
h M15iGEMENT'S DISCUSSION,LVD AhMLYSIS-OE E1MVCLQ CONDITIONAlVDRESULTS OE'OI'EQUATIONS
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RESUI.TS OF OPERATIONS
" 18 0
1991 1990 1989 Operating reienues Earnings available for common stock Average shares outstanding Earnings per share Dividends per share
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r
- On. April 5, 1991, the Company purchased Columbia Gas of New York, Inc. (CNY) from The Columbia Gas System, Inc. (CGS), CNY's parent company. The Company paid CGS ap-proximately $57 million-to purchase all of ttte common stock of CNY and all of the out-
.standing debt of CNY due to CGS at. face value (See Consolidated Statements of Cash Flows - Inn@ting Activities).
~The purchase of CNY represented a major boost for the Company's natural gas, businm
~
and a significant milestone in the Company's effort to triple the size of that business by 2000. CNY added approximately 69,000 natu-
'al'gas customers,-an increase of more than 46Ato the 148,000 the Company already served. This acquisition was an excellent
, 'atch for the Company since four out of five CNY customers were already electric customers of the Company.
~ The acquisition was accounted for as a purchase and, accordingly, operating results '
of CNY have been included in the consoli-dated operating results of the Company since the date of acquisition. The acquisition of CNY did'not have a material effect on the Co'mpany's 1991 results. of operations.
On June 28, 1991, members of the Inter-national Brotherhood of Electric Workers ap-prove'd a new three-year" contract with the Company. The contract provides-for, among =
other things, wage increases of 4.5%, 4.7%
and 4.9% on July I of each )ear beginning with 1991.
)
(Tbottsaads,evcept Per Strare Amorttrts).
$ 1>555)815
$ 1,496,780
~
$ 1,427,745
$ 148,313
$ 145,351
$ 144,804 62,906 58,678 57,138
$2.36
$2.48
$2.53~
$2.10
$2.06'
$2.02
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1991 Compared Nttth 1990
'perating revenues for 1991 rose 4X 'over 1990 primarily due to an incre'ase in electric and natural gas,rates effective February 19(I and'the acquisition of CNY.
The decrease in earnings'per share from
$2.48 in 1990 to $2.36 in 1991 is primarily due to the reduction in the Company's al-IiNed return on equity fmm 13% in 1990 to 11.7% effecti>e February 1991, in accordance with the rate decision issued by the Public Service Commission of.the State of New York (PSC) in January 1991 (See Uquidity and Capital Resources; Regulatory Matters), Eam-ings vere also adversely affected by lower electric and natural gas retail sales as a re-sult of warmer iieather and the weak econ; omy. Eamlngs were favorably affected by Incentiies earned for conducting efficient de-mand management programs.
'Ihe increase in aierage shares outstanding was primarily due to the issuance of four million shares of common stock in October 1990.
1990 Compared Ntttb 1989 Operating revenues increased 5% in,'1930 as compared to 1989 primarily due to the recognition of unbilled revenues.
In 1989, the-Company recorded an adjust-ment to the 1987 Nine hiile Point nuclear generating uhit. No. 2 (NhiP2) write<ffwhich increased 1989 earnings
$5.8 million, or 10 cents per share, net of the federal income tax effect. The increase in earnings from $2.43 per share in 1989, excluding this NhlP2 ad-'justment, to $2.48 per share in 1990 is pri-marily due to higher purchased natural gas costs and electric production costs during, the unusuallI cold December of 1989. The related revenues were not recognized until early 1990 when the meters vere read.
Incentins earned for efficient demand
~
management programs also, contributed to the increase in earnings.
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C 1
Operating Resttlts by Business Unit Electric 1991 1990 1989 (T/10Nsal1r8) 13,197,673 13,055,126
$ 1,334,509
$ i,266,668
$ 1,033,646
$961,128 Retail Sales (kwh)
Operating Revenues Operating Expenses
'13,107) 115
$ 1,367,936
$ 1,065,830
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1991 Compared reith 1990
'perating revenues rose 3% primarily due to an, increase in rates effective February 1991 and an increase in certain New York State gross receipts taxes passed on to the ratepa)ur.
The increase in revenues is in spite of a 1%
decrease in retail sale.
Operating expenses increased 3% primarily due to an increase in certain New York State gross receipts taxes and federal income taxes that increased due to higher pretax book in-come.
1990 Compared teith 1989 The 5% rise in operating revenues is pri-marily due to the reugnition of appmx-imately $43 million of unbilled revenues.
Retail sales increased 1% primarily due to an, increase in retail customers, partially offset by lower industrial sales due to the slowing eunomy.
The 8% increase in operating expenses is primarily due to federal income taxes which rose because of the passback to customers in 1989 of previously defenel excess federal in-come taxes. The passback resulted from the reduction in the statutory federal income tax rate from 46% to 34% and higher pretax book income. Other operating expenses in-creased due to Nh(P2 operating and mainte-nance expenses.
A'atural Gas 1991 1990 1989 (Tborrsands)
Deliveries (dth) 41,798
,33,672 35,348 Retail Sales (dth) 29,570 25,515 26,495 Operating Revenues
$ 187,879
$ 162,271
'161,077 Operating Expenses
$ 178,210
$ 147,777
$ 153,884
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1991 Compared suith 1990 1990 Compared reith 1989 Operating revenues rose 16% and deliveries Operating reunues increased 1% primarily increased 24% due to the acquisition of CNY.
due to an increase in the cost of purchased Excluding CNY, retail sales decreased 7% pri-natural gas passed on to the ratepa>zr. Retail marily due-to warmer isuather and the vuak sales decreased 4% primarily due to warmer economy. Excluding CNY, operating reunues than normal ueather.
decreased only 4%, in spite of the 7% decrease Operating expenses decreased primarily due in retail sales, because of the increase in rates to a decrease in purchased natural gas costs effective February 1991.
as a result of a decrease in gas purchases, Operating expenses increased 21%. A signif-partially offset by an increase in unit gas icant portion of this increase resulted from costs.
the acquisition of CNY.
Interest Expense Interest expense, before the reduction for AFDC-borroviel funds, decreased 6% in 1991 and 4% in 1990. Interest on long-term debt decreased in 1991 primarily due to the refi-nancing of certain hlghmupon long-term debt at a lower cost. Interest expense also de-creasel in 1991 due to a decrease in the weighted average interest rate for commercial paper (See Liquidity and Capital Resources-Financing Activities). Interest expense in 1990 decreasel due to the nIinancing of certain high~upon long-tenn debt at a lower cost.
LIQUIDITY'NDCAPITAL RESOURCES 20 0
from the isuance of 969,941 shares of com-mon stock through the, Plan. Earnings re-tained in the business vere approximately $ 16 million in'1991.
r
".Re Company intends to further impmve its capital structure through the sale of up to
-.five million shares of common stock in March 1992. That sale will'increase the,com-mon equity ratio to approximately 42 percent, the highest lewl since the Company was es-
'ablished as an independently-owned utility in 1949 Dividends paid in 1991 increased 12.1%
~ owr 1990 reflecting the increase in common and preferred stock outstariding and an in-
'rease in the common stock dividend from
$2.06 to $2.'10.
Embedded Cost, of Long-terna Debt.
I.IX the Agreement In Pnnciple, which is expected gn the first quarter of 1992.
The Financial Accounting Standards Board Issued Statement of Financial Accounting, Standards No.F 106, Emplo>vts'ccounting for Postretirement-Benefits Other Than Pensions (SFAS 106), in December 1990. SFAS 106 re-quires that the Company accrue a liabilityfor estimate'd future postietirement benefits during an emplo)ve's working career rather than rec-ognize an expense when benefits anI paId.
6L9 59.5 522 10.4%
32,7 352 9.7x 9.2%
9.1%
&7%
&4%
SFAS 106 is effectiw for fiscal')vars beginning after December 15, 1992.
The Company intends to adopt SFAS 106 prospectiwly in 1993 and-estimates that the additional liabilityit will be'requiml to ac-1 crue is approximately $ 166 million. This ad-ditional,'liabilitywill be amortized to expense over 20 years. As a result of'this amortization, tretf ment benefits cost will increase b 1987 19ss 1929 1990 1991 0 Long-term debt CI Prefemd stock UCommon'stock equity In Noivmber 1991, the Company issued
$ 150 million of 87/s% Series first mortgage bonds due 2021.. Net proceeds from the sale were used for the redemption in December 1991 of $85.7 million of the Company's 10s/s%%d Series first mortgage bonds due'2016.
'Ihe balance was used to repay commercial
'aper.
The Company redeemed the remaining
$20.4 million of those 10'/s96 bonds in Febru;.
aiy 1992 through a sinking fund provision in its mortgage. The refunding of those bonds will saw approximately $600,000 annually in interest costs. The Company previously re-deemed in February 1991, at par, through a sinking fund provision in its mortgage,
$ 18.9 million of those 105/s% Series bonds.
The Company issued $ 100 million of 8.95%%d prefenel stock in February 1991 to re-pay commercial paper and to strengthen its capital structure.
The Company improvel ifs common equity.
in 1991 through the Dividend Reimvstment and Stock Purchase Plan (Plan) and earnings retained in the business.
During 1991, the Company receiwdrapproximately
$24 million 19&1 19&5 I+
yV I9S&
1929 1990 I99I The Company's embedded cost of long-term debt is now only 8.4%%d compared to 1984 when it was 11.1%. Although it will be diffi-
, cult to improw from the 8.4X lewl, all op-portunities will be puisued aggiessiwly.
The Company uses interim financing in the form of short-term unsecured notes, usu-
. ally commercial paper, to finance certain re-
,fundings and construction expenditures, and, '
.for other corporate purpose's, thereby providing'<<
flexibilityin the timing and amounts of long-term financings. The Company had approx-imately $ 104 million of commercial paper outstanding at December 31, 1991, 'Ihe weighted awrage interest rate during 1991 was 6.2%%d.
'Ihe Company 'also has a revolving credit
.agreement with certain banks which pmvides for borrowing up to $200 million through pos re Y
approximately sewn times the 1991 amount.
The PSC staff is in the process of dewloping
'a policy statement related to the accounting and ratemaking treatment of postretiiement
'enefit costs.,'Ihe policy statement is expected to be finalized prior to the effectiw-date of SFAS 106. 'Ihe Company beliews that the adoption of SFAS 106 will not haw a mate-rial impact on its results of oper'ations or financial position because any increase In ex-pense should Ultimately be recoveiel in Iates.
Historically, rate recovery has been autliorized for postretirement benefit costs as they are incurred.
The Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109), in February 1992. The Company,beliews that the adoption of SFAS-109, which is effective for fiscal >vais begin-1 Recent Developments In August 1991, the Company and the PSC ning December 15, 1992, will not haiv, a staff reached an agreement in principle m'aterial effect on its,results of operations or (Agreement in Principle) which would allow financial position since the Company h'as the'Company,to establIsh~ one or more non-already adopted Statement of Financial regulated subsidiaries.
The Agreement in Prin-Accounting, Standards No. 96, Accounting fo ciple would allow the Company to inwst,an I'0"I'0"I'xceed an 'ggregate 'I>>'I, l7tnanCtng ACtMtteS-consolidated capitalization (approximately
~
~
The Company is committed to further im
$ 173 million at December 31, 1991) in one proving its capital structure and reducing its or more subsidiaries that may engage, or in-
'mbedded cost of long term debt Capital wst, In energy-related or environmental serv structure and embedded cost of long-term Im busin~ and pmmde reland RMm.
d bt m p~nud rehl~iy b low.
The Company plansrto form one or more subsidiaries once it receiws PSC appmvai of Capital Strrrchire
h
". July 31, 1992. The'Company did not have any outstanding loans under this agreement at December 31,-1991. The Company is in the process of negotiating a'similar agree-,
ment with certain. banks. for the same amount to become effects August 1", 1992.
dmg program, the Co Capttal gxpenditnres-The Company's 1991 construction program able by November I totaled approximately $246 million:Most of the expenditures were for the extension of The following tab service and for impro'I'ements,at existing facil-ities.-Construction expenditures for 1987-1991 and revision, and act and forecasted-expenditures for 1992-1994 are tion of addifional re presented graphically below.
Constnrction Evpenditgres (hfillions ofDollars)
(iillllions)
$244
$273
.. 124, 223 (32)
'78 Internal sources Long-term financing'ncrease (decrease) in short-term debt
$211 155 (16) 728 502 30 h
million of IPP generation for the years
- 1992, to recover the, costs asso'ciated with these con-1993 a'nd 1994, r'espectively. The Company es-
" tracts from its ratepa>mrs since the program,is timates that over the next tw to three >ears, mandated by the PSC. The Company will use electric rates per kwh could Increase hetman competitive bidding in the future as electric 10 and 15 percent as a Nuit of purchasing'eeds arise, to minimize the economic im-IPP power.
~
i pacts on ratepaprs of adding new electric As a @suit of the PSC's competitive bid-power mources to its system, while maintain-mpany is contracting for ing the Company's current Imi of s)stem.re-
~
ion projects to be avail-liability, 994. The Company expects k
le provides information on the Company',s estimated sources and uses of gh 1994. The Company's construction program is subject to periodic review ual construction costs may vary because of revised load estimates; imposi-gulatory requirements and the availability and cost of capital.
1992 1993 1994 Tolal 211 281 Total Uses of funds Construction Cash expenditures AFDG Tolal Working capital and 'deferrals Demand management program costs (net)
Retirement of securities and sinkin fund obli ations
$350
$336
$574
$ 1,260
$267
$270
$302
$839 8
11 13 32 275 281 315 871
. 20 2
12 34 27 25 19 71 28 28 228
.284 Tolril
$350 '336
$574
$ 1,260 I+
19SS 19S9 tg) 1991 1 g 1/3 tg9f*
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ o ~ ~ ~ ~ ~ ~ ~ ~ ~ I~
'h
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ h ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~
~
As shown in the pre'ceding table internal sources
'of funds represent approximately 85% of LJ Forecast construction expenditures for 1992-1994, or approximately 70% after adjusting for working capi-Construction expenditures for 1992-1994 tal and deferrals and demand manageInent program costs.
will be primarily for the extension of service, improvements at existing facilities and corn;
(
pliance with the Clean Air Act Amendments of Bnery -'fffclency Programs
'992, seeking PSC approval to continue im-1990 (see Environmental hiatters). The Com-The Company has implemented conseiva-plementation of those programs which have pany has no plans to build another large tion programs referred to as demand manage-demonstrated cost eIfectiimess.
base-load generating plant. Increased electric-ment (DM) programs. In 1990, the Company
~ ity.demands will be met through more effi; recelieI approval from the PSG'for a plan to Bnvlronmental Natters cient use of energy (See Energy - Emciency obtain earnings Incentive for conducting efii-
'Ihe Company asses+
on an ongoing Programs), generation from independent cient Dhl programs. Those incentins are cur-basis the measures that may need'to be taken pomr producers (IPP)and electric resources rently limited to.75% return on equity to comply with environmental laws and regu-(supply side projects and conservation pioj- 'llocated to electric operations: The tw->ear lations governing hazanlous wastes, air qual-ects) obtained through a competitive bidding 1991-1992 Dhi plan, which >as been approved ity, water quality, land use and solid waste pfogMll.
by the PSC, contains approximately 20 large-disposal. Compliance programs necessary to The Company has under contract and on scale programs including financial and tech-meet existing and future environmental laws line 126 megawatts (hlW) of IPP power gen-'ical assistance to various customers. =,
and regulations will increase the cost of elec-eration, of which 110 hIW is installed depend-In 1991, approximately 82 million kilo-tric and natural gas service by-requiring able maximum, net capability, In addition, watt-hours (kwh) were, saved by customers changes to the Company's pperations and fa-another 260 MW of IPP-power is under con-through programs that cost the Company ap-.
cilities. Historically, rate recovery has been struction and an additional 394 MW is under proximately $26 million. The 199+1(92 plan authorized for the costs of compliance with contr'act. During 1991, the. Company pur-anticipates approximately 125 million kwh of environmental laws and regulations incurred
-chased approximately $30 million of IPP gen-savings in 1992 through a program costing gaby the Company.
eration. The Company estiniates'it will approximately $37 million. The Company will The Company may also incur costs in purchase approximately
$86, $286 and
$349,.be'filing the two-year'993-1994 plan in hiay connection with legal proceedings commenced-h h
by governmental bodies arising out of the dis-posal of hazardous wastes by the Company or its predecemrs.
The Company has been noti-fied by the Environmental Protection Agency and the New York State Department of Envi-ronmental Conservation that it is. among the potentially responsible parties who may be li-able to pay for costs incurred to remediate certain hazardous waste sites. Any liability may be joint and several for certain of these sites; The ultimate cost to remediate these sites will be dependent on such. factors as the existing technology requir61 for site cleanup, the remedial action plan selected and the ex-tent of site contamination and the portion al-tributed, if any, to the Company.
As a result, the Company is unable to estimate the extent of possible remediation costs. 'Ihere I's cur-rently no clear precedent with the PSC for rate recovery of these t)Ix5 of remediation costs. However, the Company expects to re-cover the expenditures, if any, it incurs in rates, since the Company has been allovei by
'he PSC to recover similar costs (e.g., inwsti-gation and clean-up costs relating to coal tar sites) in rates in current and prior years.
The Clean Air Act Amendments of 1990 (1990 Amendments) will result in significant future expenditures for the nxluction of sulfur dioxide, nitrogen oxides and possibly toxic emissions at several of the Company's coal-0 fired generating stations. Under the 1990 Amendments, the Company must reduce its annual sulfur dioxide emissions from approx-imately 138,000 tons in 1989 to, approx-imately 74,000 tons, or 47%, by 2000. The Company estimates that the cost of complying over a 25-year period with the sulfur dioxide and nitrogen oxide limitations in the 1990 Amendments is approximately $252 million, on a present value basis, for all capital and operaling and maintenance expenses.
The cost includes
$ 159 million for an, advanced flue
. gas desulfurization (FGD) system expected to be completed in 1995 at its Mflliken Generaling Station.
In September 1991, the Company was se-lected by the Department of Energy (DOE) to receive federal funds for this system. While the Company requested approximately $65 million from the DOE, the exact amount of the funding has not yet been decided. In ad-dition, the Company expects to-receive fund-
- ing totaling up to $ 15 million from other sources. The cost of controlling toxic emis-sions, if necemry, cannot be estimated at this time. Regulations may be adopted at the state levl which would limit emissions eon fur-ther, with an additional cost to the Company.
The Company anticipates that the costs in-curred to comply with the 1990 Amendments vided for a 12.N return on common equity will be recoverable through rates based on previous rate recovery of environmental costs
" required by governmental authorities. 'Ihe Company also estimates that a 2% electric rate increase will be required for the cost of rslucing sulfur dioxide and nitrogen oxides emissions.
The 1990 Amendments require the Envi-ronmental Protection Agency to allocate an-nual emissions allowances to each of the Company's fossil fuel genenting stations based on statutory emissions limits. An emis-sions'llowance represents an authorization to emit, during or after a specified calendar
)ear, one ton of sulfur dioxide. During Phase I, which begins on January I, 1995, the Com-pany estimates that it will have allowances in excess of the affected coal-fired generating stations'ctual emissions. The Company is considering various methods of utilizing or selling these excess emissions allowances.
During Phase II, which begins on January I, 2000, the Company estimates that the ann'ual tons emitted by its fossil fuel generating stations will equal its annual emissions allowances.
Regulatory Natters In 1990, the Company receinxj approval
~
from the PSC for a plan to obtain earnings incentin5 for conducting efficient DM pm-grams. 'Ihose incentives are cunently limited to.75% return on equity allocated to electric operations (See Energy - Emciency Programs)
In January 1991, the PSC approved an electric rate increase of $50.3 million annu-ally, or 4.4X, and a natural gas rate increase of $4.5 million annually, or 2.8%, which be-came effective in February 1991. 'Ihose in-creases were the first electric and natural gas base rate increases since 1986 and 1985, re-spectively. The Company was also allo~el to recognize
$34 million>and $4.3 million of unbilled revenues for electric and natural gas, respectively, during the rate year ended January 31, 1992. 'Ihe Company will recognize
$8.3 million of unbilled ree-nues, betvmn January I, 1992 and July 31, 1992. 'Ihe remaining unrecognized unbilled revenues, which are expected to be signifi-cantly lower than the 1991 amount, will be
'ecognized pursuant to future rate decisions In January 1992, the PSC staff recommended a $643 million, or 4.6%, electric rate increase and an $ 11 million, or 4.4%, natural gas in-crease. 'Ihe PSC staff also recommended an 11.33% return on common equity. In Febru-ary 1992, the Company revised its electric rate request to $ 115.3 million, or 8.3%, and its natural gas rate request to $ 17.2 million, or 6.9%. These revisions were based on certain adjustments and updates to the Company's August 1991 filing. The Company did not re-vise its requested return on common equity.
A recommendation from the administrative law judge is expected in May 1992, and a fi-nal rate decision is expected from the PSC in July 1992. The Company is unable to predict the outcome of this proceeding.
On h1ay 14, 1991, the PSC issued an order approving an Agreement (Agreement) ben~zen the Company and the PSC staff which settled a proceeding instituted by the PSC to investi-gate the reasonableness of the Company's emission control strategies, related fuel prac-i tices and other issues at the Homer City gen-erating station (Homer City). The proceeding result61 from a PSC staff audit report issued in March 1989, which alleged thai the Com-pany's ntepa>mrs may have paid excessive fuel costs at Homer City. The Agreement, among other things, provided for a rate base disallowance for the Unit 43 section of the Homer City Coal Cleaning Plant (HCCCP) of
$20.6 million, $ 13.1 million net of the federal income tax effect, which will reduce the Com-pany's rate of return over the life of the asset.
'Ihe Agreement also provided for a six-month elec'tric rate moratorium (Rate Mor-atorium) beginning on February I, 1992. The ultimate effect of the Rate Moratorium on earnings will be dependent on such factors as the elfect of the economy and weather in the service area, the fluctuatio in interest rates, cost containment measures adopted to offset the impact of the Rate Moratorium and what rates the PSC would have allowel had the Company filed for new rates to become effec-tive in February 1992. The Company estimates that the effect of these factors w'll result in a decrease in earnings of approximately $ 16 million in 1992.
Due to a change in operational strategy, the Company determined that a portion of would probably no longer be used.
As a result of this determination in October 1991, the Company recorded a writmffof $ 5.6 million,
, $3.5 million net of the federal income tax effecL The January 1991 rate decision also provided the disallowel Unit P3 section of the HCCCP for an 11.7X return on common equity.
In August 1991, the Company filed with the PSC for an electric rate increase of $ 150 million, or 10.8%, and a natural gas rate in-crease of $32 million, or 13.4%, to become effective on August I, 1992. Those filings pro-
r
.J r
CONSOLIDATED STATEAL6NTS OE INCOAK
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~
~ ~
I
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ U ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
U I
=
Year Ended December,31 1991 1990 1989 OPERATING REVENUES Electric -
~
Natural as TOTAL OPERATING REVENUES (Thousands except Per Share Amounts) '
$ 1,367,936
$1/34,509 r '1,266,668 187,879 162,271 161,077 1,555,815 1,496,780 1,427,745 OPERATlifG EXPENSES Fuel used in electric generation (Yote I)
Electricity purchased
. Natural.gas'purchased.
(Yote I) hfaintenance r
Depreciation (Note f)
Federal income taxes (Notes,1 8r 2)
Other, taxes (Note 10)
Other o ratin e
nses 274,877 45,808 99,528 110,131
. 152,380
~,. 94447 178,185
-288 684 274,245 34,613
- 88,589 106,665 147,659 89,577 158,770 281,305 279,07.5 26,019 101,598
'7,420 148,375 64,489 146,605.,-
251,431 /
TOTAL OPERATING EXPOSES I 244 040 1,181,423 1,115,012
-OPERATING INCOhfE OTHER INCOME AND DEDUCTIONS AFDC - other arid non~h return (Note I)
Other - net Ur 311,775 315;357 U
- 2,543',
698 12,853'
.10 270 312,733
=,
1,374 18727-
=J
-~
INCOME BEFORE INTEREST CHARGES 327,171 326,325
~
332,834 INTEREST CHARGES Interest on long-term debt Other interest AFDC - borrottef (Ntfte I) 151,649',
11,877 (4,998) 158,209 164,573 15,181
=
15,495 (5,078)
(5,013)
-168,643 158,013
'57,779 20,330 12,662 12,975 h,ET Ir COMEt PREFERRED STOCK DMDENDS INTEREST CIIARGES-NET
.158 528 168312 175,055
/
23 Cl EARNINGS AVAILABLEFOR COhfhfON STOCK
'EARNINGS PER CHARE
$ 148,313 '
$ 145,351
=
$ 144,804
$2.36
$2.48
-$2.53 AVERAGE SHARES OUTSTANDING
~ I ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~
62,906
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
58,678 57,138 I
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
The aooomparrtfng notes on pays 28 through 37 are an Integral part of the Itnandal srtaternents.
U r
P
-CONSOLJDATSD BALANCESHEETS
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ I~ 0 ~ ~ ~ ~ ~ ~ 03 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
December 31
-ASSETS
~
, UTILITYPIANT, ATORIGINALCOST (NOTE I)
Electric (Note 7)
- Natural gas
'ommon 1991 1990
- Pliorrsands)
$4,421,839, I
$4,279,925 3i7;694,"
213,964 156,342.,
. 145,811 Less accumulated d
reciation 4,895,875 I 309 829 4,639,700, i,I74,65I NEI'TILITY'PLANTIN SERVICE Construction.vturk in ro TOTAL IJ11UTY PLANT OTHER PROPERTY AND INVESTMENTS CURRENT ASSETS Gash and'cash equivalents.
'Special deposits.
Accounts receivable, net (Note I)'uel, at ai4rage cost hlaterials and supplies, at-average cost Prepayments
-Accumulated deferred federal income tax bendits (Notes I & 2)
Unfunded future federal income'taxes (Notes. I, & 2)
=TOTAL CURRENT ASSETS 6,718 7355 110,010 70,834 51,225 27,s44 22,245 is,60i 11,463 133,338 66,602-51,736 37,019-16,278 22.659.
23,060 357696
~
~
319291 3,586,046
',465,049 166 815 126,041 d
3 752 861 -:
3,591,090 565si 56,447 DEFERRED CHARGES (NO+ I)
Aocumulated deferred federal income tax benefits-(Note 2)
Unfunded future federal income tax'es (Note"2)
,Unamortized debt expense Other
,,83,718 413>586 91>850-168,544 s6,596 425869 87,286 II71$52 TOTAL DEFERRED CHARGES TOTAL'ASSETS
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~
~ ~ ~ ~ ~ ~
~
~
1 ltra acdortpanylng notds on pays ZS thmugh 37 757 698r
'70,603
$4,924,s36
$4,737,431
/
~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ t ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
are an fntegrat part of the linandal staternrnh.
r
'a
r CONSOLIDATED BQANCE SHEETS
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~
k
~ ~
~ ~
~ ~ ~ I
~
~
~
~
~
~ ~ I ~
December 31 CAPITALIZATIONAND LIABILITIES CAPITAUZATION (NOTES 3 & 5)-
Preferred stock redeemable solel at the o tlon of the Com an Preferred stock sub'ect to mandato redem lion uirements Common stock equity Common stock ($6.66a/s par value, 80,000,000 shares authorized.
, and 63,400,238 and 62,430,297 shares issued and outstanding at December 31, 1991 and 1990, mpectively)
Capital in excess of-par value t
Retained eamin Total Common Stock E ui II'term debt TOTAL CAPITALIZATION CURRENT LIABIUTIES Current portion of long-term debt and preferrei stock (Notes 3 & 5)
Current, portion of unbilled,utility revenue (Note I)
,, Qmmercial paper (Note 4)
Accounts payable Interest accrued Unfunded future federal income taxes (Notes I & 2)
Accumulated defertel federal income taxes, (Notes I & 2)
Other N
TOTAL CURRENT LIABILITIES DEFERRED CREDITS Accumulated defend investment tax credit'(Notes I & 2)
Excess deferred federal income taxes (Notes I & 2)
Other TOTAL DEFERRED CREDITS ACCUMUIATEDDEFERRED FEDERAL INCOME TAXES (NOTES I & 2)
Unfunded future federal income taxes Other TOTAL ACCUAIUIATEDDEFERRED FEDERAL INCOME TAXES
'COhIMIThlEgS AND COiVTINGENCIES (NOTE 8)-
TOTAL W'ITALIZATIONAND UrtiBILITIES 1991 (Tbousaruls)
P SI60,500 108,550 "422,668 673,791 308,688 1,405,147 1,788',915 3,463,112 38,653 8,346 103,900 Ioo,847 ',
43,440 22J659 16,747 67,137 401,729 148,078 63,778 67,961
-279,817
'413,586 366,592 780,178
$4,924,836 1990 8160,500 10,200 416,202 655,892 292,250 1,364844.
1,756,257 3,291301 61,079 38,803'3,225 85,921, 47,o49 10,713 58,063 397,913 142,894 63,787 86,367 293,048 425,369 329,800 755,169 S4,737,431
.25 '
)
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~
JI
~
~
The ~>tng noJIJs on pays 28 through 37 are an Integral pan of the finandat atatementa I
J I
I
S
~ ~ ~ / ~ ~ ~ ~ ~ P ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ ~
~ ~ ~ ~ ~I ~ ~ ~ ~ ~ ~ ~ ~ ~
/
h
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~
~ ~ ~
~ ~
r /
C P
P CONSOLIDATED STATE3L6ÃTS OE CASA PLOW
'\\
l P
'Year Ended December 31-
.-,net i,
/
from OPERATING ACTIVITIES Net income
, Adjustments to reconcile net income to net cash i
provided by operating activities DepreciatIon'efemi retinue - Nh1P2 Federal income taxes and investment tax credit deferred
,Recovered'(deferred) transmission wheeling charges Unbilled revenue recognition (Note I)
Demand management program costs Other - net-q Changes in certain current assets and liabilities, net of effects purchase of Columbia Gas of New,York, Inc.
Special deposits Accounts receivable
, Inventory Accounts payable Accrued expenses Other,-'et NET CASH PROVIDED BY OPERATING ACflVITIES 1991 SI68,643
~ 152,380 ii,444 53,105 (861)
(4o,i47)
IOI578 30isol)
P (4,108)
(i5,54i) 4,590 2,937 r
- 2,699 (9,052) 305,886'990 (Thousands)
$ 158,013 147,659"-
8,703) 50,924 20,793
-(43,849) ii,o56.
(4,526) 64I)
(11~123)
(37,874) io,46i 1,209 (12556) "-
285,543 1989
$ 157,779
~
148/75 8,927) 36,145 (5,2661 10,247 85,963) 100,434 18,004 11,170 9,870 (299) 7,III5 454,484 26 Cl INVFSflivGACflVITIES Utilityplant construction expenditures.(net of AFDC - other - Note I)
Payment for p'uichase of Columbia Gas of New York, Inc., net of-
'cash uired (244,037)
(57,096),
(210,540) '191,428)
NET CASH USED IN INVESTING ACflVITIES HNANCING ACfiVITIES-Issuance, of first mortgage bonds Sale of common stock Sale<of preferred stock
'irst mortgage bonds and preferred stock repayments tung-term notes repayment Commercial paper - net Dividends on referral and common stock NET CASH USED IN (PROVIDED BY) HNANCING ACIIVITIES (301,133) i47,243 25,380 98,975 (142,715)
(2,322) 30,675 (IS0,106) 7,130 (210,540) 294gI6 115,089 (296,289)
. (5,078)
(47,775)
(133,906)
(73,643)
(191,428) t 2i,546 (146,529)
,(52,625)
-43,600 (128,390)
. (262,398)
NET INCREASE IN CASH AND CASH EQUIVALENTS CASH AND CASH E UIVALENIS, BEGINNING OF YEAR (NOTE I) 11,883
r 1/60 6,718 5,358 658-4,7oo t
CASH AND CASH E UIVALEN6, END OF YEAR (NOTE I)
SUPPLEhlENTAL DISCLOSURE OF CASH KOW INFORhIATION Cash paid during the period
, Interest Income taxes SUPPLEMEiVfALDISCLOSURE OF NONCASH PiVESTING AND FINANCING ACIIVITIES
-Capital leaM additions
%e Company purchasnl all of the common stock of Columbia Gas
'of New'ork; Inc. In conjunction with the ac'quisition, liabilities were assumed as follows:
Fair value of assets acquired,
Cash aid U'abilities assumed
$ 18,601
$ 159,927 S31,790
$9,524
- $81,99(
(57.>>2)-
S24,ss6
$6,7iS
$ 171,675=
$33,111
'$12,192
$5,358
$ 182,247 t
$26,6oi Si6,16o
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ Iv ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0 ~ 0 ~ ~ ~ 0 ~ 0 ~ ~ P ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
'the accompanying rotes on pays mt thmttgh 37 are an integral patt of the finandal statements'.
~ ~ ~
l I
P CONSOLIDATED STATEMENTS, OE CHANGES IN COIttIMONSTOCK EQUITY
~ ~ ~ ~ ~ ~ ~ \\
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 0/ ~
~ ~
~ ~ ~
~ ~ ~
~
~ ~
~ ~ ~
~ ~
~
~
g h BAMCE, ANUARY I, 1989 I
/
(Tlwusands, except Per Slsare Amounts) ~
t s
Common Stock
. Capital
@ti'629'Par Vairre tn Excess Retained Sham Amount o Par Value 'arnin s
~
Total 56,701,'378,004
'557,403
$238,621
$ 1,174,028 Net income-Cash dividends declared Preferred stock (at serial rates)
Redeemable'=
optional
- mandatory
, Common stock ($2.02 per share) issuance of stock Dividend reintestment and stock purchase plan Em lo ee stock ownetshl lan s26
.5,50s 27 178 15,357
'533 157,779 c
(11,513)
(i,462) t (115,224) 157,779 (11,513)
(1,462)
(/15,224) 20,865
,711 BAIANCE, DECEMBER 31, 1989
" 57 554 383,690 573 293 268201 1,225,184 t 'et income, Cash dividends declared Preferred stock (at serial ratel)
Redeemable
- optional t,'
mandatory Common stock ($2.06 per share)
Issuance of stock Public offering Dividend reinvestment and st'ock urchase 4,000 26,667 lan.
876 5845 66,990 i5609 (ii,4s4)
(1,178)
(121 j02)
- (ii,484)--
(1,178)
(121802)
,i 93,657 2i 454 158,013
'58,013 C'7 G
~
BAJANCE, DECEMBER 31, 1990
-62,430 416,202 655,892 292 250
',364,344 Net, income
'Cash dividends declared Preferred stock (at serial rates),,
Redeemable - optional
- mandatory Common stock ($2.10 per share)
Issuance of stock Dividend reinwstment and stock urchase lan 970 17899
.I68,643 168,643 01,395) 01,395)
, (8,935) =
(8,935)
(131,875)
(131,875) 24 65 BAMCE, DECEMBER 31, 1991 The accompanying rotes on pages 28 thmugh
'll I
I 63,400
$422,668
$673,791,
$308,688
$ 1,405,147 37 are an integra! part of the finandal statements.
1
NOTES TO CONSOLIDATED-FINANCIALSTATEMENTS 1.
SIGNIFICANT ACCOUNTING POLICIHS 28 Q
Principles ofconsolidation The consolidated financial statements in-clude the Company's wholly-owned subsidiary, Somerset Railroad Corporation (SRC). All sig-nificant intercompany balances and transac-tions are eliminated in consolidation.
Utilityplant Cost of repairs and minor replacements is charged to appropriate operating expenM ac-counts. Cost of renewals and betterments, in-cluding indirect cost, is capitalized. Generally, original cost of utility plant retinxl or other-wise disposed of and the cost of removal less salvage are charged to accumulated deprecia-tion.
Allowanceforfunds <<sed during construction (AFDC)
AFDC is a non~h return which is shown in the consolidated financial statements as AFDC-other and AFDC-borrowtxl Reven<<e The Company accrues electric and natural gas revenues on its Consolidated Balance Sheets for'ervices provided but not billed. At December 31, 1991 and 1990, approximately
$99 million and $ 102 million of unbilled retinues were accmed and included in accounts receivable, respectively.
The Company will recognize $8.3 million of unbilled retinues betmen January I, 1992 and July 31, 1992. Unbilled revnues will be recognized after July 31, 1992 pursuant to future rate decisions.
The Company recognizes as revenues in-centiws earned as a result of conducting effi-cient demand management programs. During 1991 and 1990, incentives earned were $ 12A and $2.6 million, respectively. At December 31, 1991 and 1990, approximately $ 11.3 and
$'2.6 million, respectively, of demand manage-ment incentives were accrued and included in aocounts receivable.
Accounts receivable The Company has an agreement that ex-pires in 1995 to sell, with limited recourse, undivided percentage interests in certain of its accounts receivable from customers. The agreement allows the Company to receive up to $ 138 million from the sale of such inter-ests, Accounts receivable on the Consolidated Balance Sheets is shown net of $ 138 million of interests in accounts receivable sold. All fees associated with the program are included in operating expenses on the Consolidated Statements of Income and amounted to ap-proximately $9.3 million, $ 125 million and
$ 12.6 million in 1991, 1990 and 1989, re-spectively. Accounts receivable on the Consoli-dated Balance Sheets is also shown net of an allowance for doubtful accounts.
Federal income taxes (See Note 2)
The Company follows the method of ac-counting for income taxes prescribed by State-ment of'Financial Accounting Standards No.
96, Accounting for Income Taxes.
The Company files a consolidated federal income tax return with SRC. Deferred income taxes are providol on all temporary differ-ences betvuen book and taxable income. In-vestment tax credits, which reduce federal income taxes currently payable, are deferred and amortized over the book lives of the applicable property. The effect of the altema-tive minimum tax, which increases federal in-come taxes currently payable and generates a
tax credit available for future use, is deferred and amortized at such time as the tax credit is used on the Company's federal income tax return.
Deferred charges The Company defers certain incurred
- expenses, v hich will be recovered from the ratepayer in the future, as authorized by the Public Service Commission of the State of New York.
Depreciation Depreciation expense is determined using straight-line rates, based on the average serv-ice ling of groups of depreciable property in service. Depreciation accruals were equivalent to 3.3%%d, 3.3%%d and 3.6%%d of average deprecia-ble property for 1991, 1990 and 1989 respec-tively.
Consolidated Statements of Casb Flows The Company considers all highly'liquid investments with a maturity of three months or less to be cash equivalents. 'Ibis includes cash and cash equivalents on the Consoli-dated Balance Sheets. In 1991, the Company changed from the direct method to the indi-rect method for reporting the Consolidated Statements of Cash Flows.
Reclassifications Certain amounts have been reclassified on the consolidated financial statements to con-form with the 1991 presentation.
- 2. KDERAL INCOME TAXES Year Ended December-31 Charged to operations Current Deferred - net Acceleratll depreciation Unbilled revenues Tax Reform Act (TRA) 1986 - net Alternative minimum tax (AhIT) credit Demand management hiiscellaneous Investment tax credit (ITC) deferred 1991
$22,991 37,409 13,644 (2,'284) 5,557 8,589 (8,243) 16 784 94 447 plJOllsands)
$37,804 33,704 Io,167 (3,566) 0,763) 1,985 697 10,549 89,577 1989
$34,528 41,42o (14,o64)
(16,315)
',003 (436)
(252) 18,605 64,489 Included in other income Amortization of defend ITC hfiscellaneous (11,297)
(s33)
(5,756)
'6,465) 176 2,994 TOTAL
$82,617
$83,997
$61,018 The effective tax rates differ from the statutory rate of 34% due to the following Year ended December 31 1991 1990 1989 Tax expense at the statutory rate Depreciation not normalized TRA 1986 - net ITC amortization Cost of removal Other - net
$85,428 16,oSI (2,306)
(11>297)
(6,12o) 861 (7'bousands)
$82,283 14,459 (3,566)
(5,756)
(4,148) 725
$74,391 13,561 (16,315)
(6,465) 8,689)
(46s)
TOTAL
$82,617
$83,997
$61,018
~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
The Company has recorded unfunded future federal income taxes and a cor-responding receivable from ratepa)mrs of approximately $436 and $448 million as of December 31, 1991 and 1990, respectively, primarily representing the cumulative amount of federal income taxes on temporary depreci-ation differences which were previously flovel through to ratepa>vrs. Those amounts, includ-ing the tax. effect of the future revenue re-quirements, are being amortized 'over the life'f the related depreciable assets concurrent with their recovery in rates:
The Company has approximately $ 16 mil-lion of unused investment, tax credits at December 31, 1991, which will begin to ex-pire in 2001, and $9 million of AhIT credits which do not expire.
The Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109), in February 1992. The Company belie@5 that the adoption of SFAS 109, which is effective for fiscal years begin-ning after December 15, 1992, will not have a material effect on its results of operations or financial position since the Company has already adopted Statement of Financial Accounting Standards No. 96, Accounting for Income Taxes.
J' i
- 3. LONG-ARM,DEBY
/
)
At December 31, 1991 and 1990, long-term debt was (Thousanijs):
First mortgage bonds Amount Amoutit Series Due..
1991 1990 Series Due 1991 1990 4s/s%%d May.l, 1991
$,$25,000.
6~/%, Dec.
1, 2006
$25,750
$25,I50 8s/s%%d-Aug. 15, 1994 100,000 100,000;8s/s%%d hjov. 1, 2007 60,000
. 60,000 8s/s%%d June 1, 1996 50,000 50,000 10/s%%d Feb.
1, 2016 20,424 125,000's/s%%d Jan.
1, 1997 25,000 25,000 9i(A.Apr.
1, 2016 50,000 50,000 6/A Sept.
1, )997 25>000 25,000 9%
hiar.
1, 2017, 100,000 100,000 6A%%d-Sept.
1, 1998 30,000
,30,000'-,
10s/%%d Jan.
1, 2018 100,000 100,000
7/s%%d Nov. 1, 2001 50,000
$0,000 9/sX Feb.
1, 2020
.100,000 100,000, 9.35%%d July'; 2003 33,200 35/00 97AP%%d hiay 1, 2020 r100,000
-100,000.
9s/s%
Mar. 1, 2005 75,000 75000 9 "/s%
Nov. 1, 2020 100,000 100,000 9s/sXJan.
1, 2006, 45,p00 48,000, 8~/s%
Nov. 1, 2021
< 150,000
=,7/A'ne 1, '2006 12,'000 12,000 TotalJirst morlgage.bonds
~
1,251,374 1,236 t)50
~ ~ ~ ~ ~ III~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
r-4 I
, Pollution conlrol notes J
r Letter ofCredit J
lnlerest
=
ittaturtly interest Rate Evptratto)t Rate
= Date Ad'ustment Date Date 1991 r 1990 12%%d May 1, 2014
-'0,000 60,000 12.30%
i July 1, 2014
~
40,000 40,000 4.5%%d Dec. 1,,2014 Dec.
1, 1992 Dec.
15, 1993 74,000 74;QPQ 55%%d Mar. 1,-2015
'iar.
1, 1992 'iar. 15, 1993 37,500 37,500
~ 5.5%%d htar. 15, 2015 Mar. 15, 1992 hiar. 31, 1993
- 60,000 60,000 1
30 4.85K July 15, 2015 July 15, 1992.,
July 31, 1993
@;500 63,600 4,.55'Yo Och 15, 2015 Ocb 15, 1992 Och 31, 1993 30,000 30,000 4.40%
Dec.
1> 2015 r
. Dec.
1 1992
'ec.
15, 1993 42 000 422)000
~6.6%%dJ July 1, 2026,-
July f1993 July 15, +13 65,000 65,000 5;375%%d Dec.
1, 2027 Dec.,l, 1994 Dec. 15, 1994
) 34,000
<<34,000 Total llulion conlrol notes 506,000 506,000
~
.SRC commercial paper due December 31, 1994 29,300 31,622 Obligations under capital leases
= ',,
47260 48,885 Unamortized iemium and discount hn debt - net (8,016)
(6,871)
',825,918 1,815,686
,Less debt due within 'one ear -. included in current liabilities 37 003
-59,429 Tolal.,
'1,788,915
$ 1,756,257
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ I~I ~ ~i~ ~ ~ ~ ~
~
~ ~ ~ ~ ~ ~ ~ ~ ~ I'i ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ I) ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
I' At December 31, 1991, long-term debt and Trustee pIrior to,January 1 of that par (ex-
$600,000 beginning June 1, 2001 for the'apital lease payments which will become due eluding any bonds issued on the basis ofthe'/A Series and $250,000 beginning Decem-dunng the next five pais are:
-retirement of bonds); The Company satisfied ber 1, 1992 for the 67/s%%d Series. The amount 1992 1993 1994 1995 1996' this requirement in 1991 by depositfng $ 18.9 increases to $500,000.and
$750,000 on De-(Tbottsands)
'illionin cash which was used to redeem cember'1, 1997 and December 1, 2002, 're-
$37 QQ3
$ 15 269
$ 144 08$ $P 883
$6F 146
$ 18.9 million of 10 /s% Series first mortgage sPectiiely, for the 6 /s%%d Series.
bon'ds, due 2016.'The Company satisfied this The Company's fiist mortgage bon'd inden-requirement in 1992 by depositing $20.4 mil-ture constitutes a direct first mortgage lien on The,Compansrs mortgage pmvides for,a lion in cash which was used to redeem in substantially'all iltilityplaht.-
sinking and improvement fund.*'Nis provision February 1992, the remaining $20.4 million,Adjustable rate'pollution control notes were requires the Company to make annual cash of those,lQs/s%%d bpnds.
issued to secure like amourits of taxmempt deposits with the Co'mpany's Trustee equiva-J Mandatoiy annual cash sinking fund re-adjustable rate pollution control revenue lent to 1% Of the principal amount of all quiiements are $3;000,000 for the 9s/A Series bonds'(Revue Bonds) issued by a'govern-,
bonds delimnxl and authenticated by the, due 2006, $2,100,000 for the 935%%d Series, mental authority.-The Revnue Bonds bear I
I gI
3.
- LONG-TERM DEBT (Coritinued)
I' interest at the rate indicated through the date, The Company has irrevocable letters of preceding the. interest rate adjustment date.
credit which expire 'on the,'letter of credit ex-
"Ihe pollution control notes bear interest at piration dates and which the Company antici-the same rate as the Revenue Bonds. On the pates being able to extend if the interest. rate
.interest rate adjustment date and annually on the related Revenue Bonds. is not con-thereafter (eery three )ears thereafter in the
~vtted to a fixed interest rate. Those Iette>>s of case of the Revenue Bonds due July I, 2026, credit support certain payments required, to be and'December I, 2027), the interest rate will made, on the Re>>>>enue Bonds. If the Company be adjusted, not to exceed a rate of 15%%d, or
'is 'unable to extend the letter of credit thai is, at the option of the Company, subject to cer'-
relaied to a particular series of Re>>enue tain conditions, a fixed rate of interest, not to Bonds, that series will have to be pdeemed
, exceed 18%, may become effecti>>u. In the unless a fixed rate of interest'ecomes effec-case of the Re>>vnue Bonds due July I, 2026 tisv. Payments made under the lette5 of and December I, 2027, at the option of the
- cnxiit,in connection with purchases of Rev-Company, subject'to certain conditions, a enue Bonds by the Trustee are repaid with
'ixed-rate of interest may become.effecti>>>>e 'he proceeds from the remarketing of the prior to the interest rate adjustment date or Revnue Bonds To the extent the proceeds
,each thinl )ear thereafter. Bondowners may, are not suflicient; the Company is requinxl to elect, subject to certain-conditions, to have reimburse the banl>>'that issued the letter of their Re>>anne Bonds purchased by the
'redit.
h Trustee.
- 4. BAm LO&S AND'OTHER BORROiVH>>lGS h
'Ihe Company has a revolving 'credit-agree-The revolving credit agreement does not ment with certain banb which provides for
'require compensating balances, The Company borrowing up to $200 million to July 31,
~
did not have any outstanding loans under 1992.'Af the option of the Company, the in-this agreement at December 31, 1991 or terest rate on borrowiny is related to the'990.
prime rate, the London Interbank Offered Interim financing in the form of short-Rate or the interest rate applicable to certain term unsecured notes, usually commercial certificates of deposit. The agreement also
- paper, is used to finance certain refundings p'iovides for the payment of a commitment and construction expenditures, and for other fee on the unborrowel amount of s/is of IX corporate purposes, thereby providing Aex-,
.'er a'nnum, The Company is in the process of, ibilityin the timing and amounts of long-
- negotiating a similar agreement with certain term finaiiciny.
banks for the same amount to become effec-tive August I, 1992.
1'-
7 r
fnformation.relative to short-tenn borrowiny is as follows:
Comrirercial Piiper 1991 '990
=-
1989
, (Tborrsarrds}
Ending balance
$ 103,900,
$73,225,,
'121,000 Maximum amount outstanding
'~
$ 111,000
$ 142,600
'- $ 128,'500 Average amount outstanding (I)
<<>>. $66,700
'98,400"
$82,500 Weighted average interest rate On ending balance ',,
5.3%%d
'.6%%d;,,
8.6X During the period (2)'>>
6.2%
8.5%%d 9.2X
~ ~ o'
~ ~ i ~ ~ ~ ~ ~ ~ ii ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~
>> ~ ~ ~ ~ ~
~ I~ ~ ~
(I) Calculated as the average of the sum oF daily outstanding borrowiny. --.
,(2) Calculated by dividing-total interest expense by the average of the sum of daily outstanding borrowings.
>>~~
lV V
5.
PREFERRED STOCK At December 31, 1991 and 1990 serial cumulative preferred stock was:
Shares Par Value Authorized Per Redeemable and Series Share Prior to Per Sbare Outstandin I Amount 1991=
1990
- i. Redeemable solely at the option 3.75%
$ us 4!A% (1949) 100
'4.15Yo 100 4.40m 100 4.15% (1954) 100 6.4e, 100 8.80%
100 8.4No 25 Adjustable Rate (2) 25 Total of the Company
$ 104.00
'103.75 101.00 102.00 102.00 102.00 102.00 2/I/94 26.23
'Ihereafter 25.70 10/I/93 25.75 Thereafter 25.00 150,000 40,000 4o,ooo 75,000 50,000 300,000 250,000 1,000,000 (Tbousands)
$ 1s,ooo
$ is,Ne 4,000 4,000 4,ooo 4,ooo 7,500 7,500 5,000 5,000 30,000 30,000 25,000 25,000 25,000 25,000
$ 16O,SOO 16O,SOO 1,8oo,ooo 4S,ooo 45pe Subject to mandatory redemption requirements 9AXS (3) 100
. 10/I/92 101.50 102,000
$ 10,200
$ 11,850 8.95'M (4) 25 1/I/93 27.09 4,000,000 Ioo,ooo 1101200 11,850 Less sinkin fund
'irements at ar value included in current liabilities 1,650 1,650 Total
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
$ 108,550
$ 10,200 Annual releemable preferred stock sinking fund requirements for the >ears 1992 through,1995 are $ 1.65 million, and for the >var 1996 is $3.6 million.
0 (1) At December 31, 1991, there were 1,550,000 shares of $ 100 par value pre-ferred stock, 4,000,000 shares of $25 par value preferred stock and 1,000,000 shares of. $ 100 par value preference stock authorized but unissued.,
(2) The Adjustable Rate Serial Preferred Stock, Series A, was issued in September'983.
Dividends paid from the date of is-suance through the 'January I, 1992 pay-ment varied from7'o 12.95% per annum. The payment for April I, 1992 has been adjustei to a rate of 7.6'er annum and subsequent payments can vary from 78% to 13/~% per annum, based on a formula included in the Company's Certificate of Incorporation.
8)
On October 1, Iri each >var 1992 through 1995, the Company must 'releem 16,500 shares at par. For the years 19$ through 1991, 16,500 shares were redeemed and cancelled annually. This Series is re-deemable at $ 101.50 per share prior to October I, 1992. 'Ihe $ 101.50 price per share will be reduced annually by $,50.
As of October 1, 1994, and thereafter, the reiemption price will be at par. By Sep-tember 30, 1996, the Company Inust set aside the amount required to redeem at par all shares outstanding.,'4)
On January I, in each par 1997 through 2016, the Company must redeem 200,000, shares at par. 'Ihis Series is redeemable
- at $27.09 per share prior to January I, 1993. The $27.09 price will be reducel annually by $.15 for the )ears ended 1993 through 1999; by $.14 for the >mr ended 2000 and by $.15 for the )mrs ended 2001 through 2005. The Company is restricted in its ability to redeem this Series prior to January I, 1996.
V i
h
/
- 6. 'REI',IRHMHNT BENEFITS I
The Company has "noncontnbutory retire-,
pany's policy to fund pension costs accrued ment annuity plans which coiner substantially each year to tlie extent deductible for federal all employees.
Benefits are based princijially income tax purposes.
Net pension benefit for
= on the employe'e's length of seivice and corn-
-1991, 1990 and 1989 totaled $2.9 milliori,/
pensation for the fiw highest-paid pars out '4.9 million and $3.7 million, respectively.
of the last 10 pars-of service. It is the Com-Net pension benefit for 1991 and 1990 included'the following components:
\\
1991,,
.1990
/.
I Service cost: Bendits earned during the par Interest cost on projected bendit obligation Actual return on plan assets
~ Net amortization and deferral Net pension benejl t (Thousands)
$ 13,252
$ 11,968 32,096 28)636.
(111,149) '6,499)-
63,487...
(39,017)
$ (2,914)',
$ (4,912)
The funded status of the plans
~ at December,31, 1991.was:
Pborrsands)
Actuarial present value of accumulated benefit obligation, Vested
$270,052 Nommted "
34,067 Total Fair value of plan assets Actuarial resent value'of.
ro'ected benefit obli ation Plan assets in excess of projected benefit obligation Unrecognized net transition asset Unrecognized net (gain) loss--
Unreco ized rior, service cost
$304,119
$659,993 (440,519) 219,474 (88,103)
(132,642) 5,'578'30 Net pension asset
$4,307'
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ I
~ ~ ~ ~ ~ ~ ~ ~ J ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 'I ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
I I
Plan assets primarily comist, of equity se-
.;.curities, corporate bonds, U.S. agency and Treasury bonds and notes and cash equiva-lents.,
For 1991 and 1990, the projected benefit obligation was measured using an assumed, discount rate of 7.75% and 8%respectively and a long-term rate of'increase in future icompensation levels of 6%, while the net pen-sion benefit was measured using an expected
. long-term rate of return on pjan assets of
, 7;5%.'-
In addition to p'roviding pension benefits, the Company provides certain postietirement benefits for retired emplopes and their de-pendents.
Substantially all of the Company's emplopes who retire under a Company pen-sion plan may become eligible for thos'e ben-dits at retirement. At December 311991, 1990 and 1989, 1,866, 1,785 and I;685 re-II tirees and their dependents, respec'tively, were covered under the Company's comprehensive, health insurance plan and prescription drug plan, which the Company self-insures. The cost of providing those benefits to retirees was approximately $44 million, $4.1 million and
$3.2 million in 1991, 1990 and 1989,'iespec-tiwly.
The Financial Accounting Standards Board issued Statement of Financial Accounting.
Standards No. 106, Bmplopis'ccounting for Postretirement Benefits Other 'Ihan Pensions (SFAS 10ii), in December 1990. SFAS 106 re-quires that'the Company accrue a liabilityfor estimated future postretirement benefits during'n emplope's working career rather than rec-ognize an expense when bendits are paid; SFAS 106 is elfectiw for fiscal }ears beginning after December 15, 1992.
'Ihe 'Company intends to adopt SFAS 106 I
prospectively in 1993-.and estimates that the additional liability it will be requiml to ac-
< crue'is ajproximately $ 166 million. This ad-
'itional liabilitywill be, amortized to expense over 20 pars.
As a result-of this amortization,>
postretire'ment benefits cost will increase by
-approximately sewn times the 1991 amount.
The PSC staff is in the process of dewloping a policy statement related to the accounting and ratemaking'reatment of postretirement benefit costs. The policy statement is expected to be finalized prior to the effective date of SFAS 106. 'Ihe Company helios that-the adoption of SFAS 106 w'll not haw a mate-rial impact on its results of operations or fi-nancial position because any increase in expense, should ultimately be recowied in-.
rates. Historically, rate recowiy-has been au-thorized for postietirement bendit costs-,as
'they are incurred.
c'
I f
4 s
- 7. JOINTLY-OWNED GENERATING STATIONS'omer CIty The Company has an undivided 50% inter-atic assessment of licensee performance est in,the outpuf and costs of the Homer City, (SALP) review of the Nine Mile,Point Station, Generating Station, which is comprised of (includes both Nirie hiile Point nuclear gener-three generating units. The station'is owned ating unit No. I 'and NhiP2) for the period,--
, with Pennsylvania Electric Company which
'1arch 1990 through hiarch 1991, The SALP operates the facility. '(he Company's'share of report indicated that significant im'provements the rated capability is 950,000 kilowatts and had been demonstrated in plant operations, its net utilityplant innstment was $257 and "maintenan'ce/sunuillance and safety~
'253 million at December 31,'991 and 1990, ment/quality verification. The ratings in these respectively. The accumulate'd provision for three categories'fmproiei from Catego'ry 3, depreciation.was,$ 144 and $ 135 million, at the lowest ranking under SALP, representing r
December 31, 1991 and 1990, iespectiiuly.
acceptable, although minimally adequate,
'Ihe, Company's share, of operating expense '
safety performance to Category 2, representing is included In the Consolidated Statements of good performance.
Radiological controls and,.
Income. <
~,'ngineering and technical support remained at'Category,2, while emergency preparedness one Wle PotntiUnit 2
~
and security safeguaids remained at Category The Company has an undivided ISX,Inter~ ', ~resenting s'uperior performance.-.
est in the output and costs of the Nine Mile In June 1991, the Company was advised by
, Point nuclear generating unit No. 2 (NMP2),,
Niagara Mohawk that the NRC remodel which was constructed and is being operated NhiP2 fmm its list of plants that require close
'y Niagara hiohawk-Power Corporation, monitoring, The removal was the result of
'Niagara, hiohawk). Ownership of NhiP2 is oyerall improvement iii management over-
'hared with Niagara hiohawk 41%, Long Is-sight and staff performance at NhiP2.
'and Ughting Company '18%, Rochester Gas
In December 1991, the Institute. of Nuclear and Electric CorporafioQ4X and.Central Power Operations (INPO), an industry-spon-
.Hudson Gas & Electric Corporation 9%. The sored oversight youp, performed a site eval-Company's share of'the rated capability is uation of NhiP2. 'Ihe Company does not.,
196,000 kilowatts and its net utility plant in-expect the iinal INPO report to be available
.vestment, excluding nuclear fuel, was $679 More the sennd quarter of 1992.
and
$695 million, at December 31, 1991 and The Federal Low Level Radioactive-Waste 1990, respectively. The accumulated provision Policy Act, as amended In 1985, requires
- for depreciatIon was $72 and $ 50 million, at states,to join compacts or individually develop'ecember 31, 1991 and 1990, respectively.,
their'wn,low level radioactive waste disposal.
The Company's share, of operating expenses is site, On January I, 1990, Governor Cuomo included in the Cortsolidated Statements of
'ertified a plan that requires all nuclear Income.;
power plan& in New York State to store their An interim operating agreement that pro-
" low Ieuf radioactive waste on site from Janu-vides for additional policy, budget a'nd man- 'ry I, 1993, until the end of 1995, by which agement oiytslght functions ot NMP2 by the, time an-interim storage facility is scheduled four non-operatihg cotenants became effective to be available at the site of the permanent in 1989, The interim operating agreement
-.Iow level radioactive waste site. A low level
-expires March 31,'1992.
'adioactive waste management and contin-i
'Ihe next refueling outage for NMP2 is an-gency plan is available to provide assurance ticipated to'begin February 29, 1992.
'hat NhiP2 will be properly, prepared to han- ~,
In the spring of 1991, the Nuclear Regula-die interim storage of low level radioactive tory Commission (NRC) completed'a s)stem- 'aste until. 1998.
C
8.
COMMITMENTSAND CONTINGENCIES '-
Constncctlon program The Company has made substantial corn-The Clean Air Act Amendments of 1990 stations'.actual emissions. The Company is-mitments In,connection~with its construction (1990 Amendments) will result in significant
'onsidering various methods of utilizing or program and estimates that 1992 costs will future expenditures for the reduction of sulfur selling these excess emissions allowances.
'pproximate
$275 million. 11te program is dioxide, nitrogen oxides and possibly toxic During Phase II, which begins on January I, subject to periodic review and revision, and
emissions at several of the'Company's coal-2000, the Company estimates that the-annual "actual construction'costs to be iricurred may fired generating stations. Under the 1990 tons emitted by its fossil fuel generating vary because of revised load estimates,'mposi-,
Amendments, the Company must Wuce its f stations will equal its annual emis'sions
=lion of additional regulatory requirements,'-.
'nnual sulfur dioxide emissions from approx-allowances.
and the availability and cost of capitaL imately 138,000 tons in 1989 to approx-imately 74,gq tons, or 47%, by 2000. The
Nt(clear Insurance Erzvtro1ll1ÃlltrrlMPttcl's Cflmpany estimates that the cost of complyppg Niagara Mohawk maintains public liability The'Company-assesses on an ongoing over a 25-year period with the sulfur dioxide and property insurance for'NMP2. The Com-basis the measures that may need to be taken,~ and nitmgen oxide limitations in the 1990 pany reimburses Niagara Mohawk for its 18%
=- to compiy with environmental laws and regu-Amendments is approximately $252 milflon, "
share of those costs.
lations governing hazardous wastes,pir qual-
on a present value basis for aII capital and
'he Price-Anderson Amendments Act of ity, water quality', lan'd use and solid waste
'operating and maintenance expenses'hich
'988 (Amendment) increased the public lia-disPosal. ComPliance Programs necessary to incluiles $ 159 inillion for an advanced flue bility limit for a nuclear incident to aPProx-'eet existing and futuie environmental lava" gas desuifurization (POD) system expected to
imately $7.5 billion. Should losses stemming and regulations will increase the cost of elec-be completed in 1995 'at its Miihken Generat
from a nuclear incide'nt exceed the commer-
~
tric,and natural gasxrvice by requiring ing Station
~,,
'iallyav'ailable public liability insurance, each changes to the Company's operations and, In September 1991; the Company was se-
"licensee of a nuclear facility would be liable facilities. Historically, rate recovery has been
. lected by the Department of Energy (DOE) to for up to a maximum of $63 million 'per in-authorized fear the costs of compliance with receive fe'deral funds. for this system. While cident; payable at a rate not to exceed
$ 10 environmental laws and regulations incurred the Company',requested approximately $65 million per )ear.
by the Company.,
'illionfrom. the DOE,'the exact<amount of, The Company's maximum liabilityfor'its The Company may also incur costs in
-the funding has not pt been decided. In ad-,,18%
interest in NMP2,would le approximately connection with legal prmedings commenced dition, the Company expects to receive fund-
$ 11 million per incident. The $63 million.as-
"hy governmental bodies arisingtout of'the dis-ing totaling up to $ 15 million from other
'essment is subject to periodic inflation index-pt5ai of hazardous wastes by the Company or sources. The cost of controlling toxic emis-ing and a 5% surcharge should funds prove its predecessors.
'IIte Company has been noti-sions, if necessary, cannot be estimated at this insufficient to pay claims associated with a fied by the Environmental Protection Agency time. Regulations may be adopted at the state nuclear incident. The Amendment also re-and the-New York State Department of Envi Ie>ei which would limitemissions even fur-
= quiies indemnification for precautioriary evac-
'onmental Conservation that it is among the, ther, with an additional cost to the'Company.
uations whether or not a nuclear incident potentially responsible parties'who may be li-Tlie Company anticipates that the costs in-actually occurs.
~ able to, pay for costs incurred to remediate
't curred to comply with the 1990 Amendments Niagara Mohawk maintains nuclear prop-
'certain hazardous waste sites. Any liability:Villbe recoverable through r'ates based on erty insurance for,. NMP2. Niagara Mohawk:
may be joint and several for certain of these previous rate recovery of 'environmental costs has procured property insurance aggregating sites. 'IIie ultimate cost to remediate these required by governmental autliorities. The
'approximately S2,5 billion through the Nu-sites will be dependent on such factors'as the
~ Company also estimates that a 2% electric clear Insurance Pools, Arkwright Mutual and existing technology required for site cleanup,
'ate increase will be requii61 for the cost of the Nuclear Electric Insurance Limited the remedial action plan selected and the, ex-reducing sulfur'dioxide and nitrogen oxides (NEIL). In addition, the Company has pur-tent of.site contamination and the portion at-emissions. ', "
chased NEIL insurance-coverage for the extra tributed, if any, to the Company. As a. result,
~
The 1990.Aniendments require the Envi-expense incurred in purchasing replacement the Company is,unable to estimate the extenf ronmental Protection Agency to allocate an-power during prolonged accidental outages.
of possible remediation costs. There is cur-nual emissions allowances to-each'of the Under iIEILprograms, should-losses resulting rently no clear precedent'with the PSC for Company's fossil'fuel-generating stations from an incident'at a,member facility exceed rate recovery o'f these types of remediation based on statutory emissions limits. An emis-the accumulated reserves of NEIIeach mem-costs. Hotvwver, the Company expects to re-sions allowance represents an authorization to ber,'including. the Company, would be liable
..cover the expenditures, if'any, it incurs in emit, during or afAr a specified calendar for its shaie'of the deficiency. The Company's rates, since the Company has been a!lovel by
)ear, one ton of sulfur dioxide. During Phase, maximum liability under the property dam-the PSC to recover similar costs (e.g., Innsti-I, which begins on January 1, 1995, the Com-,age and replacement power coyerages is ap-gation and clean-up costs relating to coal tar-
.pany estimates that it will have allowances in proximately $ 1.5 million.
sites) in rates in current and prior years.
excess of-the atTected coal-fired generating
- 8. COMMITMENTSAND CONTINGENCIES (Continued)
Nuclear Encl gMsposal and Nuclear Plant Decontntlsstontng Costs Niagara hioha<<% has contracted with the U.S. Department of Energy for the disposal of nuclear fuel. The Company is reimbursing Niagara Mohawk for its 18%%d share of the cost under the contract (currently approximately
$ 1 per megawatt hour of net generation).
The Company has been informed by, Niagara hiohawk that its 18% share of the cost to decommission NhIP2 is currently esti-mated to be $235 million in 2027, when de-commissioning is expected to commence.
Included in the Company's, current electric rates is an,annualized allowance of approx-imately $ 1.6 million, based on a Niagara Mohawk estimatewhich the Company expects will provide for its IS% share of decommis-sioning NMP2 in 2027.
In March 1990, the Company established a
Qualified Fund under applicable provisions of the federal tax law. The fund also complies with NRC regulations,,which require the use of an external trust fund to provide funds to, decommission the contaminated portion of NhiP2. The balance, of this fund was approx-imately $2.4 million at December 31, 1991.
The Company has been informed by Niagara hiohawk that on July 18, 1990, as requiml by the NRC, if filed a decommissioning report for NhiP2 with the NRC. The report outlined the proposed plans, which included the Com-pany's funding plan, to provide financial as-surance to fund costs to decommission NhiP2 when its license expires.
9.
INDUSTRY SEGMENT INFORMATION Certain information pertaining to the electric and natural gas operations of the Company is:
1991 1990 1989 h'atural Nntural h'atural Electric Gas Electric Gas Electric Cas P'housaiuls)
Operating Revenues '1,367,936
$ 187,879
$ 1,334,509
$ 162,271
$ 1,266,668
$ 161,077 Expenses
$ 1,065,830
$ 178,210
$ 1,033,564
$ 147,859
$961,127
$ 153,885 Income
$302,106
$9,66rt
$300,945
$ 14,412
$305,541
$7,192 Depreciation'145,700
$6,680
$ 142,286
$5/73
$ 143,433
$4,942 Construction expenditures
$210,127'35,756
$ 187,660
$23,065
$ 176,645
$15/77 Identifiable assets"
$3,841,547
$272,342
$3,781,048
$ 179,605
$3,721,147
$1639
'Induded in operating eperrses.
"Assets used in both eledric and natural gas operations not induded above rvee
$810,947, $776,778 and f785,747 at December 31, 1991, 1990 and 1989, respectively.
Sey consist primarily ofcash and cash ertuivalents, special deposits accounts receivable, prepaymenls, unamortized debt experrse, unfundedfuture federal income taxes and accrimulated deferred income tax benefits.
10: SUPPLEMENTARY INCOME
'TATEMENT INFORMATION Charges'for maintenancet repairs and depreciation, other than those set forth in the Consoli-dated Statements of Income, were not significant in amount. Taxes, other than federal'income taxes, are:
1991 1989 Pmperty Franchise and gross receipts Payroll Miscellaneous
$76,589 76,721
~ 15,4g 9,408 (Tbortsands)
$73,495 62,849 14,179
'8,247
$69,304-57,136 13,156 i
. 7009 Total Other-Taxes
$ 178,185
$ 158,770,
'146,605
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
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~ ~ ~ ~ ~ ~ ~ ~ ~
'E I
t 11.
QUARTERLY FINANCIAL--
INFORMATION (UNAUDITED)
!)
r
<<arter'ended
'arcb 31
'ne 30 Se t. 30,.
Dec. 31 s (Tbortsands except Per Share Amo<<nts)
- 1991, Operating revenues
'=
$443,581
$373,362
$349,626
$389,246 Operating income
$ 103,635
$79,146
$63,665
$65,329 Net income
'73,208(1)
$43,087
$29,374
$22,974(2)
Earnings for common stock
$68,909
$37,722,
$23,997
'1'7'685 Eaniiny per share
$ 1.10
~
$.60
$:38,
$.28 Dividends per share ~r, '.52
$.52
$ 53
~
$..53 Average shares outstanding 62,542 62,775 63,024 63,273 Common stock price'igh'
'26.75
$27
$27.63
$29.63 law
$24.38
$24
$24.63
'26.63
'990 Opeiating revenues
$438,293
$367,009
$330,344
$361,134 Operating income
$ 110,646
$81,766
$62,633
$60,312 Net income
$70,321
'43t311 '
$22,237
$22,144 Earnings for common stock,
$67,212
$40,124$ 19,060,$ 18,955, Eaminy per share
'1.17,
$'.69
$.33
$ 31 DivirIends per share r
$.51
$'.51
$.52
$.52 Average shares outstanding 57,651 57,859 58,074
ti1,097 i Common stock price*
- High,
~
$29.25
~
$25.38
$24.63,
$26.25 Low
'24.38
$22.50'
$21.38
$23
~ ~ ~ ~ ~ ~ ~ \\ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
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~
'I) First quarter 1991 results reflect the stockholders'hare of proceeds from the settlement, of lawsuits related to the design'and construction of NMP2 which increased.net income and, earnings for common stock by $3.9 million, and increased eaminy per share by 6.2 cents.
(2) Fourth quarter 1991 results reflect an adjustment to the Homer City Coal Cleaning Plant which decreased net income and eaminy for common, stock by $3.5 million, and de;,
creased eaminy per share by 5.6 cents, and the stockholders'hare of a settlement of an antitrust lawsuit which decreased net income and earnings for common stock by $ 1.9 mil=
'ion, and decreased eaminy per share by 3 cents.
/
, 'ybe Company's common stock is listed on the New York Stock Exchange. 7be n<<mber of stockholders ofrecord at Decetnber 31, 1991 <<as 59,593.
1 Dividend limitations: After dividends on all outstanding preferred stock'have been paid, or" declared and funds,set, apart for their pay-ment, the common stock is entitled,to cash,-
dividends as may-be declared by the Board of=
~
Directors out of retained eaminy accumu-lated since December 31, 1946.'ommon Stock dividends are liinited if Common Stock
'quity (40.6%%d at December 31, 1991) falls, below 25K,of total capitalization, as defined in the Company's Certificate of Incorporation.
Dividends on common stock cannot be paid unless sinking fund requirements of the pie-femd stock are met. The Company has not been restricted in the payment of dividends on common stock by these provisions. The retained earnings balances of $308,688 and
$292,250 million as of December 31, 1991 and 1990, respectively, have been'accumu-lated since December 31, 1946, P
37 0
/
i h
'EPORT OE REPORT, OE 39lNAGEALENT INDEPENDENT ACCOUNTAlVTS'
~ C'e e
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~ ~ ~
e
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~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~
/
'h
- i h
J
'lhe Company's management is tmponsible for the pmparation,
~
QOO integrity and obj'ectivity of the consolidated financial statements, notes and other information in this Annual Rayon. The consol'.
8 LyIirand dated financial statements-have been pttepaffed in accordance with
'enerally accepted accounting principles and include estimates, Tp the Stpckhpldeis and Board pf Directors','hich are based upon management's judgment and the best avail-
'. New York State Electric &.Gas Cpipoiatipn able information. Other financial information contained m this --.
report was prepared on a basis consistent with that of the consoli ithaca New York dated financial'statements.
,Iri recognition of its responsibility for the consolidated financial We hahu'audited the accompanying consolidated balance sheets statements, management maintains a system of jntemal accounting pf New York State Electric 8f Gas Corporation and Subsidiary as of controls which~ designed to provide reasonable assurance as to Decembeigi, 1991 and 1990;and the related consolidated state-the jntegrity and reliability of the financial statements, the protec-ments of income, changes ln'common.stock equity and cash flows tion of Mts from,,unauthorized use or'isposition and the pre- 'pr each pf the three years in-the Qriod ended December 31i'1991.
vention and detection of fraudulerit financial reporting.
i These financial statements are the responsibility of the Company's Managemerit.continually monitors its system of internal controls management.
Our responsibility is to.express an opinion on these for compliance. The Company maintains an internal audit depart-financial statements based olr our audits.
ment which independently assesm tlie effectiveness of the internal 'We conducted our audits in accordance with generally'ccepted con'trois. In addition, the Company's independent accountants,, 'udiIing standards. Tliose standards require that m plan and per-CooPers &Lybrand, hah'onsideml the ComPany'~ internal con-z form.the/audit to'obtain reasonable assurance about whether the trol structure to the extent they considered necessary In expressing 'inancial statements ate free of material misstatement.
An audit in-
.an opinion on the consolidated finaiicial statements.
Ibianagement dudes examining, on a test basis, evidence supporting the amounts is responsive to the recommendations of its internal audit depart-,, 'and disclosures in the financial statements.
An audit also includes ment and Coopers & Lybrand concerning internal controls and
< I' assessing the accounting principles used and-significant estimates
'orrective measuies aie takenwhen considered appropriate.,
made b)y management, as well as evaluating the overall financial. '-
Management b hievm that p pf D mb r 31, 1991, the Company's statement plantation. We 1
lieve that pur audit pmmde a rea-sjstem of internal controls provides reasonable assurance as to t>>e
- sonable basis for our opinion."
integrity and reliability of the consolidated financial statements.
/,In our opinion, the financial statements meferred to above pre-The Board of-Directors omrsees the Company's financial tu-
~
~
sent fairly, in all material respects, the consolidated, financial posi-porting through its Audit Committee. This Committee, vIhich is tipn pf New Yprk State Electric &. Gas Corporation and Subsidiary.
comprised entirely of outside directors, meets regularly with ~,"
at December 31, 1991 and 1990, and the consolidated results of management, the internal auditor and Coopers & Lybrand to dis-their operations and their cash flow for each of the three pars in cuss auditing, internal control and financial iepprting matters. To the period enilnl December 31, 1991, in conformity with generally ensure their independence both the internal auditor and independ-accepted ac'counting principles.
~cot accountants have flee access to.the'Audit Committee, without management's presence.
'h t m mC.
'ames A. Carrigg
,Cbairman, President and Chief&ecutilye Opiner
/
~
Nebv-York; New york
~
January 31, 1992 r
/
Sherwood J. Rafferty Vice President and Freasprer (ChiefFinaiicial Ogice)
/
Barrett A. Robinson Vice-Prelideiit aird Conlroiier (ChiefAccpunliiig.Ogicer) y 4 f
h.
I SELECTED FINANCIALDA'TA
~ \\ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~
~ ~ ~
~
~
(
~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~
1 b'ousands~
ence t Per Share Amouiits 1991 '990 '
- 1989,
~
1988
'1987 Operating, revenues'
" $1,555,815:
'1,496,780
~
'1,427,745
$ 1,340,169
$ 1,289,638 -
Net income (loss)
$ 168,643 <<$ 158,013
$157,779'171,467'-
($ 177,737)'
Earnings (loss) per share
$2.36
$2.48
$2.53'
~ $2.81'$
3.46)'ividends declared and paid per share
$2.10
-$2.06
$2.02
$2.00
$2.64>
Inerage shares outstanding
-, 62,906 58,678 57,138, 56,239 55318
<<Book value,per share of common stock ()ear end)
$22.16
$21.85,
$21.29
$20.71,
'19.85-Interest charges
'163,526
.$ 173/90
$ 180,068
. $ 199,730
$202/21
<<AFDC and non~h return -',
'7,541
$5,776,
$6,38tr
$28,788
$ 108,128 Depreciation
$ 152,380
$147,659
$ 148,375
$ 134,037
$ 110,679 Other taxes
$ 178,185
$ 158,770$146,605
$ 136,706
$ 128,776 Construction expenditures,
$245,883
$210,725
- $ 192,022
$228,223 $270,045 Total assets
~
'4r924i836
$4 t37 431'
$4,670,283
$4,693,277 i
$4,487/44 Long-term obligations, capital leases and redeemable preferr81stock,
$ 1,897,465
$ 1,766,457
$ 1,799,800,
$ 1+37,648
$2,073374
<<Net income and earnings per sbccre for 1987 uould have been $191,'052 and g3.21, 'respectively, rvrcluding Ibe egects ofItic rvrile-opof Itic'ne htile Poiirt nuclear-generating unit No.2 (NhtP2) and jarnesport disalloived costs,and an accorcntiicg ange for income Azves'. h'et,,
incoiiie and earnirigs per share for 1988 and 1989 include Ibe effects ofndj ccstnrenis recorded in April 1988 and December "1989 to Ibe 1987 NhIP2 rvrctewg PJrcluding those ndjrcstments, nel iiicome niid eaniings per share for 1988 and 1919 rvere gl65,377 acid $'2.70
~
~
and gl51,998 and g2.43, raspedively.
I I
.; eLOSSAZY, 00 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
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~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ J
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~
h Aliorvnnceforfiinds used during con-Earnings for common stock: eaminy pany's growth potential (The higher the P/E structton (AFDC)i the cost of money used after all expenses are recognized and p'referroI ratio, the niore potential the market bellies to finance a project which is'added to con-dividends have been paid,,
there is for growth.)
V
,struction costs and recovered over the life of
',Earnings per share earnings for corn-Retained ear'cctngsi the portion of eam-the asset mbn stock for a given period divided by the iny'that is reinAste'djn the business and'not
>'Alloivedreturn on cominon equily: ~the average number of shares outstanding for the paid out as dividends cost of, common equity"as,determined by the 'eriod
- Return on connnon equity: the rate of" Public Service Commission of the State of,,
Independent pouer producers (Ipps):
return earned on common equity calculated-5ew York (PSC)
. non-utility generators of electricity, by dividing earnings for common st'ock by Book:value per share: common stock Heat rate: a,measure'of generating sta-average common equity equity divided by the number of common tion efficiency often expressed as the number Total shareholder retrcrn: the increase in shares outstanding for the period of Btu'needed to generate'one kilowatt-hour the value of a'shareholder's Innstment in-Btrc (British'liiermal unit): the quantity of electricity eluding dividends receiwxl and changes in the of heat required to raise the temperature of Loadfactor: the average load of an market price per common share one pound of water one degree Fahrenheit at electric or natural gas.distribution system, Transportntttin gns: natural gas pur-sea level
~
compared to its~maximum load capability for chased directly from a supplier by an end- '
Common equity: the value of common a certain period of time, expressed as a user and'transported; for a fee, by a local dis-stockholders'niestment in a company along percentage tribution company such, as NYSEG with retained eaminy 'Nnrket Io book ratio: an indication of Unbilled revenuesi the estimated eu-Conipetitive bidding: a mandated pro-,,the market's perception of a stock's value (a,,
nues attributable to energy which has been cess. by which utilities must seek bids for ad-,
ratio of-over,100 indicates that. the m'arket
'elhunxl to a company's customers but for ditional generation or. demand management beliefs the stock is worth more than its book which the metenxl amount has not been (Dibi) projects
-'alue) billed to the customers Dekatberm; a measure of heating value.
Net lncomei earniny after all expenses IValt: one ampere of electric current under.
equal to one million Btu (1,000 cubic feet of are recognized, but before prefernxl dividends one volt-of pressure (one kilowatt is 1,000 natural gas (one mc0 equals approximately are paid watts; one kilowatt-hour is one kilowatt used
- one dekatherm)
Peak load: the point of highest custome~r for one hour and one'megawatt,is 1,000 kilo-Demand managectrenti the planning and demand for electricity (NYSEG is a winter watts or 1 million watts) implementation of programs designed to help, peaking utility;it's nxonl peak is 2,597 Yield: the return which dividends provide resi'dential,'commercial and industrial electric megawatts)
~
a shareholder calculated by dividing'the customers conserve energy,
'rice/earnings (P/E) ratio: a measure-
~
annual dividend per share by the current
~
ment of the market's perception of a corn-market price per share i
EIMVCIALAND OPERATING STATISTICS
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ IO ~ ~ ~ ~I~ ~ ~ ~
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1991 1989 1988 1987 1986 1981 OPERATING RMSUES Efectric Natural as-
$ 1,367,936
$ 1,334,509 187 879 162,271
$ 1,266,668 16i o77
$ 1) 191,806
$ 1,136,799
$ 1,098,089 148,363 152,839 179,195 Pbortsnnrts, except Per Sbrrre Amoants) t
$674,740 158361 TOTAL OPERATING EXPENSES Fuel used in electric generation Electricity purchased Natural gas purchased Maintenance Depreciation Federal income taxes Other taxes Other o ratin e
nses TOTAL 274,245 34,613 88,589 106,665 147,659 89,577 158,770 281,305 274,877 45,808 99,528 110,131 152,380 94 447 178,185 288 684 I 244 040 1,181,423 I 555 815 1,496,780 1,427,745 279,075 26,019 101,598 97,420 148,375 64,4s9 146,6oS 251,431 1,115,012 1,340,169 1,289,638 1,277,284 238371 29302 Ili,147 ss,4s6 100,796 122,987 122,400 182 710 253,326 249,520 19,432 29,638 82,822 90,974 90,097 93,274 134,037 110,679 81,689 110,355 136,706 128,776 214,541 195,204 1,012,650 1,008,420 996,199 833,101 177,592 72,591 112,176 s1,616 49,44s
'3,844 72,935 108,294 688,496 OPERATING I COME
~
AFDC - other and non-cash return Other-net
'11,775 2,S43 12 853 315357 698 10,270 312,733 327,519 281,218 281,085 1)374 14,042 60,816 78,942 18,727 14,890 (134,692) 34,795 144,6o5 24,742 9,237 INCOME BEFORE INTERESI'HARGES 327 171 326325 332,834 356,451 207,342 394,822 178,584 INTEREST CHARGES Interest on long-term debt Other interest AFDC '- borrovtef 151)649 11,877 (4998) 158,209 164,573 15,181 15,495 (5,078)
(5,013) 187304 195,264 187,238 12,426 7,057 12,020 (14,746)
(47,312),
(32,930) 68,773 9,987 (7,977)
INTEREST CihRGES-NET 158 528 168,312 175,055 184 984 155,009 166,328 70,783 INCOMF. BEFORE CUMULATIVE EFFECT OF ACCOUNTING CIIANGES Cumulative effect for )ea5 prior to 1987 of accounting change
'or disalfovel project costs (less applicable taxes of
$95,434)
Cumulative effect for pars prior to 1987 of accounting change for income taxes 16s,643 NET INCOME (LOSS) 16s,643 PREFERRED STOCK DIVIDFSDS 20 330 158,013 158,013 12,662 157,779 157,779 12975 171,467 52,333 228,494 (210,914)
(19,156) 171,467 (177,737) 228,494 13,492 13,662 20 104 107,801 107,801 17 536 EARNINGS (LOSS) AVAILABLE FOR COMMOiV STOCK COMMOiV STOCK DMDENDS 148,313 131 875 14s 351 121302 144,so4 115,224 1
157,975 '191399) 208390 112,252 145,794 140,432 90,265 58,657 RETAI)VED EARiVINGS INCREASE (DECREASE)
$ 16,438
$24,o49
$29,580
$45,723
($337,193)
$67,958
$31,608 Average number of shares of common stock outstanding 62,906 Earnings (Inss) per share
$2.36 Dividends paid per share
$2.10 56,239 55318
$2.sl
($3.46)
$2.oo
$2.64 58,678
$2.4s
$2.o6 57,138
$2.s3
$2.O2
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ I ~ ~ ~ ~ I ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
54,o14
$3.s6
$2.60 30,586
$295
$ 1.94
/
4
'I I'IMVCIALSTATISTICS
~
~
h
~ ~ o'
~ ~ ~ ~
'I
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~
I J
II FINANCIALSTATISTICS Return on average common stock equity-percent
~ Percentage of AFDC and non~h return to total eaminy Mortgage bond interest-times earned Interest charges and preferred dividends-times earned, Book value per share of common stock
()ear end) hiarket value per share of common stock ()ear end)
Dividend payout ratio (percent)
Price eaminy ratio ()ear end)
PROPERTY, PLANT AND EQUIPMENT (ItiCLUDES CO>VSTRUCTIO>V IVORK IiV'ROGRESS)
Electric Natural gas Common 1991
- 1990, 1989,
~
1988 1987 t, 1986 io.7 ii.4 r
s.i
'.o 3.0 2.9 12.2'5.3 11.5'3.2;.
4.6 i5.5 2.6 1.8 1.7
.29
$20.71 50.3 53.7 1.6
2.9 1.2 1.9
$ 19.85
$25.86 r
$20.88
$31.38 82.2",
67.4 6.5** -
8.1 1.8
$22.f6 1.8
$21.85
$21
$26.00
'$28.88
'22.75
'3.1 79.8 71.2, 10.5 11.4 8.1
$29.00 89.0 12.3 (Tbousands)
$4,537,356
$4,367,913 S4,217,920
$4,089,485
$3,885,989 336,199 222,125
'201,942 189,580,
. 176,019 189,135 I
175,703 155,340 '29,860
- 100,252
$4,129,838 i64,426 78,78f
,1981 I3.4 36.3 2.8 1.9
$22.15,
$ 15.00
,65.8 5 Ir
$2,105,593 133,156'9,278
-*TOTAL
$5,062,690
$4,765,741
$4,575,202
$4,408,925 S4,162;260
$4,373,045'2,288,027 ACCUMUIATEDDEPRECIATION
'APITALIZATIO>V (INCLUDES CURRENT MATURITIFS)
Long-term debt Preferred stock Common stock e'i
'I
$ 1,309,829
$ 1,174,651
$ 1)063,630 r
$ 1,825,918
$ 1,815,686
$ 1,501,762 270,700,172,350 174,000 1,405,147 I 364 344 I 225 184
$956,415
$855,198 I r (Tbousands)
)$ 1,985,276
$2,091,678 178,650 183,320 1,174,028 1,106,518
$ 1,959,0tI9 217,970 1,397,962
$863,398 246,812
-722,709'769,336
$490,579 TOTAL CAPITALIZATION
"'3,501,765
$3,352,380'3,200,946
$3/37,954
$3 381 516
-$3,575,021
$ 1,832,919 CAPITALIZATIONRATIOS (PERCENT) t Long-term debt Preferred stock Common stock equity NUMBER OF STOCKHOLDE15 Common stock Preferred stock PAYROLL (IiVCLUDINGPEiVSIONS, ETC.)
Charged to operations Charged to construction and other accounts 52.2 7 7 4o.i 59,593 3,943
$ 163,421 82,555 54.2 51 4o.7 60,585 4,o68 Si48,oo7 72,76i 56.3
,54 38.3 62,552 4,238 Si4o,4i5 64,890, 59.5
-5.3
'5.2
'66,689 4,444 (Thousands)
$ 132,617
'i,go8 61.9
'4
'32:7 4,583
$ 134,484 54,276 54.8 6..1 39.1 71,935 6,o6o
'5126,307 55,936 47.1
]3 5 39.4 71,4lvi 5,932
)83,044 3
44,504 TOTAL
,$245,876
$220,768
$205+05'194,425
$ 188,760
~
$ 182,243
$ 127;548 Number of employs ()var end)',
4,842
'4,599 4,558
" 4,494 4,498 4,423 4,307.
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ rr ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~
~
~ ~
~
~
P
'Return of> average common stock equity for 1987 exdudes the effects of the iivitewffof Nine hiile Point nuclear geperating unit No.2 (NhlP2) and Jamesport disalkeed costs and an accounting change for income taxes. ',
~-
'the return on equity. for 1988 and 1989 exdudes the NMP2 witooifadjustments.,
"Exclu'des the 1987 witewfs and mounting change.
h
/
- 'LECTRIC SALFS STATISTICS
~ /=
~ ~ ~ ~ ~ ii ~ ~ ~ // ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ /) ~ ~ / ~ ~ ~ ~ ~ ~ ~ /'
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~
/~ ~ ~ ~ ~ ~ ~ ~ // ~ ~ ~ ~ ~ //
'/
\\
1991 1990 1989' 1988
)
'1987 '1986 1981
'ILOWJTf-'HOUR (KWH) SALES.
(MILUONS)
Re'sidential, ',
Commercial Industrial-Other SUBTOTAL Other electric utilities TOTAL 5,297 3,285, a,068 i,4s7 13.107 S,o66 18,173-5,319 3,235 3,175 i,46s 13,197 4,750 17,947
/
5,233 3,181
,3,210 1,431'3,055 4,461 17,516.,
5,148 3,069 3,159 1,400 I2,776 3,896 i6,672 405,.
2,882 3,018 1372 12,177 4,295 i6,472,.
4,791 2772 2,899 U45 11,807 3,545 15,352 4,429 2,516.
',845 1,218 11,008 i,6o2 12,610 OPERATING REVENIJES (THOUSANDS)
'Residential
~
)
$553,056
$ 521,688 Commercial
'2931197>>
267,598
~
Industrial
'07,933 196,016 Other 124,575 ',
116,352 Unbilled revenue reco ition.
35,333
~
42,995
$510,941
~
$507,428 261,606 257,707 196,701,>>
'98j44 114364 113,$76
)483,531
$457,132 244;416
'35,246 190,806
'87)'372-110,846>>
109,181>>'271,335'42,643
~
~
121,618 Q,113 SUBTOTAL 1,214,094 i,i44,649-1,083,612 1,077,055
-1,029,599 988,931 599.709 Other ekdric utilities Othero ratin revenues 131,412 22,43o 145,104
~ 44,756 134,108 48,948 89,784 24,967'09,453'2,253) 95,70'7 13,451 65,863 9,168, TOTAL OPERATING REVENUES.
$ 1,367,936
$ 1 334,509
$ 1,266,668
$ 1 191,806
$ 1,136,799.
$1,098,089
$674,740, OPERATING REVElv'UES PER IPVfI (CENTS).-
Residential Commercial "
Industrial Other Total Retail
.= Other ekctric utilities AVERAGE REVEifUE PER KWH NUMBER OF CUSTOMERS (YEAR END Residential
. Commercial Industrial Other 10.44 9.81 9.76 8.93 8.27 '.22 6.78 '.17.,
6.13 8.55 7.93>>
7.99 8.99 835 <<8.30 2.59 3.05 3.01 7:33'.20 7.23 692,922
'85,898 -, 676,590 71,463 70,802 69,230 I
1,506 1,498,
- ',465 10,907 10,825 10 694 757,979 769,023 TOTAL" 776,798 9.86 s.4o 6.28 v 8.11 8.43 2:30 7.15 66s,296 67,4ss 1,437 io,ss6 744,777 9.86 9.54 8.)8
'8.49 6.32 6.46 8.08 8.12 8.46 ')
8.38'.55
~
2.70 65,923 r 1,411 10363',603 1)388 io,si6 731,095
. 716 601 6.90 7.15
)
653,398 640,094
~
6.13 s.67 4.27 5.26, 5.45 4.ii 5.35.
600,803 58,455 1,333 9,887 670478 ANNUALAVERAGE USE (KWH) ~
-'esidential Commercial Industrial (thousands)
ANNALAVERAGE BILL~
'esidential Commercial 7,672 45,864',047
$801 4,093 Industrial 138,714
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ C>> ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ >>'/ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~i~
'Computed using the <<etghted average number of customers
/
7,796 4s,s26 2,i42
$76s.
3,791 132,265
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
for the Jear.
7,786 46,o9S
~
2,200
$760
-3,791 134;819 7,791 v
7;569 45,600 43,787
=2,226 2,134
=
$768
$746 3,829 3,713 139,777
'34,941
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ / ~ ~ ~ ~ >> ~
7,538 42,935 2,081
-7,393
'43,2S7
~
2)iIII
~
$453 2,452 90,221
$719
.- 3,644 134,510
>>)
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ >> ~ ~ ~ ~ ~ +/ ~ ~ ~ ~ /
U
r' BLECTRIC GENERATION STATISTICS I
SYSTEhl CAPABIUTY (hlEGA)VATIS)
Coal Nuclear Hydm=
Internal Combustion 1991 2,412 198'0
.). 8 r
1990 2,414 194 68 7
1989 2,414, 193 7-1988 2,405 67 7
1987 1986 68-68 2"
7 1981 I;720 TOTAL GENERATING CAPABILITY 2,686 ',683 ',680 2,673 2,461 2,441
~ 1,769 Purchased-Powr Authority
'-IPP'ess:
Fiim Sales 488 487.
487 510 110 53 9
(115)
(125) 509'63 764 242 TOTAL SYSTEM CAPABILITY 3,284 3,223 3,061 3,058 2,970 3,004 2,775 SYSTEM CAPABILITY(PERCENT Coal r
Nuclear
-Hydio ',
Internal Combustion 74 6
<<2
'I
) '75 6
2 6
"2 79 6
2 81 79 62' 2
r Purchased-Povter< Authority
~
-IPP'ess:
Firm Sales" t, 15 3
TOTAL'ENERATINGCAPABIUTY 82 83 15 2
87 16'7 r
(4)
(4) 83 81
'l,7 t,-
19 r
27=
'TOTAL SYSTEM CAPABILITY ~
PRODUCTIO( STATISTICS>>
Annual load'actor (percent)
Coal burned, (thousands of'net tons)
Coal heAt value (Btu per lb.)
Btu per kwh generated (net)
KILO'tVATI',-HOUR(KMI) PRODUCTION NET (MILUONS)
Generated:
r',
Coal
'Nuclear
=
H'dro
~ ~
TOTAL-GENERATED 100 100 100 68.9 6,310 12,610
.9,898"
/
16IIS7 11180 258 69.4, 64.2 6,39s 6,472 12 510'2 477 9,936,,
9,931 16,211
~
16345 743 773 356 292 17,410 17,595 17,310 100 100 15,589 "15,025 639 -
60 245 280 15365 i6,473 63;5 '5.5 6;106 5,956 12,572 12,487 9,881 t "II,897, 66.3
- s334, 12,335 9,959 13,196'.
t.
338 13.534 100 J
64.4 4,867,
>>,600 10,701 10)552 210 10,762 Purchased-Pomr Authority q
1,667 1,607 ',667
-Other ~,
343 347 102 1,743 4s 1,911 583
>> 2,590~
464 2,061" 904 TOTAL 19 605 19,264 19,179 18,261 17,859
'16,588 13,727 PRODUCTION 'EXPENSES (TIIOUSANDS)
Generated,
$391,393
$391,977
$381,371 '351,963
$332,250 Purchase'd 45,808
'4,613 26,019 19,432 29.638
$318,885
'29302
$216,805,,
.-72,591
'OTAL
$437,201
$426,590)
$407390
$371395
$361,888
$348,187 COST PER IMI (MILLS)
Generated Purchased
'n (excludin mduction) 22.24 22.79
,11.79 22.64 17.71 12.32 21.91' 21.37 21.62.
23.56 14.71 10.87 11.88>>
9.59 11.20 9.65 9.79,9.85 20.15 24.48 7.35
-'OTAL 34.09
-34.46 32.44 2999 30.05 30.05 ELECTRIC OPERATIOiV AND MAINHAANCE
)
EXPENSES (THOUSAVtDS)
Pmduction,
~
$437,201 Transmission
=-30,462
, Distribution 62,763 Customer accounting
. 37722 Customer service
>> 24,345 Administrative and eneral
~
~
75-812
$426;590 30,118 r 58,876 38,838 27,625 81,815
$407390 29,239
$371,395 22,196 54,420,, 49,t37 35,370 '1,522 23,426 20)527 72 405 62,258
$361,888
$348;187
'24314 22,438
>> 55,673 49,:522 20,158
'9,220 12,047 8,867 62660 63,328
$289,396 11308 32,287 I3,449
-3,719 40,129
- TOTAL,
$668,305
'663;862
$622,250
$547,635
$ 536,740
$511,562
- $$90,288.
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ) ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ r ~ ~ ~
'Independent Iotjter pnxtucets.'
MTMALGAS QLES STATISTICS DEKATIIERhi (DTH) SALES (THOUSANDS)>>
Residential Commercial Industrial-Other SUBTOTAL Transportation of customer<wned natural as TOTAL
- 1991, 171920 7,955 1,779 1.916 29,570 12,228 41.798 1990 I4,809
. 6,532 2,023 2,151 25,515 8,157 33,672 1989 15331 6,926 2,167 2,071 26,495 8,853 35348 1988 14,818 7,055 3,121 2,242 27,236 7,825 35,061 1987 13,897 6,803 3,038 2,499 26,237 5,959 32,196 1986 14,139 7,343 5)126 3373 29,981 3,287 33,268 1981 16,412 s,o44 11)509 3,991 39,956 39,956 OPERATING REVERES (THOUSANDS)'esidential Commercial Industrial
-'ther Unbilled remnue reco ition
$ 110,519 43,729 8,604 10,243 4
633'94,531 37,852 101267 ii,574 853 38,726 10,437 io,776 35,680 12,821 10,738
$93,873
$83,115
$s5,242 37,620 13,909 iz,6zo
$91,068
'42,711
'4,429 17,783
$71899 30,989 40,077 14,117 SUBTOTAL Transportation of customer-owned natural gas Other natural as revue SUBTOTAL 177.728 9,571 580 10 151 155077
',7,169 25 7,194 153,812 6,721 544 7,265 142354 5,523 4s6 6,009 149391 2,931 517 3,44s 175,991 2,168 1,036 3,204 156,582 1,779 1,779 TOTAL OPF RATING REVENUE
$ 187 879
$ 162,271
$ 161;077
$ 148,363
$ 152,839
$ 179,195
$ 158,361 OPERATING REVENUES PER DTH Residential Commercial Industrial Other Average NUhtBER OF CUSTOhIERS (YEAR F~ID)>>
Residential with house heating Residential without house heating I
Commercial with space heating Commercial without space heating Industrial Transportation of customer-owned natural gas Other
$6.i7 5.50 4.s4 5.35
$5.85 178,625 12,906 23,023 z,z4i 386 342 1,557
$6.38 5.79 5.08 5.38
$6.o4
$6.12 5.59 4.82 5.20
$5.83 117,429 s,36o i6,s43 114,497 8,079 16,626 277 I,246 228 i,i54 i,54s i,476
,334 '43
$5.61 5.o6 4.ii 479
$5.24 111,543 8,340 16,419 i,444 343 z14 1,133
$6.13 5.53 4.58 5.05
$5.71 108,515 8,220 i6,265 i,4os 4oo 149 1,202
$6.44 5.82 4.77 5.27
$590 I06,006 8,286
. 16,221 1,417
, 399 I
39 I,I74
$4.35
. 3.85-3.4s 3.54
$3.96 103,273 9,509 14,oz4 1,109 390 1,132 TOTAL 219 080>>
I46,037 i42,4o3 I39,436 136,159 133,542 129,437 ANNUALAVERAGE USE (DTII)>>>>
Residential Commercial Industrial ANNUALAVERAGE BILL>>>>
Residential Commercial industrial COST OF NATURALGAS PURCIIASED Amount (thousands)
Per dth NATURALGAS OPERATION AND MAINTFSANCE EXPENSES (THOUSANDS)
Production Tmtsmission and distribution Customer accounting Customer service Administratiw and eneral I26 386 6,246 146 550 29,137 120 387 7,6i4 119 358 6,oo3 125 398 8,694 125 419 iz,657 103 340 4,757
$638
$763 1,871
)
2,076 23)005 30,466
$738 2,139 34,s6o
$774 2,158 30,079
$703 2,012 35,713
$803 2,437 60/19.
$636 2,120 io1,461
$88,5s9
$3.64
$82,822
$3.02
$99,528
$3.3o
$90,974
$ 111,147
$ 112,176
$3.43
$3.75
$2.sz
$ 101,598
$3.57
$ 101)458 18,491 8,505 6,533 15.735
$ss,90i 13,982 6,264 5,942 6464
$ 102,014 I3,247-5,489 3,972 8,571
$83,155 11,712 4,6o7 3352 9,758
$91,369 11,570 4,656 2374 11,901
$ 111,538 11,013 4,os5 2,227 9,589
.-$ 112,410 8,249 2,975 871 7,476 TOTAL
$ 150,722
$ 121,553
$ 133,293
$ 112,584
$ 121,870
$ 138,452
$ 131,981 Ihe increase is primarily due to the acquisition of Columbia Gas of New York; inc.
"Computed using the weighted average number of customeis for the lear,
~ ~ ~ ~
~ ~ ~ ~ ~
~ ~
~ ~
~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ I
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
NKSTORNFOEbRTION Btngbamton Executtve Ofitces 4500 Vestal Parkway East P.O. Box 3607 Binghamton, NY 13902-3607 (607) 729-2551 Ithaca Evecuttve aces Ithaca-Drltien Road P.O. Box 287 Ithaca, NY 14851-0287 (607) 3474131 General Counsel Huber Lawrence &Abeli 605 Tlurd Avenue Nsv York, NY 10158 Independent Accountants Coopers &Lybrand 1301 Avenue ofthe Americas New York, NY 10019 Topresent certtftcates fortransfer, (certilied or registered mail is recommended)
Manufacturers Hanover Trust Company Attention: StockTransferAdministration P.O. Box 24935 Church Street Station rew York, NY 10249 Por stock transfer tnstructtons, write to:
Manufacturers Hanover Tmst Company Attention: Legal Transfer 450 IVest 33rd Street New York, NY 10001 Please contact NYSEG sbarebolder servtces rvttbquesttons regardtng:
~ dividend payments or lost dividend clrecks
~ direct deposit ofdividends
~ our dividend reinnstment and stock puxhase plan
~ rep!acement oflostcertificates
~ a change ofaddress
~ report requests
~ our annual meeting ofstockholders We are avatlable between 8 a.m. and 4:30p.m. (Eastern Time) on regular business days bydialing 1-800-225-5643.
Or you maywrite to:
New YorkState Electric &Gas Corporation Attention: Shareholder Servins P.O. Box 200 Ithaca, NY 14851 You may also obtain a free copy ofForm 10-K, which is fiIed each year with the Securities and Exchange Commission, by contacting NYSEG shareholder services at the telephone number or address above.
t Securtttes Ltsted on tbe New YorkStock Evcbange
~ Common Stock
~ 3.75% Prefemd Stock
~ 8.8%Preferred Stock
~ 8.4F/o Prefemd Stock ($25 par value)
~ Adjustable Rate Preferred Stock ($25 par value)
~ 7 5/8'int Mortgage Bonds (Due 2001)
~ 9 3/8/o First Mortgage Bonds (Due 2005)
~ 9 3/F/o First Mortgage Bonds (Due 2006)
~ 85/8/o First Mortgage Bonds (Due 2007)
Tradtng Symbol The trading symbol forour stock which is listed on the New YorkStock Exchange is NGE.
Annual Neettng Friday, May 8, 1992 at 11 a.m.
ithaca Executive 01105 Ithaca-Dryden Road, Dryden, NY Formal notice ofthe meeting, a proxy statement and form ofproxywillbemailed to stockholders in early April.
h'et@ )'orkSLv(e8&ried Cu Corporation Il/~ca-DgYien Rond P.O. Btm287 Ithaca, N'4851 BULKRATE US POSI'ACE PAID Iles YorkState EIeotrto &Gas GorPNation Docket 0 o-~>~
lillGS BIoll II~V Date ~
~
of Itr
-'NOTICE-THE ATTACHED FILES ARE OFFICIAL RECORDS OF THE INFORMATION 8 REPORTS MANAGEMENT BRANCH.
THEY HAVE BEEN CHARGED TO YOU FOR A LIMITED TIME PERIOD AND MUST BE RETURNED TO THE RE-CORDS 8 ARCHIVES SERVICES SEC-TION P1-22 WHITE FLINT. PLEASE DO NOT SEND DOCUMENTS CHARGED OUT THROUGH THE MAIL.REMOVAL OF ANY PAGE(S) FROM DOCUMENT FOR REPRODUCTION MUST BE RE-FERRED TO FILE PERSONNEL.
-NOTICE-
k l
The Long Island Lighting Company's 6,600 employees provide electric and gas service to 1 million customers in Nassau and Suffolk Counties and the Rockaway Peninsula in Queens County.
LILCO's service territory covers 1,230 square miles with a population of approximately 2.7 million people.
Bridgeport Connecticut New Haven i
Nt w London
/
White Plains Long Island Sound
".ihelt>> r lalalal 'q tto1lt,n(tk Point New York Port J(Cf(e(on I
Northport
(
Huntintaon
'ronx t'l('n tk>>>> '.
t 1
Suffolk
('t>> nwood 'n"n '"""
k'.(n,tt t Ro>>lyn
))
k
))I ~:
I NaSSau;.
Br(ntlk(N)(l Queens Pate)N)g(N" e
e no (iarden (".ity 'ay Bhon..
}{en)p4ttvnt e
Bellman Kings litwh tt lvhmd Park Pill toekaw y Jon Be leh Ji1tll (' ja)rt Riverhead I'.~)at Hampton Blidg(fit(alp'ton Booth<<mpton Atlantic Ocean Territory Served by Long Island Lighting Company e'
Table of Contents Highlights To Our Shareowners Creating Partnerships Electric Operations Gas Operations Conservation Services Customer Outreach Building for the Future Financial Review Report of Independent Auditors Audited Financial Statements and Notes Selected Financial Data 10 12 14 16 22 42 On the cover: Commissioned by President George 1Vashingt(rn in
- 1795, the Montauk Lighthouse is one of Long Island's most recognizable landmarks.
Phot(r right: lang Island's Suffolk County boasts a thriving agncultural industry tvith 35,000 acres offarmland producing 8115 million in prrrducts each year.
cubi 4
lights EI~
Ef EI l'CW e
a s ad% ~
r I
rr ii
'rwr E~.
i)
Ee
~t 0
g!
I
) ~
I
'.Cr "-',
t-r Ar 4
,, ',;w.P4-',V>> =r-
'L', ~
.- 'i a
g-.,
Vr 4 ~
tg!
Column stock quarterly dividend increased ~r e ~
I >~tm egndgeneralandreinndingtrends tgt d
oi% notch.
- ~
~ Unsecured debt and preferred s&8$ raised to nvestment grade.
o mon stra:tr trade/ on ~rage aire 20 yegr hig-ti, ss ie
To Our Shareowners, LILCO's financial health continued to improve in 1991.
Earnings for the year were $239 million or 82.15 per common share, and we increased our quarterly common stock dividend by 13 percent to 42.5 cents per share, effective October 1, 1991.
The PSC granted the Company electric rate increases of approximately four percent for each of the next three years, a sign that the Commission is fulfillingits obligation under the 1989 Shorcham settlerncnt. The PSC also authorized a one-year gas rate increase of 4.1 percent.
As a
- result, the Company's first mortgage and general and refunding bonds were once again upgraded by investment-rating
- agencies, allowing us to borrow money at lower interest rates.
Wc entered 1991 with the country perched at the brink of the Persian Gulf War, engendering an escalated concern over our nation's dependence on foreign oil. LILCO responded to that concern with aggressive sales ofnatural gas and a comprehensive conservation campaign.
Natural Gas Business Over the past two years, we installed gas heat in more than 20,000 homes and businesses on Long Island as we successfully market our product and expand our pipelines into new neighborhoods.
On Long Island, 3 out of every 4 homes heat with oil which presents us with an opportunity to convert many homes to natural gas heat.
With the completion of the Iroquois pipeline which is now transporting gas from Canada to Long Island and a proposed new pipeline from New Jersey to Long Island scheduled to be completed in 1994, we willhave sul'ficient gas supplies to take advantage of the demand for natural gas. We are poised to expand the gas business throughout the 90s.
Conservation Business The New York Public Service Commission (PSC) has provided utilities with financial incentives to promote energy conservation. LILCO has implemented one of the most comprehensive conservation programs in the country. Our many conservation programs provide our customers with opportunities to control their energy costs and preserve the environment.
Along with our gas
- business, we view conservation as a growth business unit within the Company.
Electric Business As Long Island lifestyles become morc and more dependent on electric appliances, customers are increasingly looking to us to provide their homes and businesses with an uninterrupted flow of electricity.
We have responded with a comprehensive reliability program trimming more trees away from power lines and installing more sophisticated equipment which is having good
- results, despite the many storms thaF affect the Company's more than 50,000 miles of overhead lines.
Last summer, the Company received high marks from government officials and our customers for the quick response in restoring power following the damage caused by Hurricane Bob. The hurricane's 90-mile an hour winds uprooted trees, snapped utility poles and tore down power lines, wreaking havoc with the electric system. Our employees did a superb job in getting power back to our customers.
Creating Partnerships LILCO has taken a leadership position in helping to attract new businesses and more jobs to the community. As a member of the Long Island Partnership, LILCO is taking the lead in developing an economic development program to attract new businesses to the Island. In addition,
LILCO received PSC approval of a new rate design which offers attractive electric rates to companies relocating or expanding on Long Island.
In Febriiary 1991, we introduced the Long Island Energy Research and Development Initiative, a partnership between LILCO and Long Island's academic and research institutions designed to encourage energy research. The initiative allows the Company to take advantage of the research talents on Long Island to improve its operations.
Service First As 1991 drew to a close, we witnessed the end of the cold war with the extraordinary breat-up of the Soviet Union. At LILCO, we also sought a new organizational structure, which would empower our employees to assume responsibility for the profitability of the Company and provide better service to our customers.
We selected an organizational structure to complement our very successful Service First prograln 1Uhlch ainls at providing oui'ustomers 1Ulth unparalleled service.
We are making great strides in becoming a premier service organization as our employees display genuine care in serving our custonlcls.
On behalf of LILCO's Board of Directors and Officers, I extend my sincere thanks for your support in 1991. We are making great strides in our quest to provide unparalleled service; yet there is still much to accomplish. With the hard work and commitment to excellence that has been demonstrated by LILCO employees, we will continue on the steady track towards service excellence.
<<I '
Sincerely, William J. Catacosinos Chairman and Chief Executive Officer William J. Catacosinos Chairman and Chief Executive Officer
<<t.
~<<,
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"Economic development projects benefit the community by broadening the tax base and increasing jobs in the region."
LILCO President Anthony Earley tt Partnership lilith Long Island Creating Partnerships LILCO has set out to become a customer-driven organization, providing unparalleled service to our customers.
We have improved service to customers by responding courteously to customer inquiries, reducing electric service interruptions, responding quickly to electric and gas service
- requests, and meeting commitment dates on new service installations.
In 1991, we extended our service goal a step further by taking a leadership role in the Long Island community. In February 1991, LILCO created the Long Island Energy Research and Development Initiative. The Initiative supports research on energy-related issues, using Long Island's considerable technological talent to improve methods of producing and distributing electricity, natural gas and conservation services.
In May, we introduced an economic development program designed to attract new businesses to Long Island and to encourage businesses already on the Island to expand.
The program urges environtnentally sensitive growth by combining electric rate incentives with energy-efliciency requirements.
Explains LILCO President Anthony Earley, "Economic development projects benefit the community by broadening the tax base, increasing jobs in the region, and holding down the electric rates."
Photo rigltt Long Island's rapidly growing hlcrtrtlturAirport Itantllcs botlt commuter andjet service daily.
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LILCOsignificantly improved its electric reliability in 1991, a key element in customer satis-faction. The Company reduced the frequency of electric outages by extensively trimming trees and upgrading equipment throughout the electric distribution system.
We also enhanced reliability with new transmission lines; one across Shelter Island provides a continuous loop of electric power between the North and South forks, and another provides a second link with the State's electric grid by connecting Nassau and Westchester Counties.
The Company is improving response to the day-to-day service requests of our customers as we begin to install computers in our service trucks, allowing us to dispatch job infor-mation directly to our field workers.
We are also developing a new computerized system for scheduling service appointments, which lets us accurately schedule electric service calls so that our customers know exactly what time a LILCO representative willarrive at their home.
As part of the Company's multi-year capital improvement plan, major equipment ovcrhauls and upgrades werc conducted at LILCO's Northport, E.R Barrett and Glerrwood generating facilities. The result of these power plant improvements was a Company-wide system availability of 87.1 percent for thc year, a LILCO record.
Plioto left: EAD Plaza in Uniondale is one oftire Island's most rvell-knorvn once complexes.
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Gas Sales (adj usted for tvcathcr) detmthemrs 51,854,000 53,156,000 54,658,000 1989 1990 1991 A Partnership 1Vith Long Island Gas Operations
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Skyrocketing oil prices due to the Middle East crisis caused many Long Islanders to convert to natural gas heat in late 1990.
But even after the war, when oil prices felland fierce competition from a coalition of Long Island oil heat companies increased, we installed morc than 10,000 new gas heat customers, a good sign for future gas expansion.
LILCO's marketing efforts concentrated on natural gas as a price-stable, clean-burning fuel the smarter fuel choice for our customers, both economically and environmentally.
By combining its superior product with its superb service organization, LILCO offers customers an attractive alternative to oil heat. In 1991, LILCO developed a new Full-Service Gas Conversion program to make the conversion process hassle-free for customers.
By handling all thc necessary details, from arranging financing to supplying a contractor, we offer customers a "one-stop shopping" approach.
Initiated as a pilot program in September, the program has received enthusiastic response from our customers, and LILCO expects to expand the program Island-wide in 1992.
Thc Company's aggressive approach to natural gas sales also included an expanded Gas Main Extension program, bringing more than 140,000 feet of ncw gas mains into communities that previously did not have access to natural gas supplies.
Photo rights Entenrnann's Bahery lorvered operating costs by converting their ovens to natural gas.
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Conservation Customer Contacts 346,311 205,093 1989 265,057 1990 1991 tt Partnership IVith Long Island Conservation Services VV Successful energy conservation programs provide options for our customers to help them lower their energy bills, while helping LILCO meet the coinmunity's energy needs.
More than 20 percent of our customers took advantage of the Company's energy conservation programs in 1991, saving an estimated 209 megawatts, or enough power to supply more than 100,000 homes.
Last year, LILCO's new lighting rebate program offered customers the opportunity to purchase screw-in fluorescent bulbs directly from LILCO and receive a $6 rebate on every bulb ordered.
Long Islanders purchased more than 60,000 bulbs from LILCO in 1991.
The Company also introduced an energy-efficient refrigerator rebate program, offered in conjunction with local retail appliance dealers and the New York State Energy OAice. The program, implemented in July, gave customers up to $120 in rcbates for purchasing cnergy-eAicient refrigerators.
By the end of the year, more than 3,700 custoiners had received rebatcs.
Conservation options for coinmcrcial and industrial customers were expanded as well, with rcbates available for additional technologies and customized energy-eAicient systems.
Programs were designed to help businesses, new construction projects, and not-for-profit organizations make their facilities as energy-efficient as possible.
The Company also created specialized workshops for Long Island's school administrators, helping them choose energy conservation measures to lower operating costs and ease tight school budgets.
EV Pltoto Iefit Energy specialist Ivaren Buswciler advises eustotner Rub>'itclli about efficient insulation.
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120,000 68,000 80,000 1989 1990 1991 A Partnership 1Vith Long Island Customer Outreach An important part ofproviding unparalleled service to our customers is creating and supporting community outreach programs.
LILCO has put in place special programs for seniors, educators, youth and low-income customers.
For senior citizens, the Company offers Golden Link, a program designed to provide seniors with information on energy issues, community resources, and health news. In 1991, Golden Link membership increased by 50 percent to 120,000 members.
To assist Long Island educators, LILCOspearheaded a special project to develop environmental curricular materials specific to Long Island. With the State University at Stony Brook and 26 local secondary school teachers, the Company produced materials on topics such as energy conservation, recycling and solid waste management for Long Island schools.
For Long Island's youth, the Company initiated many programs, including the LILCOScout Academy, where morc than 600 scouts learned about energy, safety and environmental issues.
Participation in the Scout Academy assists these youngsters in attaining an energy merit badge.
The national recession has troubled many Long Island families, and LILCO has responded to customers in financial crisis by providing trained social workers to help families receive support services.
In addition, our successful "Energy Packager" weatherization program provides energy conservation assistance to low-income families to help them reduce their energy bills.
Photo right: Youngsters at Santapogue Elcrnentary get a lesson in electricsafctyfrom LILCOrctiree Enrico Scena.
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"We are working toward a model that will help us better serve our customers."
LILCO President Anthony Earley A Partnership lVith Long Island Building for the Future In 1992, LILCOwillcontinue to create and implement new programs to bring thc Company closer to achieving its goal of unparalleled customer service.
Thc Company will begin to implement a major Company reorganization plan, designed to further our goal of becoming a service-driven organization.
Iil the reorganization, the Company will consolidate activities into three distinct business units Electric, Gas and Conservation with support services assigned specifically to each unit. The reorganization willalso decentralize thc gas and electric businesses into geographic regions to bring decision-making closer to the customer.
A "one-stop shopping" feature will be established for customers conducting business with LILCO, enabling them to complete all transactions through a single point of contact.
Implementation of thc reorganization will be done in phases and is expected to take up to three years to complete.
LILCO employccs played an integral role in the reorganization process.
Representatives from various areas of the Company initially studied thc new organizational structure and meetings were held to solicit feedback from all management employees.
"We are working towards a model that will improve information flow, facilitate decision-making, morc clearly define accountability, and integrate many company functions into the business units theinselvcs," said LILCO President Anthony Earley. "Itis a major under-taking that will help us bcttcr serve our customers."
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Plioto left: Beautifisl beaches on Long Island provide recreation and a chance to build castles to millions.
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- '0 Financial Review Overview The year 1991 was another year of continued improve-ment in the Company's financial health. This improvement is evidenced, in part, by thc elevation by certain rating agencies in 1991 of the Company's First Mortgage Bonds and General and Refunding Bonds (GRR Bonds) from miniinum investment grade to one notch above and the eleva-tion of the Company's unsecured debt by one notch to minimuin investment grade. In addition, one rating agency upgraded thc Company's preferred stock to minimum investment grade. This is the second time in the past two years that the investment ratings of'the Company's securities have been upgraded.
Other significant events in 1991 included:
~ Approval, by the Ncw York State Public Service Commission (PSC),
of a
three-year rate plan granting the Company annual electric rate increases of 4.15%, 4.1% and 4.0%, respectively, beginning December 1, 1991.
~ An increase in gas rates of4.1% effective December 1, 1991.
~ An increase in the Company's common stock quarterly dividend from 37'/2 cents per quarter to 42'/2 cents per quarter.
Earnings for common stock for 1991 were 82.15 per common sharc compared to 82.26 per common share for 1990.
~ Refinancing ofapproxiinately $1.2 billionof high-cost securities which significantly lowered the Company's cost of debt and preferred stock.
~ Issuance of $ 100 million of low-cost tax-exempt securities resulting in substantial savings for the Company's ratepayers because these securities carry significantly lower interest rates than taxable bonds.
~ Completion ofthe Iroquois Gas Transmission System, increasing thc reliabilityofthe Company's gas supply and enabling it to provide natural gas to an additional 40,000 homes.
~ The addition of morc than 10,000 new gas heating installations, 34% of which were residential conversions.
~ Receipt ofa possession-only license from thc Nuclear Regulatory Commission (NRC) which willpave the way for the transfer ofthe Shoreham Nuclear Power Station (Shoreharn) to an agency of the State of New York.
Thc financial viability of the Company had bcen-jeopardized in the recent past by the controversy concern-ing Shorcham and the federal Racketeer InfIuenced and Corrupt Organizations Act (RICO Act) litigation. The 1989 Settlerncnt was designed to eliminate the controversy over Shoreham by providing for the transfer of Shoreham to an agency of the State, reciting the intention to return the Company to investment grade financial condition, authoriz-ing fixed rate increases of5.4% and 5.0% in 1989 and 5.0%
in 1990, and targeting annual rate increases of 4.5% to 5.0/o in each year thereafter through 1998 based upon assumptions as originally sct forth in the 1989 Settlement.
The Company's financial recovery began in 1989 following the 1989 Settlement and a class action settlement (Class Settlcmcnt) entered into between the Company and its ratepaycrs to resolve the RICO Act litigation. During 1990, the financial recovery ofthe Company continued as evidenced by thc Company increasing the common stock quarterly divi-dend from 25 cents per quarter to 37'/2 cents per quarter.
The Company also utilized 8100 million of tax-exeinpt securities in 1990.
Liquidity and Capital Resources Cash and Revolving Credit At December 31, 1991, the Company's cash and cash equivalents amounted to approximately 8298 million, com-pared to $ 103 million at December 31, 1990.
In addition, the Company has an estimated $ 114 million available under a revolving line of credit through October.
1, 1992, provided by its 1989 Revolving Credit Agreement (1989 RCA). For additional information respecting the 1989 RCA, see Note 7 of Notes to Financial Statements.
Rate Matters In response to the Company's rate filing in December 1990, the PSC approved the Long Island Lighting Company Rateinaking and Performance Plan (LRPP) which provides f'rannual electric rate increases, bef'ore giving effect to the Class Settlement discussed in Note 4 of Notes to Financial Statements, of4.15%, 4.1% and 4.0% effective December 1, 1991, 1992 and 1993, respectively.
Thc LRPP is designed to be consistent with the long-term goals of'the 1989 Settlement. Onc principle objective ofthe LRPP is to reassign risk so that the Company assumes the responsibility for risks
'ithin the control ofmanagement.
Risks largely beyond thc control of manageinent are assurncd by thc ratepayers.
The LRPP provides for an 11.6% return on common equity for thc three years commencing December 1, 1991.
Under the LRPP, the Company is allowed to earn up to 60 additional basis points or forfeit up to 38 basis points of'the return on common equity as a result ofits pcrforinance within certain incentive and/or penalty programs. These programs consist of a customer service perfonnance plan, a demand side management program, a fuel-cost adjustment (FCA) incentive plan and a time-of-usc program. The LRPP contains a mechanism whereby earnings in excess ofthe allowed rate of return on common equity, excluding the impacts of the various incentive/penalty programs, will bc shared equally between ratepaycrs and shareowners.
In conjunction with the 1989 Settlement, the PSC authorized the Company, in 1989, to record on its books a Financial Resource Asset (FRA). The FRA consists of two components, the Base Financial Component (BFC) and the Rate Moderation Component (RMC). Thc Rate Moderation Agreemcnt (RMA), one of the constituent documents of the 1989 Settlement, provides that the Company amortize the BFC over a forty-year period, through rates, beginning July 1, 1989, and permits a fullreturn on the unamortized balance. The BFC, as initially established, represents the present value ofthe future nct-after-tax cash flows provided to the Company for its financial recovery. The RMC reflects the difference between the Company's revenue requirements under conventional ratemaking and the revenues resulting from the implementation ofthe rate moderation plan provided in the RMA. The RMC is initiallydeferred but is designed to bc fullyrecovered over a ten-year period with a fullreturn on the unamortized balance. The RMA is dcsigncd to hold electric rate increases to thc levels provided for in the 1989 Settlement, subject to adjustments provided therein.
The rate structure under thc 1989 Settlement, as reflected in the LRPP, is intended to provide the Company with adequate and timely rate relief which, when coupled with access to the capital markets, will enable the Company to meet its operating and capital requirements.
In November 1991, the PSC issued a rate order granting a gas rate increase of 4.1% which became effective on December 1, 1991. The gas rate increase reflects costs related to expected levels ofcapital expenditures, operations and maintenance expenses and the Company's gas expansion program. The gas rate order contains a weather normaliza-tion clause which moderates the impact of variations in temperature on gas revenues.
On December 31, 1991, the Company filed a request with the PSC to increase its gas rates effective December 1, 1992, by 5.8% or $30 million in additional revenues.
Although the Company calculated that an increase of 9.8%, or $51 million, is warranted, the Company proposes to collect only 5.8% in the rate year and defer the balance of the request for recovery in later years. This filingreflects the Company's latest projections of capital expenditures, operations and maintenance expenses and continued expansion of its gas business.
For a further discussion ofthe 1989 Settlement and Rate Matters, see Notes 2 and 3 ofNotes to Financial Statements.
Financing Program During the period 1992 to 1995, thc Company estimates that it willbe required to seek external financing ol'pprox-imately $ 1.8 billion. Although a portion ofthis financing will be used to meet its operating and capital requirements, most will be used to refund maturing debt. In addition, the Company
- intends, when market conditions
- permit, to refinance higher-cost debt and preferred stock.
The Company refinanced approximately 81.2 billion of higher-cost debt and preferred stock in 1991 as follows:
~ The Company issued 8250 million of 8/4% G&R Bonds in February, the proceeds ofwhich were used in March to redeem, at thc applicable regular redemp-tion price, $225 million of G&R Bonds, 13'/i%
Series Due 1995.
~ Thc Company issued a total of$830 millionof8 /4%
and 93/~% G&R Bonds in May, the proceeds ofwhich werc used in June to redeem, at their applicable regular redemption prices, 8525 million aggregate amount of higher-cost G&R Bonds. The balance of the net proceeds were used to reimburse thc Company's treasury for previously incurred capital expenditures and to provide working capital.
~ The Company also issued 865 million of Preferred Stock, $2.35, Series Z, in May, the proceeds ofwhich were used in June to rcdecm, at its applicable optional redemption price, $60 million par value ofPreferred Stock, 83.31, Series T.
~ The Company issued"$ 375 million of 9/s% G&R Bonds in August, thc proceeds of which were used to redeem, at its applicable regular redemption price, 8350 million Debentures, 11.50% Series Due 2014.
In addition, the Company utilized $100 million of tax-exempt securities in January 1991 to reimburse thc Company's treasury for previously incurred capital expenditures.
Consistent with the Company's aggressive refinancing strategy to further reduce interest cost to the Company's ratepayers, the Company utilized $ 100 millionof tax-exempt securities in February 1992 to reimburse the Company's treasury for previously incurred capital expenditures.
In addition, thc Company intends, ifmarket conditions permit, during 1992, to refund higher-cost debt and preferred stock.
The Company will also seek permission to utilize the proceeds from thc sale ofan additional 9100 millionof tax-exempt securities which would be sold later in 1992. Thc proceeds would be applied to reimburse the Company's treasury for previously incurred capital expenditures.
The 1989 Settlement cornrnitted New YorkState to support an allocation to the Company ofat least 8500 millionofNew York State private activity bond volume cap (at a minimum of $100 million per year) to pcrrnit thc sale of tax-exempt securities for the Company's benefit. After the issuance of
$ 100 million of tax-exempt securities in February 1992, the Company has at least
$200 million of this volume cap remaining.
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Capital Requirements and Capital Provided Capital requirements and capital provided for 1991 and 1990 were as follows:
The chart beloiv indicates the ratings for each of the.
Company's principal securities at December 31, 1991, and the minimum investment grade ratings used by each agency.
Capital Requirements (In millions of dollaa) 1991 1990 Mood 's S&P Fitch D&P Construction Electric Gas Common S
127 S
138 90 79 18 13 First Mortgage Bonds G&R Bonds Debentures Preferred Stock Baa2 Baa2 Baa3 baa3 BBB-BBB-BBB BBB-BBB-BBB BB+
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",x v Total Construction Refundings nnd Dividends Long-Term Debt Preferred Stock Preferred Stock Dividends Common Stock Dividends Total Refundin s and Dividends Subtotal Shorehnm Post Settlement Costs Total Capital Requirements 235 230 1,129 82 71 14 66 68 173 125 1 439 289 1,674 519 158 153 S 1,832 S 672 (Increase)
Decrease in Cash Long-Term Debt Preferred Stock Financing Costs Internal Cash Generation from 0 craiions Total Capital Provided S
(195)
S 237 1,532 112 63 (88) 2 520 321 S ls832 S 672 Forfnrthcr information, sce thc Statement of Cash Flott?s.
Ca ital Provided In millions o dollars 1991 1990 MinimulllIllvcstlllcllt Grndc BanS BBB-BBB-BBB-Capitalization The Company's capitalization (defined as the total oflong-term debt, preferred stock and common shareowners'quity) at December 31, 1991, was approximately 87.8 billion, as compared to 87.3 billion at December 31, 1990. This increase in capitalization of approximately
$492 million reflects an increase in long-term debt associated with the Company's financing activities in 1991 and an increase in common shareowners'quity comprising 1991 net income of approximately 8306 million offset by $245 million of common and preferred stock dividends.
At December 31,
- 1990, capitalization increased by approximately 8134 million from the December 31, 1989, balance of 87.2 billion. This increase in capitalization priinarily rcflccts an increase in common shareowners'quity coinprising 1990 net income of8331 million offset by $207 million of common and preferred stock dividends.
At December 31, 1991, 1990 and 1989, the components of thc Company's capitalization ratios were as follows:
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For 1992, total capital rcquiremcnts (excluding common stock dividends) are estimated at 8608 million, of which construction requirements arc estimated to bc $316 million, mandatory rcl'undings are
$ 10 million, preferred stock sinking fund requirements are $ 11 million, preferred stock dividends are $64 million, and Shoreharn post-settlement costs are estimated at approximately $207 million.
Investment Rating The Company's securities are rated by Moody's Investors Service, Inc. (Moody's), Standard and Poor's Corporation (SAP), Fitch Investors Service, Inc. (Fitch) and Duff and Phelps (DIP).
The 1989 Settlement was intended to improve the Company's credit ratings. In 1989, the rating agencies significantly upgraded their ratings on each ofthe Company's principal securities. In 1990, the four major independent rating agencies upgraded the Company's First Mortgage Bonds and G&R Bonds to minimum investment grade. In 1991, the Company's Debentures were similarly upgraded to minimum investment grade by two of these agencies which also upgraded the Company's First Mortgage Bonds and GER Bonds one level.
Cn itnlizntion Ratios Long-Term Debt Prcfcrrcd Stock Common Sharcowncrs' uii 1991 1990 1989 63.9%
62.3%
63.1%
8.8 9.5 9.9 27.3 28.2 27.0 100 0%
100 0%
100 0%
Other Items Tnx Matters The Internal Reveriuc Service has confirmed the Company's entitlement to the Shoreham abandonment loss deduction which the Company claimed on its 1989 federal income tax return. Principally, as a result of this deduction, the Com-pany, at December 31, 1991, had a net operating loss (NOL) carryforward of approximately $2.2 billion. Accordingly, for 1991, the Company's payments for federal income taxes were minimal. The Company estimates that the balance ofthe NOL carryforward willbc fully utilized to reduce federal income tax payments within the 15-year statutory carryforward period.
Electric Competition, Conservation nnd Supply The Company is presently experiencing competition from cogeneration and small independent power production projects. These projects supply electric energy to existing or new industrial and commercial custoiners and excess
electricity is sold to the Company pursuant to the purchase
~ requirements of the Public UtilityRegulatory Policy Act of 1978 (PURPA). The Company is unable to predict whether the volume of electric customers gaining access to non-Company sources will be signifrcant in the future.
During
- 1991, the Company sponsored various PSC approved energy eAicient and peak load reduction programs.
The Company estimates these programs reduced annual electric usage by approximately 309,000 megawatt hours and reduced peak electricity demand by approximately 210 megawatts in 1991. Due to the success of these programs, the Company collected, through
- rates, approximately 85 million of revenue incentives during 1991.
The Company's current electric load forecasts indicate that, with continued implementation ofits aggressive conservation and load management programs and with electricity provided by independent power producers anticipated to come on line, thc Company's existing generating facilities and contracts for purchased power arc adequate to meet the energy demands on Long Island to the end of the century.
Gas Colnpetition In 1987, the Federal Energy Regulatory Commission (I'ERC) issued an order allowing gas pipeline companies and producers access to certain of the Company's customers for the purpose of supplying competing gas service.
As of December 31, 1991, approximately 100 of the Company's former large gas customers were purchasing gas directly from gas pipeline companies and producers and arranging for its transportation through the Company's gas mains.
The Company receives a fee for this transportation service
'hich accounted for approximately 3% oftotal gas revenues for 1991.
Clean Air Act In late 1990, significant amendments to the federal Clean AirAct werc adopted. A number ofelectric utilities anticipate substantial increases in operating costs and capital expenditures as a result of the amendments.
The Company does not expect to incur any costs to satisfy these recent amendments with respect to the reduction of sulfur dioxide emissions, since the Company already uses fuel with acceptable lcvcls of sulfur. However, the Company expects that it will incur costs for additional continuous emission monitoring (CEM) requirements and for future nitrogen oxide reduction requirements that may be imposed under federal or state regulations. The Company estimates that the cost of installing CEM and nitrogen oxide control equipment, which thc Company will seek to recover through rates, will be approximately $15 million and 8100 million, respectively.
811siness Units In 1992, the Company willcontinue to enhance its organi-zational structure through a corporate reorganization dcsigrred
~to consolidate activities into three separate and distinct business units Electric Operations, Gas Operations and Conservation Services.
Results of Operations Eal'nlngs For 1991, earnings for common stock were approximately
$239 million, or $2.15 pcr common share.
Earnings for common stock for 1990 were approximately 3251 million, or 82.26 per common share, excluding the effect in 1990 ofthc accounting change for unbilled gas revenues discussed below. The decrease of approximately
$ 12 million, or 11 cents per share, compared with 1990 was primarily attributable to increases in non-fuel operation and maintenance
- expenses, operating taxes and depreciation
- expense, partially offset by higher electric revenues.
Earnings for common stock rellected the positive effects of thc 1989 Settlement for the entire year. Earnings for common stock in 1990 also reflected a change in the Company's method of recognizing gas revenues.
Effective January 1, 1990, the Company's revenues include estimated consumption of gas delivered to customers, but not yet billed at month-end, resulting in thc fullaccrual ofall unbilled gas revenues.
The cumulative effect of this accounting change increased 1990 earnings by nearly $ 12 million, nct of tax effects, or 10 cents per common share. Excluding this item, earnings for common stock in 1990 would have been approximately 8251 million, or $2.26 per common share.
This would have been an increase of34 cents pcr share over 1989, excluding the 1989 non-cash charges to net income attributable to the 1989 Settlement, the Class Settlement and the Nine Mile Point Nuclear Power Station, Unit 2 (NMP2) disallowance.
In 1989, the Company incurred a loss for common stock ofapproximately 8175 million, or 81.57 per common share that resulted from recording non-cash charges to net income attributable to the 1989 Settlement and thc Class Settlement.
Under the 1989 Settlement, the Company recorded on its books the establishment of the FRA and the write-offof its investment in Shoreham (and other related assets). The net loss resulting from thc write-offand the reduction ofnet income resulting from the cessation ofthe allowance for funds used during construction (AFC) accruing on Shorcham, which mitigated such write-oA; totaled approximately 8269 million, nct of tax effects, or 82.41 per common share.
Upon the effectiveness of the Class Settlement, the Company recorded a charge to income of approximately 8113 million, net of tax effects, or $1.02 per common sharc, which represented the present value at June 30, 1989 of the total amount of the Class Settlement.
Also, the Company, thc other cotcnants ofNMP2, the PSC and other interested parties reached an agreement in January 1990 with respect to the construction of NMP2 and its operation through January 19, 1990. Under the terms of the agreement, the Company's share of disallowed costs aggregated approximately $7 million, net of tax eA'ects, or 6 cents per common share, and was charged to income in 1989 in accordance with the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 90, Regulated Enterprises Accounting for Abandonments and Disallowances of Plant Costs.
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Excluding these three items, earnings foi common stock in 1989 would have been approximately 8213 million, or 81.92 per common share.
Earnings (loss) per common sharc for 1991, 1990 and 1989 are shown below. The presentation reQects per share data on the basis of excluding and including the items described above.
1991 1990 1989 Earnings, excluding the following items
~ Unbillcd Gas Revenues
~ 1989 Scttlemeni
~ Class Sculcrncnt
~ NMP2 Disallowance 8 2.15 2.26
.10 1.92 (2.41)
(1.02)
.06 Earnings (Loss) Per Common Sharc 82.15 8
2.36 I)
(1.57)
Revenues Total revenues in 1991, including revenues from recovery offuel costs, were 82.5 billion, which represents an increase of$102 million, or 4.2%, over 1990 revenues. Total revenues for the Company's electric and gas operations for 1991, 1990 and 1989 are shown below:
The average number ofelectric custoiners served in 1991 was approximately 1,005,000, up about 4,000, or 0.4%,
over 1990. The increase in 1990, compared to 1989, was about 6,000, or 0.6%.
Revenues from fuel cost adjustments were higher in 1991 primarily due to increased recoverics of conservation expenses.
Revenues from fuel cost adjustments were higher in 1990 than in 1989 primarily due to increased oil prices.
The average cost of oil burned in the Company's steam generating plants in 1991 was $17.38 per barrel, compared with $20.49 per barrel in 1990. The average cost of oil burned in 1989 was $17.83 per barrel.
On December 1, 1991, the Company was granted an elec-tric rate increase of4.15% and had been granted increases of5.0% on December 1, 1990, 5.0% on December 1, 1989 and 5.4% on K"ebruary 18, 1989. These rate increases provided incremental revenues of $81 million in 1991 and 883 million in 1990.
Gas Revenues: In 1991, gas revenues decreased by 810 million, or 2.8%, compared to 1990. Revenues in 1990 had decreased 83 million, or 0.8%, compared to 1989. The decreases in gas revenues resulted primarily from several factors, in thc amounts shown in the following table:
Revenues Electric Gas 8 2,198 8 2,086 1,983 351 361 365 In millions o dollaa 1991 1990 1989 In millions o dollaa Customer Consumption Customer Additions Fuel Cost Adjustmcnts Rate Increases 91/90 90/89 (2) 8 (9) 5 4
(15)
(2) 2 4
Total Revenues 82,549 8 2,447 8 2,348 Total S
(10 8
(3)
Electri Revenues: In 1991, electric revenues increased $112 million,or 5.4%, over 1990. Revenues in 1990 had increased 8102 million, or 5.2%, over 1989. The increase in electric revenues resulted primarily from several factors in the amounts shown in the following table:
In millions o dollaa Customer Consumption Customer Additions Fuel Cost Adjustmcnts Rate Increases Total 91/90 90/89 13 8
(70) 8 12 10 77 81 83 8
112 8
102 Average customer consumption decreased by 38 kilowatt-hours (kWh), or approximately 0.2%, in 1991, primarily as thc result of the expansion of the Company's aggressive conservation programs, and the continued sluggishness of the region's economy. However, despite the slight decline in average overall consumption, changes in the customer mix resulted in higher revenues.
Weather was not a significant factor in 1991. In 1990, average consumption decreased com-pared to 1989 for many of thc same reasons plus a decline in sales to other utilities and the loss ofpotential sales resulting from independent power producers and cogeneration ventures, most notably the Grumman Cogeneration project.
The decrease in average customer consumption in 1991 was 6 dekatherms (dth), or 4.9%, and was largely attributable to wanner winter weather. Also, many of the Company's large interruptible custoiners are now purchasing much of their gas from other suppliers. While this results in lower sales and revenues, there is no effect on net income since profits from interruptible sales are passed back to lirm customers through fuel cost adjustment credits and are not retained by the Company.
On average, the total nmnber ofgas space heating custorneis served in 1991 was up about 10,500, or 4.4%, over 1990, including about 4,000 existing customers who converted their heating systems to gas during the year.
Revenues from I'uel cost adjustments were lower in 1991 primarily due to lower sales. The average cost of gas sold in 1991 was $3.29 per dth, compared with $3.19 per dth in 1990. The increase in average gas prices in 1991 was more than olfset by the decrease in sales volume. The average cost of gas sold in 1989 was $3.31 per dth.
Effective December 1, 1991, the Company was granted a gas rate increase of4.1%, which provided additional revernies of $0.5 million in 1991.
In January 1990, the Company was granted a gas rate increase ofapproximately 1.3%. This rate increase provided the Company with incrcincntal revenues of $4 millionin 1990 and another 81.3 million in 1991. The Company did not, receive any gas rate increases in 1989.
~ Operating and Maintenance Expenses Operating and maintenance (0&M) expenses, excluding fuels and purchased power, werc 8523 million in 1991, an increase of 847 million, or 9.9%, over 1990. In 1990, these 0&Mexpenses increased 849 million, or 11.4%, over 1989.
The increase in 1991 was primarily attributable to higher expenses for employee wages and benefits, electric produc-tion, gas distribution and higher provisions for doubtful accounts reflecting the continuing weakness in the region's economy.
Thc Company continues to pursue aggressive collection practices and has further enhanced its procedures that were implemented in 1990.
The increase in 1990 was principally due to higher research and development expenditures, thc implementation and expansion of aggressive energy conservation programs and the costs of maintaining electric production plant, reflectin the Company's commitment to enhanced customer service and service reliability. Higher costs for ernployce wages, health insurance and higher provisions for doubtful accounts also contributed to the increase.
Other Items For a discussion of the accounting treatment of the 1989 Settlement and the Class Settlement, see Notes 2, 3 and 4 of Notes to Financial Statements.
In 1991, federal income taxes were approximately $182 million. In 1990, federal income taxes were $183 million, excluding the tax effect of thc accounting change for unbilled gas revenues.
In 1989, the Company recorded a federal income tax benefit of81.0 billion, principally resulting from the Shoreham abandonment loss deduction.
Operating taxes, predominantly property taxes, were 8388 millionin 1991, compared to $370 millionin 1990 and 3364 million in 1989.
Depreciation expense increased by $12 million in 1991 and by $9 millionin 1990 primarily attributable to additional plant in service. Interest expense increased by 816 million in 1991 and by $24 million in 1990 principally due to increased debt
- levels, partially offset by reductions in interest rates.
In 1991, the Company recorded non-cash charges to in-come of approximately $25 million, or $17 million, nct of tax effects, for the ongoing carrying costs of its obligation under the Class Settlement. In 1990, these ongoing charges amounted to approximately 823 million, or 815 million, net of tax effects.
The Company ceased accruing AFC on its investment in Shoreham, effective January 1, 1989. AFC has not been a significant component of the Company's earnings since then. However, other non-cash income has been substan-tial, generated principally by thc accretion of the RMC of the FRA. In 1991, the accretion of the RMC amounted to approximately $229 million, or $ 151 million, net of tax effects. In 1990 and 1989, these amounts were 8297 million, or $196 million, net oftax effects, and $ 131 million, or $87 million, net oftax effects, rcspcctively. RMC carrying charges of 840 million, 816 million and Pl million for the years ended December 31, 1991, 1990 and 1989, respectively, are included in other income on thc Statement of Income.
For a further discussion of the FRA, see Notes 1 and 2 of Notes to Financial Statements.
The Company was required to reduce the RMC for earnings in excess of thc sum of the 70 basis point incentive cap and the allowed electric rate of return of 12.77% for the rate year ended November 30, 1991.
Accordingly, the Company reduced thc RMC by approxi-mately $15.3 million.
The Company is required to adopt SFAS No. 96, Accoun-ting for Income Taxes, no later than January 1, 1993. The impact of SFAS No. 96 on the Statement of Income is not expected to be material. However, the Company estimates that had it adopted SFAS No. 96 at December 31, 1991, the Company would have recorded an accumulated deferred tax liabilityand an offsetting regulatory asset ofapproximately
$ 1.5 billion. See Note 1 ofNotes to Financial Statements.
In December 1990, the FASH issued SFAS No. 106, Employers'ccounting for Postretircment Benefits Other Than Pensions.
Sl'AS No. 106 will require the Company to change its method of accounting for such benefits from a pay-as-you-go basis to an accrual basis by requiring the accrual of the expected cost of providing postretirement bcnelits over the period employee service is rendered. The Company believes that it will bc permitted to record a
regulatory asset resulting from the adoption ofthis statement.
This regulatory asset would bc recovcrcd through rates at the time these expenses are funded. This accounting treat-ment is subject to thc approval of the PSC. The Company must adopt SFAS No. 106 by January 1, 1993, and does not expect to do so prior to that date. The Company estimates that had it adopted SFAS No. 106 at December 31, 1991, it would have recorded an accumulated postrctirement benefit obligation and a regulatory asset of approximately $350 million. See Note 8 of Notes to Financial Statements.
Selected Financial Data Additional information respecting
- revenues, expenses, electric and gas operating incoinc and operations data, capital expenditures and balance sheet information for the last five years is provided in Tables 1 through 11 ofSelected Financial Data. Information with regard to thc Company's business segments for the last three years is provided in Note ll of Notes to Financial Statements.
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Report of Ernst fk Young Independent Auditors a"
-T To the Shareowners and Board of Directors of Long Island Lighting Company We have audited the accompanying balance sheet ofLong Island Lighting Company as of December 31, 1991 and 1990 and the related statements of income, shareowners'quity and cash flows for each ofthc three years in the period ended December 31, 1991. These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material
- respects, the financial position of Long Island Lighting Company at December 31, 1991 and
- 1990, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1991 in conformity with generally accepted accounting principles.
~ ~
, I Melville, New York February 6, 1992
-1
- f Y
. Financial Statements
. Statement of Income I'or year ended December 31 (ln thousands ofdollars except per share amounts)
Revenues Electric Gas Total Revenues Expenses Operations fuel and purchased power Operations other Maintenance Depreciation, depletion and amortization Base financial component amortization Regulatory liabilitycomponent amortization Rate moderation component Regulatory liabilitycomponent Jamesport amortization Operating taxes Federal income tax current Federal income tax (credit) deferred and other Total Expenses Operating Income Other Income and (Deductions)
Allowance for other funds used during construction, net offinancial stability adjustment revenues Rate moderation component carrying charges Other income and deductions, net 1989 Settlement Class Settlement Federal income tax credit (charge) deferred and other Total Other Incoine and (Deductions)
Income Before Interest Charges and Cumulative Effect ofAccounting Change Interest Clmrges mul (Credits)
Interest on long-term debt Other interest Allowance for borrowed funds used during construction, net offinancial stability adjustment revenues Total Interest Charges and (Credits)
Income (Loss) Before Cumulative Effect ofAccounting Change Cumulative Effect ofAccounting Change for Unbilled Gas Revenues (net ofapplicable taxes of$6,017)
Net Income (Loss)
Preferred stock dividend requirements 1991
$ 2,197,689 351,161 2,548,850 768,702 375,267 147,492 124,820 100,971 (86,360)
(228,572) 388,380 515 168,937 1,760,152 788,698 2,202 40,456 32,074 (25,467)
(12,201) 37,064 825,762 472,974 50,842 (3,592) 520%224 305,538 305,538 66,394 1990
$ 2,085,605 361,242 2,446,847 786,999 340,518 135,291 112,784 100,971 (86,101)
(297,214) 370,317 3,638 177,014 1,644,217 802,630 2,940 15,683 27,218 (22,574)
(2,629) 20,638 823,268 467,700 40,559 (4,628) 503,631 319,637 11,680 331,317 68,161 1989
$ 1,983,288 364,326 2,347,614 772,452 297,518 129,788 103,430 50,485 (43,038)
(131,167) 793,592 104,160 364)391 14,612 (729,032) 1,727,191 620,423 (54,918) 682 32,948 (303,947)
(186,000) 322,991 (188,244) 432,179 453,267 31,366 43,349 527,982 (95,803)
(95,803) 79,232 Earnings (Loss) for Common Stock Average Common Shares Outstanding (000) 111,348 111,290 111,215 239,144 263,156 (175,035)
Earnings (Loss) per Coinmon Share Before cumulative effect ofaccounting change Cumulative effect ofaccounting change 2.15 2.26
.10 (1.57)
Eariiings (Loss) per Common Share Dividends Declared per Common S)iare 2.15 2.36 (1.57) 1.60 1 25
.50
.Pro Forma Earnings withAccoiniting Change Applied Retroactively Earnings (loss) for common stock Earnings (loss) per coinmon share Sec Aotcs to Financial Statetnents.
251,476 2.26 (173,251)
(1.56)
L Balance Sheet Assets At December 31 (In tltousands ofdollars)
UtilityPlant Electric Gas Coinmon Construction work in progress Nuclear fuel in rocess and in reactor 1991 Q 3,323,008 666,904 157,495 157,511 29,818 1990 3 3,213,032 565,272 141,700 183,337 47,481 4(
I 1
Less Accumulated depreciation, de letion and amortization Total Net Utilit Plant Regulatory Asset Base financial component (less accumulated ainortization of8252,427 and $ 151,456)
Nonutilit Pro ert and Other Investments Current Assets Cash and cash equivalents Special deposits Customer accounts receivable (less allowance for doubtful accounts of$26,935 and 318,684)
Other accounts receivable Accrued revenue iVlaterials and supplies at average cost Fuel oil at average Lost"""
Gas in storage at average cost Pre a ments and other current assets Total Current Assets Deferred Charges Rate moderation component Shoreham post settlement costs Shoreham nuclear fuel Unamortized storm damage costs Unainortized cost ofissuing securities Accumulated deferred income taxes Other Total Deferred Char es Total Assets See Itlotes to Financial Statements.
4,384,736 1,332,003 8,002,738 3,786,403 9,788 298,098 23,207 210,525 6,515 136,565 86,868 44,002 43,888 34,854 884,017 602,053 8'78,386
'79,760 28,435 227,713 439,285 104,778 1,860,360 Q 9,543,301 4 150 822 1,262,743 2,888,079 3,887,373 6,381 102,936 21,492 216,732 9,694 138,917 92,138 68,866 41,466 33,819 726,060 411,443 225,818 92,069 34,754 132,875 359,768 78,064 1,334,791 3 8,842,684
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Ca italization and Liabilities At December 31 (In thousands ofdollaa)
Capitalization Long-term debt Unamortized remium and (discount) on debt Preferred stock redemption required Preferred stock no redem tion re uired Total Preferred Stock Common stock Premium on capital stock Capital stock expense Retained earnin s
Total Common Shareowncrs' uit Total Ca italization Current Liabilities Current maturities oflong-term debt Current redemption requirements ofpreferred stock Accounts payable and accrued expenses Accrued taxes (including federal income taxes of$27,693 and 828,453)
Accrued interest Dividends payable Class Settlement Customer de osits Total Current Liabilities Dcferre<1 Credits 1989 Settlement credits Class Settlement Accumulated deferred income taxes Other Total Deferred Credits Reserves for Claims, Damages, Pclrsrorls arid Bencfrts Commitmcnts and Contin cncics Total Capitalization and Liabilities See t'Votes to Financial Statements.
1991 8 5,001,016 (14,850) 4,986,166 524,912 154,371 679,283 556,825 993,509 (40,216) 620,373 2,130,491 7,795,940 10,000 10,616 223,589 60,174 85,565 60,287 20,000 22,664 492,895 173,507 173,564 816,053 84,035 1,247,159 7,307
$ 9,543,301 1990 8 4,556,016 (23,125) 4,532,891 527,550 154,674 682,224 556,620 992,885 (42,676) 560,405 2,067,234 7,282,349 29,000 13,616 189,029 56,248
( 69,175 53,279 20,000 19,483 449,830 182,720 167,569 634,704 117,172 1,102,165 8,340 8 8,842,684
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Shnreowners'quity Statexncnt ofRetained Earttittgs (In thousands ofdollaa)
Balance at January 1
Restricted for preferred stock dividend rcquircments at beginning ofyear Net income (loss) for the ear Deductions Cash dividends declared on preferred stock Cash dividends declared on common stock Capital stock expense Balance at December 31 1991 560,405 308,838 865,943 67,261 178,169 140 620,373 1990 436,690 331,317 768,007 68,218 139,128 256 560,405 1989 679,579 341,008 (95,803) 924,784 429,749 55,618 2 727 436,690 Preferred Stock At December 31 (In titousands ofdollars)
Call Price Per Share December 31 1991 Final Par Value 8100 pcr Share, Cumulative Shares authorized Shares issued and outstandin 1991
'7,000,000 2,438,993 1990 7,000,000 2,528,400 1989 7,000,000 2,624,172 5.00% Series B 4.25% Series D 4.35% Series E 4.35% Series F 5 1/8%Series H 5 3/4%Series I Convertible 8.12% Series J 8.30% Series K 7.40% Series L" 8.40% Series M*
8.50% Series R*
9.80% Series S*
Total Par Value $ 100 Par Value 828 per Share, Cumulative Shares authorized Shares issued and outstandin 82.47 Series 0*
$2.43 Series P
$3.31 Series T"
$2.65 Series Y" 82.35 Series Z*
8101.00 102.00 102.00 102.00 102.00 100.00 101.00 103.29 103.44 103.64 101.50 103.00 8 25.25 27.75 27.65 27.35
$ 101.00 8
102.00 102.00 102.00 102.00 100.00 101.00 103.29 100.00 100.00 100.00 100.00 S 25.25 8
27.75 25.00 25.00 10,000 7,000 20,000 5,000 20,000 2,371 25,000 30,000 21,350 25,200 22,500 55,478 243,899 30,000,000 17,840,000 26,000 35,000 320,000 65,000 10,000 7,000 20,000 5,000 20,000 2,674 25,000 30,000 22,400 26,600 26,250 57,916 252,840 30,000,000 17,720,000 28,000 35,000 60,000 320,000 10,000 7,000 20,000 5,000 20,000 3,592 25,000 30,000 23,450 28,000 30,000 60,375 262,417 30,000,000 17,920,000 30,000 35,000 63,000 320,000 Total Par Value 825 Less Sinkin fund re uirements Total Preferred Stock 8
446,000 8
10,616 679,283 443,000 13,616 682,224 448,000 13,638 696,779 Con11noI1 Stock At December 31 (In thousands ofdollars)
Par Value Q5 per Sharc Shares authorized Shares issued and outstanding Increase in shares outstandin Increase in 85 par value Increase in premium on capital stock Decrease in capital stock expense
- Iledcmption required, sec Note 6.
See Notes to Financial Statements.
1991 150%000,000 111,368,056 40,975 205 614 2,460 1990 150,000,000 111,324,081 74,613 373 924 240 1989 150,000,000 111,249,468 56,460 28'2 608 13,235
. Statement ofCash Flows For ear ended December 31 (In thousands o dollars)
Operating Activities Net Income (Loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities Cumulative effect ofaccounting change for unbilled gas revenues Depreciation, depletion and amortization Fuel moderation component Provision for doubtful accounts Base financial component amortization Regulatory liabilitycomponent amortization.
Rate moderation component Rate moderation component carrying charges Regulatory liabilitycomponent Jamesport amortization 1989 Settlement Class Settlement Federal income taxes (credit) def'erred and other Allowance for other funds used during construction Other Changes in operating assets and liabilities Accounts receivable Accrued revenue Materials and supplies, fuel oil and gas in storage Prepayments and other current assets Accounts payable and accrued expenses Class Settlement Accrued taxes Other Nct Cash Provided b 0 eratin Activities Investing Activities Construction and nuclear fuel expenditures
. Financial stability adjustment revenues Construction and nuclear fuel expenditures, net offinancial stability adjustment revenues Shorcham post settlement costs Other Net Cash Used in Investin Activities Financing Activities Proceeds from issuance oflong-tertn debt Proceeds from issuance ofshort-term debt Redemption oflong-term debt Redemption ofshort-term debt Proceeds f'rom sale ofpreferred stock Redemption ofpreferred stock Preferred stock dividends paid Common stock dividends paid Cost ofissuing long-tenn debt and preferred stock Other Net Cash Provided b (Used in) Financin Activities Net Increase (Decrease) in Cash and Cash Equivalents Cash and cash equivalents at beginning ofyear Net increase (decrease) in cash and cash e uivalents Cash and Cash Equivalents at End ofYear Interest Paid, bel'orc reduction f'r the allowance for borrowed funds used during construction Federal Income Taxes Paid Federal Income Taxes Refunded Scc Notes to Financial Statements.
1991 305,588 124,820 34,025 35,481 100,971 (86,360)
(228%572)
(40,456) 25,467 181,138 (2,202) 46,640 (26,045) 2,352 28,217 (1,035) 34,560 3,926 (17,98 520,428 (235,349)
(285,849)
(158,432)
(8,928)
(397,704) 1,582,247 (1,129,000) 63,130 (70s 688)
(65,888)
(172,584)
(88,586) 3,707 72,488 195,162 102,936 195,162 298,098 477,240 1,650 642 S
8 1990 331,317 (11,680) 112,784 3,804 30,097 100,971 (86,101)
(297,214)
(15,683) 22,574 179,643 (2,940) 29,919 (22,463) 30,748 (48,040) 23,752 2,345 (20,129)
(42,187)
(459) 321,058 (229,525)
(229,525)
(152,675) 81 (382,119) 112,319 (82,000)
(13,659)
(68,046)
(125,192)
(1,327) 1,59$
(176,307)
(237,368) 340,304 (237,368) 102,936 479,278 900 23,588 1989 (95,803) 103,430 16,971 12,347 50,485 (43,038)
(131,167)
(682) 793,592 104,160 303,947 186,000 (1,052,023) 1,166 23,189 (53,324)
(97,983)
(6,681) 23,890 42,818 66,750 (7,456) 240,588 (297,396) 96,180 (201,216)
(75,'044)
(393)
(276,653) 1,541,350 111,585 (732,585)
(111,585) 309,120 (307,73&)
(418,387)
(27,807)
(77,983)
(2,150) 283,820 247,755 92,549 247,755 340,304 475,672 2,660 r* ~$ 1
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Notes to Financial Statements Note 1. Summary ofSignificant Accounting Policies Thc Coinpany's accounting policics conform to generally accepted accounting principles (GAAP) as they apply to a rcgulatcd enterprise. Its accounting records are maintained in accordance with the Uniform Systeins of Accounts prescribed by the Public Service Commission of the State of New York (PSC) and the Federal Energy Regulatory Com-mission (FERC).
Financial Rcsourcc Asset GAAP authorizes recognition of the existence of a regulatory asset when it is probable that a regulator willpermit full recovery of a previously incurred cost. Pursuant to the 1989 Settlement, thc Company recorded a regulatory asset known as the Financial Resource Asset (FRA). Thc FRA has two components, the Base Financial Component (BFC) and the Rate Moderation Component (RMC). The Rate iVIoderation Agreement (RMA), one of the constituent documents of the 1989 Settlemcnt, provides for thc full recovery of the FRA. For a further discussion of the 1989 Settlement and thc FRA, scc Note 2.
UtilityPlant Additions to and replacements ofutilityplant are capitalized at original cost, which includes material, labor, overhead arid an allowance for the cost of funds used during construction.
The cost of renewals and betterments relating to units of property is added to utility plant. The cost of property replaced, retired or otherwise disposed of is deducted from utilityplant and, generally, together with dismantling costs less any salvage, is charged to accumulated depreciation.
Thc cost of repairs and minor renewals is charged to maintenance expense.
Mass properties (such as poles, wire and meters) are accounted for on an average unit cost basis by year of installation.
Allowance for Funds Used During Construction Thc Uniform Systems of Accounts defines the allowance for funds used during construction (AFC) as thc net cost of borrowed funds for construction purposes and a reasonable rate of return upon the utility's equity when so irscd. AFC is not an item of current cash incoinc. AFC is computed monthly using a rate permitted by FERC on that portion of construction work in progress which is not included in the Company's rate base. The average annual AFC rate, without giving effect to compounding, was 10.74/0, 11.03/0 and 12.20/0 for thc years 1991, 1990 and 1989, respectively.
From 1984 up to the effectiveness of the 1989 Settleinent, the Company was provided with additional revenues through the operation of the financial stability adjustment (FSA) authorized by the PSC. FSA revenues were in excess of thc amounts to which thc Company was entitled under conven-tional ratemaking and resulted in an offset to AFC. Because thc Company, effective January 1, 1989, ceased the accrual ofAFC on thc Shorcham Nuclear Power Station (Shorcham) in its GAAP basis financial statements, FSA revenues, net.
of tax effects, amounting to $96 million, exceeded AFC during the year ended Deceinber 31, 1989.
Depreciation The provisions for depreciation result from the applica-tion of straight-line rates to the original cost, by groups, of depreciable properties in service. The rates arc determined by age-life studies pcrformcd annually on depreciable properties.
Depreciation for electric was equivalent to approximately 3.3/0, 3.2/0 and 3.2/0 of respective average depreciable plant costs for the years 1991, 1990 and 1989.
Depreciation for gas was equivalent to approximately 2.9/0, 2.8/0 and 2.9/0 of respective average depreciable plant costs for the years 1991, 1990 and 1989.
Cash Equivalents Cash equivalents are highly liquid investments with maturities of three months or less when purchased.
Unbilled Revenues Thc Company accrues electric revenues for services rendered to customers but not billed at month-end.
Effective January 1, 1990, the Company adopted the full accrual method for unbiHed gas revenues.
Previously, unbillcd gas revenues were recognized only for customers biHed on a bi-monthly cyclo basis for the month in which they were normally not billed. This change better matches revenues and expenses and provides consistency with the Company's revenue recognition method for electric revenuea The cumulative effect of this change at January 1, 1990 was
$11.7 million, net of tax effects, or $.10 per share and had been included in net income for thc year ended Decembet 31, 1990. The effect of this change on income before the cumulative effect ofaccounting change and on earnings for common stock for the year ended December 31, 1990 was not material.
Fuel Cost Adjustments The Company's electric and gas tariffs include fuel cost adjustment (FCA) clauses which provide for the dil'fercnce between actual fuel costs and thc fuel costs allowed in the Company's base tarilfrates (base fuel costs). Thc Company, to achieve a proper matching of costs and revenues, defers these adjustinents, net oftax eAccts, to future periods in which they will be billed or credited to customers.
Prior to the effectiveness of the electric rate order discussed in Note 3, base fuel costs collected from ratepayers in excess ofactual electric fuel costs were recorded as a liabilitysubject to final disposition by thc PSC. Thc Company willcontinue to collect thc higher ol'actual electric fuel costs or the base fuel costs, pursuant to the RMA. Effective December 1, 1991, base fuel costs in excess ofactual electric fuel costs willbe credited to thc RMC as incurred.
The electric rate order issued by the PSC in November 1991 authorized the adoption of a partial pass-through fuel cost incentive, effective December 1, 1991. The partial pass-through fuel cost incentive includes a mechanism that compares the Company's actual cost to produce electric energy against a targeted fuel value. The incentive measures the Company's ability to purchase fuel at the lowest possible cost, to purchase energy economically from other power sup-pliers and to operate its generating plants at optimum eAi-ciency. The shareowners are allocated 40/0 of the impact between actual fuel costs and targeted fuel values up to a maximum benefit or penalty of20 basis points ofreturn on common equity. The shareowners'ortion of these impacts willbe deferred and passed through the FCA in the follow-ing rate year.
Gas Take or Pay Costs FERC has ruled that, subject to its regulations, interstate gas pipeline companies may pass on to their customers certain costs which resulted when demand for natural gas from interstate gas pipeline companies declined due to changing market conditions. In 1989, thc PSC determined that 87.5 /0 ofthese costs, known as take-or-pay (TOP) costs, will be recovered from ratepayers.
Thc Company wrote offin 1989 approximately $3.1 million, net of tax effects, which represents the estimated non-recoverable portion of TOP costs.
Capitalization-Premiums, Discounts and Expenses Premiums or discounts and expenses related to the issuance oflong-term debt are amortized over the life ofeach issue. Unamortized premiums or discounts and expenses related to issues of long-term debt that are refinanced are amortized and recovered through rates over the shorter life ofthe redeemed or new issues. Capital stock expense related to that portion of preferred stock that is required to be redeemed is written-offas an adjustment to retained earnings upon redemption unless the preferred stock is redeemed below par value. In that case, any resulting gain, net of the related capital stock expense, is recorded as additional premium on capital stock. The capital stock expense and redemption costs associated with redeeming Preferred Stock Series T, U, V, W and X and the cost ofissuance ofPreferred Stock Series Y and Z are recorded as deferred charges and are being amortized and recovered through rates over the ten-year lives of Series Y and Z.
Federal Income Taxes The Company provides deferred federal income taxes with rcspcct to certain differences between net income before income taxes and taxable income in certain instances when approved by the PSC, as disclosed in Note 10. The Company defers the benefit of 60/0 of pre-1982 gas and prc-1983 electric and 100/0 of all other investrncnt tax credits, with respect to regulated properties, when realized on its tax returns.
For ratemaking purposes, certain accumulated deferred federal income taxes are deducted from rate base and amor-tized or otherwise applied as a reduction (increase) in federal income tax expense in future years. Accumulated deferred investment tax credits are amortized ratably over the lives of the related properties.
The tax effects of other differences between income for financial statement purposes and for federal income tax purposes are accounted for as current adjustments in federal income tax provisions. The Financial Accounting Standards Board (FASB) Statement ofFinancial Accounting Standards (SFAS) No. 96, Accounting for Income Taxes, is effective for fiscal years beginning after December 15, 1992. SFAS No. 96 willrequire, among other matters, recognition of the amount ofcurrent and deferred taxes payable or refundable at the date ofthe financial statements as a result ofall events that have been recognized in the financial statements and adjustment ofdeferred income taxes for an enacted change in tax laws. For regulated enterprises, SFAS No. 96 will prohibit nct of tax accounting and reporting and require recognition ofa deferred tax liabilityfor the tax benefits which are flowed through to its customers and the equity component of AFC. A regulatory asset or liability will be recognized relating to such items ifit is probable that the future increase or decrease in taxes payable thereon shall be recovered from or returned to customers through future rates. The Company does not expect to adopt SFAS No. 96 prior to January 1, 1993, which willprovide additional time for thc Company to complete its evaluation and analysis ofSFAS No. 96. The impact of SFAS No. 96 on the Statement of Income is not expected to be material. However, thc Company estimates that had it adopted SFAS No. 96 at December 31, 1991, the Company would have recorded an accumulated deferred tax liabilityand an offsetting regulatory asset ofapproximately
$ 1.5 billion.
In June 1991, the FASB issued an exposure draft (ED) of a proposed SFAS which, if adopted, would replace SFAS No. 96 and be effective for fiscal years beginning after December 15, 1992. While the ED, as currently proposed, contains certain provisions that differ from SFAS No. 96, the Company estimates that the impact of adopting the ED would not significantly differ from that of adopting SFAS No. 96.
Reserves for Claims, Damages, Pensions and Benefits Losses arising from claims against the Company and extraordinary storm losses are partially self-insured.
Amounts provided are credited to the reserves based upon experience, risk of loss, actuarial estiinates and/or specific orders of the PSC.
Note 2. The 1989 Settlement On February 28, 1989, the Company and the State of New York (by its Governor) entered into the 1989 Settle-ment resolving certain issues relating to the Company and providing, among other matters, for the transfer ofShoreham and its subsequent decommissioning. The 1989 Settlement recites the intention of thc parties that the Company shall be returned to investment grade financial condition and that the Company and thc State of New York anticipate that the PSC shall ensure that the future impacts on rates are to bc minimized to the maximum extent practicable. It is the Company's position that these objectives can bc achieved, in part, through the continued receipt ofadequate and timely rate relief.
Upon the effectiveness of the 1989 Settlement, the Company simultaneously recorded on its Balance Sheet the retirement of its investment of approximately 84.2 billion in Shoreham and Bokum Resources Corporation (Bokum) and the establishment of'he FRA.
The BFC, a component of the FRA, as initiallyestablish-ed, represents the present value of the future net-after-tax cash llows which thc RMA provided thc Company for its financial recovery. AtJune 30, 1989, the BFC was approxi-mately 84.0 billion. The BFC, which is granted rate base treatment under the terms of thc RMA, is included in the Company's revenue requirements through an amortization included in rates over forty years on a straight-line basis beginning July 1, 1989. As of December 31, 1991 and 1990, the unamortized balance. ofthe BFC was approximately 83.8 billion and $3.9 billion, respectively.
The RiVIC, a component of thc FRA, which willprovide the Company with a
substantial amount of non-cash earnings over the next several years, reflects the difference between the Company's revenue requirements under conventional ratemaking and the revenues resulting from the implementation of the rate moderation plan provided for in thc RiMA. This rate moderation plan is designed to hold electric rate increases to thc levels provided for in the RMA, subject to the adjustments provided for therein. The RMC is based on forecast data filed in connection with the RMA.
As a result of thc electric rate order, discussed in Note 3, effective December 1, 1991, thc RMC is adjusted for certain Nine Mile Point Nuclear Power Station, Unit 2 (NMP2) operations and maintenance expenses and fuel credits resulting from the Company's electric fuel adjustment clause discussed in Note 1. Prior to December 1, 1991, the RMC was adjusted to reflect actual property taxes, cost of asbestos removal, interest expense, energy conservation and load management program costs, costs to provide added elec-tric system reliability and inflation. The RMC initially increases as the difference between revenues resulting from the implementation ofthe rate moderation plan provided for in the RMA and revenue requirements under conventional ratemaking, together with a carrying charge based on the allowed rate of return on rate base, are deferred and will subsequently decrease and is expected to bc fullyamortized by the year 2000 as these deferred revenue requirements are recovered.
The Company recognized a
loss in June
- 1989, of approximately $62 million, net oftax effects, which primarily reflected the difference between the recorded costs of the Company's investment in Shoreham and Bokum and the BFC.
Under the 1989 Settlement, certain tax benefits attributable to the Shoreham abandonmcnt are to be shared between ratepayers and shareowners. A regulatory liabilityofapproxi-mately $794 million was recorded in June 1989 to preserve an amount equivalent to the ratepayer tax benefits attributablc to the Shoreham abandonment.
This amount is being amortized over a ten-year period on a straight-line basis from the effective date of the 1989 Settlement. The tax benefit arising from the abandonment loss deduction has been offset against the corresponding regulatory liability in the Company's Balance Sheet as it could not have been fully recognized under GAAP werc it not for the fact that its recovery is assured under the 1989 Settlement through the regulatory liability offset.
The 1989 Settlement amount on the Statement of Income ofapproximately 8304 millionfor thc year ended December 31, 1989, principally rellects the net difference between the write-offofShoreham and Bokum, the establishment of the BFC and an adjustment required to correspond with the negotiated settlemcnt amount.
The Statement of Income reflects an amortization of the Company's investment in a proposed generating station in Jamesport of approximately 8104 millionfor the year ended December 31, 1989, which was offset by deferred federal income tax credits of an equivalent amount.
Shoreham post settlement costs (decommissioning, payments in lieu ofproperty taxes and other costs as incurred) are being capitalized and amortized and recovered through rates over a forty-year period on a straight-line remaining life basis.
Upon the effectiveness ofthc 1989 Settlement, Shoreham nuclear fuel was reclassified to deferred charges and is being amortized and recovered through rates over a forty-year period on a straight-linc remaining life basis.
The 1989 Settlement credits on the Balance Sheet of approximately
$ 174
- million, net of amortization, reflect an adjustment of the book write-offto the negotiated 1989 Settlement amount and are being amortized over a tcn-year period.
)
The Company believes that the accounting treatment afforded the FRA under the 1989 Settlement conforms to GAAP. For purposes of administering its Uniform Systems of Accounts, FERC has adopted the provisions of SFAS No. 90, Regulated Enterprises Accounting for Abandonments and Disallowances of Plant Costs, which sets forth the criteria for recognition ofregulatory created assets resulting from abandonrnents.
Accordingly, the Company believes that the accounting treatment afl'orded the FRA con-forms to FERC's standards for accounting and asset recogni-tion of regulatory created assets.
The Company has settled certain disputes with a contrac-tor in connection with the construction of Shoreham.
For a discussion of the pending transfer of Shoreham, see iVotc 9.
Note 3. Rate Matters Electric Pursuant to the 1989 Settlement, discussed in Note 2, the Company received electric rate increases contemplated by the RMAfor each of the three rate years ended November 30, 1991. The RMA contemplates that the Company will apply to the PSC for targeted annual rate increases of4.5%
to 5.0% in each year for an eight-year period beginning December 1, 1991. In response to the Company's rate filing in December 1990, the PSC approved thc Long Island Lighting Company Ratemaking and Perfonnance Plan (LRPP) in November 1991, which provides for annual electric rate increases, before giving effect to the rate reductions rcquircd by the Class Settlement discussed in Note 4, of4.15%, 4.1% and 4.0%, effective December 1, 1991,
.1992 and 1993, respectively. The LRPP is designed to be consistent with the RMA's long-term goals including: (a) the recovery of the BFC; (b) the recovery of the RMC in approximately ten years; (c) the Company's return to invest-rnent grade linancial condition; and (d) the Company's receipt of adequate and timely rate relief. One principal objective of the LRPP is to reassign risk so that the Company assumes thc responsibility for risks within the control of management, whereas risks largely beyond the control of management would be assumed by the ratepayers.
The LRPP reflects an update of the long-range forecast of thc Company's revenue requirements, which was the basis of the RMA's initial three rate increases. Thc LRPP contains three major components-revenue reconciliation, expense attrition and reconciliation, and performance incentives.
Revenue reconciliation is provided through a mechanism that reduces the impact of experiencing electric sales that are significantly above or below the LRPP forecast by providing a fixed annual net margin level (defined as sales
- revenues, net of fuel and gross receipts taxes),
that the Company will receive over the three rate years under the LRPP. The differences between the actual electric net revenues and the annual net margin level willbe deferred on a monthly basis during thc rate year. The deferred balances resulting from thc net margin, customer service performance plan, time-of-usc incentive program, property taxes, interest expense and wage rates willbc netted at the end ofeach rate year. The LRPP established a band whereby the first $ 15 million of the total net defcrrals will be used to increase or decrease the RMC balance. The total net defer-rals in excess of815 millionwillbe refunded to or recovered from the ratepayers in the following twelve-month period beginning in April, through the FCA.
The expense attrition component permits the Company to make adjustments for expenses including certain operation and maintenance
- expenses, property taxes and interest charges.
These adjustments recognize that certain cost increases are unavoidable due to inflation and changes in the business. The LRPP includes the annual reconciliation of certain expenses for wage rates, property taxes, interest charges and demand side management (DSM) costs, the deferral and amortization of certain costs for enhanced reliability and operating and maintenance, and the applica-tion ofan inflation index to other expenses for the rate years effective December 1, 1992 and 1993.
The LRPP provides for an 11.6% return on common equity for electric operations for the three years commenc-ing Dcccmber 1, 1991. Under the LRPP, the Company is allowed to earn up to 60 additional basis points, or forfeit up to 38 basis points, of the return on common equity as a result of its performance within certain incentive and/or penalty programs. These programs consist of a customer service performance plan, a DSM program, a time-of-usc incentive program and a partial pass-through fuel cost incentive plan, discussed in Note 1. The LRPP contains a mechanism whereby earnings in excess of the allowed rate of return on common equity, excluding the impacts of the various incentive/penalty programs, willbe shared equally between ratepayers and sharcowners.
Prior to December 1, 1991, the RMAprovided that earned returns on common equity in excess oftargeted allowed rates ofreturn, as adjusted, werc to bc applied to reduce the RMC or mitigate rates, as determined by the PSC, at thc end of each rate year. The Company earned $15.3 millionin excess ofits targeted allowed rate ofreturn for the rate year ended November 30, 1991 but did not earn in excess ofits allowed rate ofreturn for the rate years ended November 30, 1990 and 1989.
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To assist in recovering the RMC within a ten-year period under the rates provided by the LRPP, the Company, in accordance with tkie LRPP, willcredit the RMC with several deferred ratepayer benefits including any amounts collected in excess of actual fuel costs.
In December 1991, the Company applied $57.6 mfllionol'previously defcrrcd credits and related carrying charges for amounts collected in excess of actual fuel costs as a reduction to the RMC. Other miscellaneous deferred credits were also applied as a
reduction to the RMC in December 1991.
Gas In November 1991, the PSC issued a rate order granting a gas rate increase of 4.1/0 which became effective on December 1, 1991. The gas rate increase reflects costs related to expected levels of capital expenditures, operations and maintenance expenses and the Company's gas expansion program. The gas rate order contains a weather norrnaliza-tion clause which moderates thc impact of variations in temperature on gas revenues.
On December 31, 1991, the Company filed a request with the PSC to increase its gas rates effective December 1, 1992 by 5.80/o or 830 million in additional revenues.
Although the Company calculated that an increase of 9.8/0 or 851 million is warranted, the Company proposes to collect only 5.8/0 in the rate year and defer the balance of the request for recovery in later years, together with a return thereon.
". This filingreflects the Company's latest projections ofcapital expenditures, operations and maintenance expenses and the continued expansion of its gas business.
Note 4. The Class Settlement In February 1989, the Company and certain ofits foriner officers entered into an agrcemcnt (Class Settlcmcnt) that resolved a civillawsuit against thc Company brought under the federal Racketeer Influenced and Corrupt Organizations Act (RICO Act). The lawsuit which the Class Settlement resolved had alleged that the Company made inadequate disclosures before thc PSC concerning the construction and completion of nuclear generating facilities.
The Class Settlement provides for rate reductions aggregating 8390 million to bc made to thc ratepaycrs'onthly electric bills over a ten-year period, as well as approxiinately 810 million for attorneys'ees and expenses and certain other costs associated with the Class Settlement which were paid in 1990.
As a result of the Class Scttlcment, the Company's electric rate increases after December 1990 on average will be approximately.2/0 to.3/o pcr year lower than they would othcrwisc have been during the balance of the Class Settle-ment period which ends in the year 2000. Thc amounts recorded on the Statement of lncoine for 1991 and 1990 of approximately $25 million and $23 million, respec-.
tively, represent the increase in present value of the Class Settlement liability.The amount recorded on the Statement of Income for 1989 of 8186 million represents the present value of the Class Settlement at June 30, 1989 plus the increase in present value of the Class Settlement liabilityfor the remainder of 1989.
Note 5. Nine Mile Point Nuclear Power Station, Unit 2
. Thc Company has an 18/0 undivided interest in NMP2 which is operated by Niagara Mohawk Power Corporation (NMPC) near Oswego, Ncw York. Ownership of NMP2 is shared by five cotenants: the Coinpany (18/0), NMPC (41 /0),
New YorkState Electric R Gas Corporation (180/0), Rochester Gas and Electric Corporation (14/o) and Central Hudson Gas 4'lectric'Corporation (9/0). At December 31, 1991, the Company's iiet utilityplant investment in NMP2 was $796 million, net of accumulated depreciation of 880 million, which is included in the Company's rate base. Output of NMP2, which has a design capability of 1,084 megawatts, is shared in the same proportions as the cotenants'espec-tive ownership" interests. The operating expenses of NMP2 are also allocated to the cotenants in thc same proportions as their respective ownership interests. The Company's share of these expenses is included in the appropriate operating expenses on the Statement of Income. The Company is required to provide its respective share of financing for any capital additions to NMP2. Nuclear fuel costs associated with NMP2 are being amortized on the basis of the quantity of heat produced for thc generation of electricity.
A settlctnent agrecmcnt reached in 1989 (NMP2.
Settlement) among the cotenants ofNMP2 and other parties and subsequently approved by thc PSC, resolved certain ratemaking issues regarding the construction of NMP2 and its operation through January 19, 1990.
In December 1989, the Company recorded $7.3 million, net oftax effects, as a charge to earnings, which represents the effect of the NMP2 Settlement. Under the terms ofthc Nil'IP2 Settlement, the Company is limited to recovering $716 millionoforiginal plant costs from its ratepayers, net of tax effects.
NMPC has contracted with the United States Department of Energy for the disposal of nuclear fuel. In 1991, the Company reimbursed NMPC for its 18/o share of the cost under the contract at a rate of $1.00 per megawatt hour of nct generation.
Based upon a study performed by NMPC, the Company's share of the decommissioning costs for NMP2 is estimated to be $37 million (in 1989 dollars) assuming that decom-missioning willcommence in 2027 or $237 million (in 2027 dollars). The Company's share ofestimated decommission-ing costs are being provided for in electric rates and are being charged to operations as depreciation expense. Thc amount of accumulated decommissioning costs collected from the Company's ratepayers through December 31, 1991 was $3.7 million. Amounts collected by the Company for the decommissioning of the contaminated portion of thc NMP2 plant, which approximate 84% of total decommissioning costs, are held in an independent decommissioning trust fund.
This fund complies with regulations issued by the Nuclear Regulatory Commission (NRC) governing the funding of nuclear plant decommissioning costs. The Company's funding plan for its share of decommissioning costs will provide reasonable assurance that, at the time oftermination ofopera-
- tion, adequate funds for the decommissioning of the Company's share ofthe contaminated portion ofNMP2 plant will be availablc. The Internal Revenue Service (IRS) has ruled that the Company's decommissioning trust meets the requirements ofa qualified fund under applicable provisions of the federal income tax law. This IRS ruling allows the Company's contributions to the decommissioning trust to be deductible for income tax purposes for the tax year in which they are made.
Note 6. Capital Stock I
Preferred Stock Preferred stock dividends are cumulative. At December
.31, 1991, 1990 and 1989 there were no preferred stock dividends in arrears. On September 1, 1989, the Company resumed regular dividend payments on its preferred stock by paying all dividends, then in arrears, amounting to approximately $390 million.
Redemption ofvarious series of preferred stock is effected through the operation ofvarious sinking fund provisions. On July 25, 1989, simultaneous with the declaration ofall pre-ferred stock dividends then in arrears, the Company satisfied sinking fund requirements totaling approximately $56 million then in arrears on all series of preferred stock by crediting previously acquired shares of preferred stock held in the Company's treasury. The aggregate par value of preferred stock required to be redeemed in each of the years 1992 through 1996 is gll million.
In May 1991, the Company sold 2,600,000 shares of Preferred Stock, $2.35, Series Z, cumulative, par value $25 per share. The Company used the proceeds from the issuance of the Scrics Z Prefcrrcd Stock to call, at its applicable redemption price, Preferred Stock, $3.31, Series T.
Preference Stock None of the authorized 7,500,000 shares of non-participating preference stock, par value gl per share, which ranks junior to thc preferred stock, are outstanding.
Common Stock Of thc 150,000,000 shares of authorized common stock at December 31, 1991, 1,882,586 shares werc reserved for sale through the Company's Employee Stock Purchase Plan to employees with at least one year of service and 138,268 shares were reserved for conversion of the Series I Convertible Preferred Stock at a rate of317.15 per share. In addition, the Company has reserved 6,802,247 shares for the Automatic Dividend Reinvestment Plan which has been suspended since February 1984. Common and preferred stock dividend limitations in the mortgage securing the Company's First Mortgage Bonds are not material. There are no dividend limitations contained in thc Company's other debt instruments.
Note 7. Long-Term Debt Each of the Company's four mortgagcs is a lien on sub-stantially all of the Company's properties.
First Mortgage Allofthe bonds issued under the First Mortgage, including those issued after June 1, 1975 and pledged with the Trustee of the GAR Mortgage (GM Trustee) as additional security for General and Refunding Bonds (GM Bonds), are secured by the lien of the First Mortgage. First Mortgage Bonds pledged with the G&R Trustee do not represent out-standing indebtedness of the Company. Amounts of such pledged bonds outstanding were $957 million and $449 million at December 31, 1991 and 1990, respectively. Thc annual First Mortgage depreciation fund and sinking fund requirerncnts for 1991, due not later than June 30, 1992, are estimated at $179 millionand $ 18 million, respectively.
The Company expects to meet these requirements with property additions and retired First Mortgage Bonds.
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)I GRR Mortgage The lien of the G&R Mortgage is subordinate to the lien of the First Mortgage. The annual G&R Mortgage sinking fund requirement for 1991, due not later than June 30, 1992, is estimated at $27 million. Thc Company expects to satisfy this requirement with retired G&R Bonds.
Third Mortgage/1989 Term Loan Agreement The Third r'rlortgage is subordinate to the liens ol'the First Mortgage and the G&R Mortgage. The bank debt secured by the Third iMortgage was restructured on June 30, 1989, at which time, the Company entered into the 1989 Arncnd-ed and'Restated Restructuring Credit Agreement (1989 Tenn Loan Agreement) pursuant to which the Company is to pay to its lending banks approximately $446 million in sixteen substantially equal consecutive quarterly installments commencing on January 1, 1993 and ending on October 1, 1996. Pursuant to the 1989 Term Loan Agreerncnt, the Company has the option to commit to one of three interest rates including: (a) the Adjusted Certificate of Deposit Rate (CD Rate) which is a rate based on the certificate of deposit rates ofcertain ofthe lending banks, (b) thc Base Rate which is generally a rate based on Citibank, N.A.'s prime rate and (c) the Eurodollar Rate which is a rate based on the London Interbank Offering Rate (LIBOR).
Fourth Mortgage Thc Fourth Mortgage secures $85 millionofthe Company's obligations under the letter of credit dcscribcd below under the heading Authority Financing Notes. Through an Intcr-crcditor Agreement, the letter of credit bank secured by the Fourth Mortgage holds a lien on Company property that is equal in rank to the lien held by the banks secured by the Third Mortgage.
1989 Revolving Credit Agreement On June 30, 1989, thc Company and certain ofits lending banks entered into the 1989 Revolving Credit Agreement (1989 RCA). The Company has an cstimatcd $114 million available under this $300 million revolving line of credit through October 1, 1992. Allor part ofthc remaining $186 million has been dedicated for the purposes described below.
This line of credit is secured by a first lien upon the Company's accounts receivable and fuel oil inventories. Thc Company has the option to cornrnit to onc of three interest rates including: (a) the CD Rate, (b) the Base Rate and (c) the Eurodollar Rate. The Company has agreed to pay a fce of one quarter of onc percent per annum on thc unused portion. At December 31, 1991, no amounts were outstanding under the 1989 RCA. The termination date of the 1989 RCA may be extended for onc-year periods upon the acceptance by the lending banks of the Company's request delivered to the lending banks prior to April 1 in each year beginning in 1992.
The amount ofcredit available under the 1989 RCA al'tcr-Octobcr 1, 1992 will be $264 million through October 1, 1993. The Company has, with the approval of the NRC, dedicated an amount of the 1989 RCA sul'ficient to cover estimated, not yet incurred, costs attributable to thc decommissioning of Shoreharn. At December 31, 1991, the Company estimates that $ 186 million would represent the amount of estimated, not yet incurred, decommission-ing costs. After October 1, 1992, the amount available under the 1989 RCA, not required for the decommissioning of Shoreham, will be reduced from 8114 million to approximately $78 million. However, the amount available under the 1989 RCA will increase as decommissioning costs are paid by the Company through means other than the 1989 RCA.
Authority Financing Notes Authority Financing Notes are issued by the Company to thc Ncw York State Energy Rcscarch and Development Authority (NYSERDA) to secure certain tax-exempt Pollu-tion Control Revenue Bonds (PCRBs), Electric Facilities Revenue Bonds (EFRBs) and Industrial Development Revenue Bonds issued by NYSERDA. Certain ol'these bonds are supported by letters ofcredit and are subject to periodic tender at which time their interest rates are subject to re-dctennination.
When such letters of credit expire, the Company is required to obtain either an extension of the letter of credit or substitute credit backup. Ifneither can be obtained, thc bonds must be redeerncd unless the Company purchases the bonds in lieu of redemption and subsequently rcmarkcts them.
Allof the outstanding EFRBs are supported by letters ol'redit pursuant to which the letter ofcredit banks have agreed to pay the principal, interest and premium on any tendered EFRBs, in the aggregate, up to approximately $ 109 million for each issue in thc event of default. The obligation of the Company to reimburse the letter ofcredit banks is unsecured.
These letters ol'credit expire on January 24, 1994, Junc 3, 1993 and October 31, 1994 for the 1991 EFRBs, 1990 El'RBs and 1989 EFRBs, respectively.
The 1985 PCRBs are supported by a letter of credit, pursuant to which the letter ofcredit bank, partially secured by the Fourth iMortgage in thc amount of 885 million, has agreed, in the event of default to pay the principal, interest and premium on the tendered PCRBs, in the aggregate, up to approximately $ 165 million. This letter of credit expires on r'r'larch 31, 1993.
Lon -Term Debt at December 31 In thousalrdso dollars Maturity Interest Rate Series 1991 1990 I','>> '
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Cz First Mortgage Bonds (excludes Pledged Bonds)
August 1, 1991 April1, 1993 June 1, 1994 June 1, 1995 March 1, 1996 April1, 1997 September 1, 1999 September 1, 2000 April 1, 2001 December 1, 2001 September 1, 2002 Deccrnber 1, 2003 Total First Mort a e Bonds General and Refunding Bonds June 1, 1995 April15, 1996 May 1, 1996 February 15, 1997 March 1, 1999 June 1, 2006 December 1, 2006 May 1, 2007 April1, 2008 April 15, 2015 iMay 1, 2021 Jul 1,2024 Total General and Refundin Bonds Third Mortgage 1989 Tenn Loan A reement (LIBOII)
Debentures 5%
4.40%
4 5/8%
4.55%
5 1/4%
5 1/2%
8.20%
9 1/8%
7 1/4%
7 1/2%
7 5/8%
8 1/8%
13 1/4%
11 1/4%
8 3/4%
8 3/4%
9.75%
9 5/8%
8 5/8%
8 5/8%
9.20%
ll 7/8%
9 3/4%
9 5/8%
5.3%
L M
N 0
P Q
R S
U V
EV X
40,000 25,000 259000 40,000 35,000 35,000 25,000 40,000 50,000 50,000 60,000 425,000 415,000 250,000 63,000 70,000 50,000 85,000 75,000 415,000 375,000 1,798,000 446,341 25,000 40,000 25,000 25,000 40,000 35,000 35,000 25,000 40,000 50,000 50,000 60,000 450,000 225,000 250,000 67,000 70,000 50,000 85,000 75,000 275,000 1,097,000 446,341 I
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"'e April 1, 1993 November 15, 1993 Junc 15, 1994 November 15, 1994 June 15, 1999 November 15, 2014 June 15, 2019 Total Debentures Authority Financing Notes Pollution Control Revenue Bonds December 1, 2006 December 1, 2009 October 1, 2012 i%larch 1, 2016 Electric Facilities Revenue Bonds September 1, 2019 June 1, 2020 December 1, 2020 Industrial Development Revenue Bonds December 1, 2006 Total Authorit Financin Notes Total Long-Tenn Debt Less Current maturities Total Long-Term Debt Less Current Maturities ll 3/8%
11.70%
10.25%
11.75%
10.875%
11.50%
11.375%
7.5%
7.8%
8 1/4%*
5.375%**
5 35%<<r'r'Ir:
5.4%***
7.5%
1976A 1979B 1982 1985 A,B 1989A,B 1990A 1991 A 1976 A,B 375,000 175,000 400,000 175,000 350,000 350,000 1,825,000 28,375 19,100 17,200
, 150,000 100,000 100,000 100,000 2,000 516,675 5,011,016 10,000 85,001,016 375,000 175,000 400,000 175,000.
350,000 350,000 350,000 2,175,000 28,375 19,100 17,200 150,000 100,000 100,000 2,000 416,675 4,585,016 29,000 84,556,016 "Tcndcred cvcry three years, next tender Octoller 1994
- Tendered annually on r1farch 1
- Tendered weekly
'Long tenn debt due in thc nextfiveyears is 810 000 (1992), 8705 585 (1993), 8715 585 (1994), 8140 585 (1995) and 8570585 (1996).
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I Note 8. Retirement Benefit Plans Thc Company maintains a primary defined benefit pension plan (Primary Plan) which covers substantially all employees, a supplemental plan (Supplemental Plan) which covers key executives and a retircinent plan which covers the Board of Directors (Directors'lan). All pension costs are borne by the Company.
The Company's funding policy is to contribute annually to the Primary Plan a minimum amount consistent with the requirements of the Employee Retirement Income Security Act of 1974 (ERISA) plus such additional amounts, il'ny, as the Company may determine to be appropriate from time to time. Pension benefits are established by crediting the employee with an amount deter-mined using the base salary for each year the employee is a participant in thc plan, plus an additional amount credited for each year the employee remains a participant beyond the age of 50. Employees are vested in thc pension plan after five years of service with the Company.
Primary Plan The Primary Plan's funded status and amounts recognized in the Balance Sheet at December 31, 1991 and 1990 werc as follows:
Assumptions used in accounting for the Primary Plan were:
Discount rate Rate ol'uture compensation increases Long-term rate of return on assets 1991 1990 1989 7.75%
7.25%
7.5%
5.5%
6.0%
6.0%
7.0%
7.0%
7.0%
The Primary Plan assets at fair value primarily include cash, cash equivalents, group annuities, bonds and listed equity securities.
Pursuant to an order issued by the PSC in 1987, the Company had deferred approximately $7.3 million which was the excess of pension expense collected from its ratepayers through 1989 over that determined under SFAS No. 87, Employers'ccounting for Pensions. Subsequently, the Company's rates. were based on pension expense deter-mined under SFAS No. 87. The portion attributable to elec-tric operations of approximately $4.6 million, was credited to the RMC on December 1, 1991 in accordance with the LRPP, discussed in Note 3. The portion that is attributable to gas operations of approximately 82.7 million, will be amortized to income over a three-year period beginning December 1, 1991, in accordance with the gas rate order.
(lrs thousands ofdollars) 1991 1990 y
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'.r Actuarial present value ol'cnelit obligation Vested bcncfits Nonvcstcd benefits g 375,326 383,805 5 315 6,459 Plan assets at fair value Actuarial prcscnt value of ro'ected benefit obli ation Projcctcd bcncfit obligation less than plan assets Unrecognized January 1, nct obligations Unrcco nizcd net ain 8 519,816 468,050 446 718 464.797 73,098 3,253 33,113 114 389 25,922 30.741 Nct accrued pension cost (8,178) 3 (1,566)
Periodic pension cost for 1991, 1990 and 1989 for the Primary Plan included the following components:
(Iu thousands ofdollaa) 1991 1990 1989 Service costbenefits carncd during thc period 8 14,323 12,720 3
10,797 Intcrcst cost on projected benefit obligation and service cost Actual return on plan assets Nct ainoriizaiion and dcfcrral 33,698 32,264 31,458 (63,875)
(23,121)
(49,316) 33 569 5,449 22,955 Nct criodic cnsion cost 8 17,715 3
16.414 3
15,894 Accumulated benefit obligation
$ 380,641 3
390,264 Supplemental Plan The Supplemental Plan provides supplemental death and retirement benefits for officers and other key executives without contribution lrom such employees. The Supplemental Plan is a non-qualified plan under the Internal Revenue Code.
Death benefits are currently provided by insurance.
The provision for retirement benefits, which is unfunded, totaled approximately 8675,000,
$561,000 and 8546,000 and were recognized as an expense in 1991, 1990 and 1989, respectively. The cost of this plan is borne by the Company's shareowners.
Directors'lan The Directors'lan, adopted in February 1990, provides benefits to directors who are not oAicers of the Company.
Directors who have served in that capacity for more than five years qualify as participants under the plan. The Directors'lan is a nonqualified plan under thc Internal Revenue Code. The provision for retirement benefits, which is unfunded, totaled approximately $ 101,000 and 899,000 and were recognized as expense in 1991 and
- 1990, respectively.
Postretirement Benefits Other Than Pensions In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees.
Substantially all of the Company's employees may become eligible for these benefits if they reach retirement age while working for the Company. These and similar benefits for active employees are provided through insurance companies whose premiums are based on the benefits paid during the year. The cost of providing these benefits on a pay-as-you-go method was 837,312,000,
$29,410,000 and $27,155,000 for 1991, 1990 and 1989, respectively, and were recognized as an expense as premiums were paid.
Thc cost of providing these benefits for approximately 2,100 retirces, is not separable from the cost of providing benefits for approximately 6,000 active employees for the years 1989 through 1991.
In December 1990, the FASH issued SFAS No. 106, Employers'ccounting for Postretirement Benefits Other Than Pensions.
SFAS No.
106 establishes accounting standards for employers'ccounting for such benefits. SFAS No. 106 willrequire the Company to change its method of accounting for such benefits from a pay-as-you-go basis to an accrual basis by requiring the accrual of the expected cost ofproviding postretirement benefits over the period the employee service is rendered.
The Company believes it willbe permitted to record a regulatory asset resulting from the adoption of this statement. The regulatory asset would be recovered through rates at the time these expenses are funded. This accounting treatment is subject to PSC approval.
-The Company must adopt SFAS No. 106 by January 1, 1993 and does not expect to do so prior to that date. The Com-pany estimates that had it adopted SFAS No. 106 at December 31, 1991, it would have recorded an accumulated postretirement benefit obligation and a regulatory asset of approximately $350 million.
Note 9. Commitments rind Contingencies Litigation Asbestos: The Company is one of several co-defendants in a number of consolidated asbestos actions pending in both New York State Supreme Court and the federal district courts for the Southern and Eastern Districts of New York (In Re Nerrr York Asbestos Litigation). The damages which have been demanded in each of these actions range up to $55 million, including punitive damages, against all defendants.
In the State court, the Company is a party in some of the consolidated cases which proceeded to trial in 1992. In addition, on the federal level, trial to determine medical causation and the amount of plaintiffs'amages has been completed in 47 consolidated cases in which thc Company and several other parties had been impleaded by an asbestos manufacturer. Thc Company is one ofnumerous defendants who may be found liable for a share of $38 million in damages awarded to 24 of these 47 plaintiffs. A second trial to determine the allocation ofthis liabilitybegan in late 1991.
Pursuant to court-ordered negotiations, the Company has been involved in settlement negotiations to resolve these State and federal claims. In addition, the Company has com-menced fourth-party actions against certain of its insurcrs seeking indemnification for liabilityand defense costs in these cases and is also involved in court-ordered settlement discus-sions in these matters.
Based upon the progress of these negotiations and other factors, the Company believes that the resolution of these cases willnot materially impact the financial condition of the Company.
Contract Suit: The Company is also involved in litigation against Suffolk County in which both parties are seeking damages for the other's alleged breach ofcontract concern-ing thc preparation of an offsite emergency response plan for Shoreharn which, pursuant to the 1989 Settlement, the Company agreed to never operate.
In its proposed counterclaims, Suffolk County seeks significant damages for alleged fraud in the inducement, brcach of contract by the Company, tortious conduct and fraudulently procured utility rates, as well as $700 million in alleged punitive damages.
The Company has moved the court to impose sanctions on Suffolk County relating to these claims on the basis that thc allegations are frivolous and ignore significant precedent r
including the NRC s approval of the Company's evacuation plan for Shoreharn and various Second Circuit Court of Appeal's decisions in related litigation between the parties.
In addition, the Company has argued that there is no basis for punitive damages in this case. Thc Company intends to vigorously prosecute its claims against Suffolk County and to defend against Suffolk County's counterclaims.
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Transfer of Shorelram The 1989 Settlement provides for the transfer ofShoreharn to thc Long Island Power Authority (LIPA)and for its decom-missioning. The Company and LIPA have filed an applica-tion with the NRC, which is pending, to transfer Shoreham's possession-only license to LIPA. LIPA has also filed a decom-missioning plan for Shoreham with the NRC.
Colllmitrncllts The Company has entered into substantial cornmitmcnts for fossil fuel, gas supply, purchased power and transmission facilities. Thc costs associated with these commitments arc normally recovered from ratcpayers through provisions in the Company's rate schedules.
Nuclear Plant Insurance Thc Company has property damage insurance and third-party bodily injury and property liability insurance for its 18% share in NMP2 and for Shoreham. The premiums for this coverage are not material. Thc policies for this coverage provide for retroactive premium assessments under certain circumstances.
Maximum retroactive premium assessments could be as much as approximately
$4.7 million. For property damage at each nuclear generating site, the NRC requires a minimum of81.06 billion<ofcoverage. The NRC has given the Company a partial exemption from these requirements for Shoreham.
Under certain circumstances, thc Company may bc assessed additional amounts in the event of a nuclear incident. Under agreements established pursuant to the Price Anderson Act, the Company could be assessed up to approximately $74 million per nuclear incident in any one year at any nuclear unit, but not in excess of approximately
$ 12 millionin payments pcr year for each incident. The Price Anderson Act also limits liabilityfor third-party bodily injury and third-party property damage arising out of a nuclear occurrence at each unit to 87.4 billion.
Note lo. Federal Income Taxes On April17, 1989, the Company received a private letter ruling from the IRS which stated that thc Company would bc entitled, for federal income tax purposes, to an abandon-ment loss deduction in connection with Shoreham, upon effectiveness of the 1989 Settlement. The Company claimed an abandonment loss deduction on its 1989 federal income tax return ofapproximately $ 1.8 billion. The Company's net operating loss carryforward is estimated to be approxi-mately $2.2 billion at December 31, 1991.
On January 8, 1990, the Company received a Revenue Agent's Report disallowing certain deductions claimed by the Company on its tax returns for thc years under audit.
The Revenue Agent's Report reflects proposed adjustments to the Company's federal income tax returns for 1984 through 1987 which, if sustained, would give risc to tax deficiencies totaling approximately 887 million. Thc Company is protesting some of the adjustments and seeks an administrative and, ifnecessary, a judicial review of thc conclusions reached in the Revenue Agent's Report. Thc Company cannot.predict either the timing or the manner in which this matter willbe resolved. If, however, the ultimate disposition ofany or all matters raised in the Revenue Agent's Report is adverse to the Company, the Company expects that any deficiencies that may arise will be substantially offset by the net operating loss carrybacks associated with the Shoreharn abandonment loss deduction and thus any impact would not have a material effect on the Company's financial condition or cash flows.
The amount of investment tax credit (ITC) carryforward for financial statement purposes after 1991 is approximately
$206 million. These credits expire by the year 2002. In.
accordance with the Tax Reform Act of 1986 (TRA 86),
ITC allowable as credits to tax returns for years al'ter 1987 must be reduced by 35%. Thc amount of the reduction will not be allowed as a credit for any other taxable year.
The Company has not provided deferred taxes on approxi-mately
$500 million of various other deductions and depreciation method differences for property placed in service prior to 1981 which, in conformity with the rate-rnaking practices of thc PSC, have been llowed through.
These various other flow-through tax deductions, which are deductible currently for tax purposes but capitalized for accounting and ratemaking purposes, include certain taxes, a portion of AFC, pensions and certain other employee benefits. See Note 1 with respect to a change in the method of accounting for incornc taxes which the Company must adopt by no later than 1993.
The federal income tax amounts included in the Statement ofIncome differ from the amounts which result from applying the statutory federal income tax rate to nct income (loss) before income taxes. The table below sets forth the reasons for such differences. The 1989 difference results principally because thc tax basis attributable to Shoreham was less than its recorded basis for financial statement purposes and the FRA and certain other 1989 Scttlerncnt items recorded by the Company pursuant to the 1989 Settlement have no tax basis.
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(In thousands ofdollaa) 1991 1990 1989 h
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e Federal income tax, per Statement of Income current Deferred and other (see Note 1) 1989 Settlement Shoreham abandonment Jamesport recovery Hokum Resources Corporation Rate moderation component Other 1989 Settlement items Shoreham post settlement costs Contractor litigation settlement Class Settlement Interest capitalized Accrued utilityrevenues Mortgage recording tax Accelerated tax depreciation Call premiums Fuel cost adjustments Nine Mile Point 2 deferred revenues Capitalized overheads Retired debt costs Other items, net Total Deferred Total federal income tax expense (credit)
Income (loss) before cumulative effect ofaccounting change Income (Loss) Before Cumulative El'feet of Accounting Change and Income Taxes Statutory federal income tax (credit)
Additions (reductions) in federal income tax resulting from:
1989 Settlement Shorcham abandonment Jamesport recovery Hokum Resources Corporation Rate moderation componerrt Other 1989 Scttlernent items Allowance for funds used during construction Lien date property taxes Tax credits Excess of book depreciation over tax depreciation Interest capitalized Other items, net Total Federal Income Tax Expense (Credit)
%of Pl'C lilx Amount Income Amount 515 3,638 14,612 10,G77 20,400 77,715 (13,638) 50,375 (18,758)
(2,038)
(2,5G2) 4,653 30,447 18,496 (3,289) 180 9,185 (705) 181,138 181,653 305,538 8 487,191 3,239 101,053 (13,577) 61,475 (534)
(3,220) 727 (589) 33,342 (3,111) 4,879 2,287 (6,328) 179,643 183,281 319,637 8 502,918 (907,467)
(104,160)
(35,977) 44,597 (37,500) 6,656 (63,240)
(3,752)
(2,803)
(687) 3G,242 12,452 4,451 4,151 1,272 (6,258)
(1,052,023)
(1,037,411)
(95,803) 8 (1,133,214) 4,003 (1,310) 277 (2,980) 13,108 4,232 (1,322) 0.8 (0.3) 0.1 (0.6) 2.7 0.9 (0.3) 4,035 (2,573)
(8,757) 1,537 11,987 6,031 29 0.8 (0.5)
(1.8) 0.3 2.4 1.2 0.0 (691,242) 20,101 (34,015)
(7,360)
(19,821) 31,527 20,034 13,534 10,842 3,251 1,031 8 181,653 37.3%
3 183,281 36.4%
3 (1,037,411) 8 1G5,645 34.0%
8 170,992 34.0%
8 (385,293)
%of Prc-tax Income 34.0%
61.0 (1.8) 3.0 0.7 1.8 (2.8)
(1.8)
(1.2)
(1.0)
(0.3)
(0.1) 91.5%
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Operating revenues Electric Gas 1991 8 2,197,689 351,161 1990 5 2,085,605 361,242 1989 8 1,983,288 364,326 Note ll. Segments of Business The Company is a
public utility operating company engaged in the generation, distribution and sale of electric energy and the purchase, distribution and sale of natural gas to residential and commercial customers in Nassau and Suffolk Countics and the Rockaway Peninsula in Queens County, all on Long Island, New York. Identifiable assets by segment include net utilityplant, financial resource asset, materials and supplies (excluding common), accrued revenues, gas in storage, fuel and deferred charges (excluding common). Assets utilized for overall Company operations consist of other property and investments, cash, temporary cash investments, special deposits, accounts receivable, prepayments and other current assets, unamortized debt expense and other deferred charges.
Total Operating expenses (excludingincome taxes)
Electric Gas Total Operating income (loss) (beforeinconie taxes)
Electric Gas 8 2,548,850
$ 1,252,405 338;295 8 1,590,700 945,284 12,866
$ 2,446,847
$ 1,141,050 322,515 5 1,463,565 944,555 38,727 8 2,347,614 8 2,115,994 325,617
$ 2,441,611 (132,706) 38,709
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Depreciation, depletion and amortization Electric Gas Total Construction and nuclear fuel expenditures+
Electric Gas Total 958,150 (5,794)
(47,068) 523,816 169,452 12,201 305,538 305,538 8
110,087 14,783 8
124,820 144,356 93,195 237,551 983,282 (7,568)
(20,327) 508,259 180,652 2,629 319,637 11,680 331,317 99,922 12,862 112,784 151,425 81,040 232,465 At December 31 (In tlrousandsof dollars)
Identifiable assets Electric Gas Total Assets utilized for overall Com an o erations 1991 8 7,986,887 621,570 8,608,457 934,844 1990
$ 7,643,963 540,355 8,184,318 658,366 Total Assets 8 9,548,301
$ 8,842,684
- Includes non-casli allowance forotherfunds used during constniction and excludes Slroreliam post seitlemens costs.
(93,997) 98,267 456,317 484,633 (714,420)
(322;991)
(95,803)
(95,803)
S 91,759 11,671 103,430 148,388 51,662 8
200,050 1989 5 7,133,161 451,447 7,584,608 935,430
$ 8,520,03/
. Note 12. Quarterly Financial Information (Unaudited)
E*Y g I',z (ln tliousands of dollars except eaniings pcr cominon share)
Operating revenues For the quarter ended iMarch 31 June 30 September 30 December 31 Operathig hicome For the quarter ended il'larch 31 June 30 September 30 December 31 Net iiicolne For the quarter ended March 31 June 30 September 30 December 31 Earnings for conunon stock For the quarter ended March 31 June 30 September 30 December 31 1991
$ 667,294 541,356 738,592 601,608 8 207,830 166,830 268,041 145,997 86,404 50,089 144,449 24,596 69,567 33,013 128,175 8,389 1990 8 665,531 510,788 707,820 562,708 8 202,899 167,410 282,104 150,217 90,356(a) 47,780 156,848 36,333 73,205 (a) 30,681 139,845 19,425
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The cumulatiie effect ofthis change increased nct income by approximately 811.7 million, net of tax effects, or 8.11 per conunon share, for thefirst quarter.
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Summary of0 )erations (Sec Itrores ro Financial Statements)
Table 1 Total revenues (000)
Total operating income (loss) (000)
Before federal income taxes After federal income taxes Income (loss) before cumulative effect ofaccounting changes (000)
Cumulative effect of accounting change for unbilled gas revenues (net of taxes) (000)
Cumulative effect of accounting change for disallowed costs (nct of taxes) (000)
Earnings (loss) for cornrnon stock (000)
Average common shares outstanding (000)
Earnings (loss) per common share Before cumulative effect of accounting changes Cumulative effect ofaccountin chan es Earnings (loss) per common sharc Pro forma earnings with accounting changes for unbilled gas revenues and disallowed project costs applied retroactively Earnings (loss) for common stock (000)
Earnings (loss) pcr common share Common stock dividends declared per share Common stock dividends paid pcr share Book value per common share at year end Common shareowners at year end Ratio of earnings to fixed charges Ratio of earnings to combined fixed charges and preferred stock dividends Ratio of earnings to fixed charges (excluding AFC and RMC)
Ratio of earnings to combined fixed charges and preferred stock dividends (excluding AFC and RiXIC)
- The Company had no eanrings ro coverfixed charges.
958,150 S
983,282 788,698 S
802,630 S
(93,997)
S 701,049 S
670,324 620,423 500,938 S
382,604 11,680 239,144 263,156 111,348 111,290 S (1,345,110)
(175,035)
S {1,121,128)
S 192,312 111,215 111,177 111,129 2.15 S
2.26 S
(1.57) $
2.02 S
1.73
.10
{12.10) 2.15 S
2.3G
{1.57) $
{10.08)
S 1.73 S
251 476
{173>251) S 223>712 S
177>414 S
2.26
{1.56) $
2.01 S
1.60 1.60 1.25
.50 1.55 1.125
.25 19.13 18.57 17.45 S
19.6'1 S
29.71 90,435 82,903 85,142 93,267 106,117 1.93 1.98 1.95 2.02-1.GO 1.58 1.56 1.48 1.60 1.60 1.23 1.15 1.30 1.24
$ 2i548y850
$ 2 446>847 S 2 347 614 S
2>137 834
$ 2~072~077 Operations and Maintenance Expense Details (In rliousairds ofdollars)
Table 2 Total payroll and employee benefits Less Char cd to construction and other 420,293 S
378,831 349,242 123,838 97,650 117,761 333,359 315,114 129,990 115,315 Payroll and Employee Benefits Charged to 0 erations 296,455 281,181 231,481 203,369 199,799 Fuels electric operations Fuels gas operations Purchased power costs Fuel cost ad'ustmcnts deferred 354,859 175,046 197,154 41,643 444,458 175,877 168,749
{2,085) 461,576 188,139 128,368
{5,631) 410,174 172,431 88,465 3,359 422,997 174,G10 93,186
{5,104)
Total Fuel and Purchased Power Allother 768,702 786,999 226,304 194,628 772,452 674,429 685,689 195,825 154,527 142,201 Total Operations and rrlaintenance Expense Employees at December 31
$ 1,291,461
$ 1,262,808 S 1,199,758
$ 1,032,325 S 1,027,689 6,605 6,630 6,239 6,281 6,378
Electric 0 eratbi Income (In rlrausands ofdollaa) 1991 1990 1989 1988 1987 Table 3 Revenues Residential Commercial and industrial Other s stem revenues Total systcrn revenues Sales to other utilities Other revenues Total Revenues Expenses Operations fuel and purchased power Operations other Maintenance Depreciation Base financial component amortization Regulatory liabilitycomponent amortization Rate moderation component Regulatory liabilitycomponent Jarncsport amortization Operating taxes Federal income tax current Federal income tax deferred and other Total Ex enses Electric Operating Income S 1,047,490 1,070,098 47,838 2,165,426 23,040 9,223 2,197,689 593,656 296,798 127,446 110,037 100,971 (86,360)
(228,572) 338,429 515 173,259 1,426,179 771,510 S
997,868 1,017,387 46,673 2,061,928 24,140 (463) 2,085,605 611,122 271,608 118,545 99,922 100,971 (86,101)
(297,214) 322,197 3,138 169,274 1,313,4G2 S
772,143 S
915,644 981,740 42,232 1,939,616 42,880 792 1,983,288 584,313 237,931 115,502 91,759 50,485 (43,038)
(131,167) 793,592 104,160 312,456 14,612 (738,500) 1,392,105 S
591,183 S
835,584 883,267 40,518 1,759,369 24,152 3,412 1,786,933 501,998 195,283 96,599 82,811 262,644 18,394 166,557 1,324,286 462,647 800,952 849,626 49,791 1,700,369 11,889 6,603 1,718,861 511,079 187,573 88,431 63,840 250,047 64,095 208,954 1,374,019 344,842 gag
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Gas 0 eratui Irrcomc (In rIrousands o dallaa) i Revenues Residential, lirmspace heating other Non-residential, lirrnspace heating other Total firm revenues Interru tible rcvenucs Total system revenues Sales to other utilities Other revenues Total Revenues Expenses Operations fuel Operations other Maintenance Depreciation, depletion and amortization Operating taxes Federal income tax current Federal income tax deferred and other Total Ex crises Gas Operathig Income 190,976 29,383 70,938 25,515 316,812 21,686 338,498 12,663 351,161 175,046 78,4G9 20,046 14,783 49,951 (4,322) 333,973 17,188 198,734 30,854 68,441 26,501 324,530 30,515 355,045 6,197 361,242 175,877 68,910 16,746 12,862 48,120 500 7,740 330,755 30,487 209,192 31,692 72,351 28,674 341,909 19,226 361,135 3,191 364,326 188,139 59,587 14,286 11,671 51,935 9,468 335,086 S
29,240 201,312 31,803 68,114 28,078 329,307 18,821 348,128 2 773 350,901 172,431 53,415 12,599 10,785 48,220 15,160 312,610 38,291 Table 4 194,303 32,877 63,267 28,443 318,890 24,150 343,040 4,970 5,206 353,216 174,610 53,140 12,856 10,065 50,112 19,482 (4,811) 315,454 37,762
Electric Sales and Customers Sales millions ofkWh Residential Commercial and industrial Other System sales Sales to other utilities Total Sales Cirstorners monthly average Residential Commercial and industrial Others Customers total monthly average Customers total at ear end 1991 7,022 8,322 469 15,813 598 16,411 898,974 101%740 4,540 1,005,254 1,005,363 1990 7,022 8,359 472 15,853 532 16,385 895,294 101,562 4,504 1,001,360 1,001,441 1989 7,063 8,636 470 16,169 633 16,802 890,406 100,481 4,452 995,339 996,488 1988 6,979 8,566 495 16,040 433 16,473 882,962 98,450 4,436 985,848 989,097 1987 Table 5 6,603 8,004 439 15,046 239 15,285 872,419 95,871 4,389 972,679 976,928 Residential kiVh per customer Revenue er kAVh 7,812 7,844 7,932 7,905 7,569 14.92C 14.21C 12.96C 11.97C 12.13C Commercial and Industrial kWh per customer Revenue er kWh 81,797 12.86C 82,304 85,943 87,005 83,487 12.17C 11.37C 10.31C 10.62C System kWh per customer System revenue per kWh 16,326 16,363 16,881 16,709 15,714 13.69C 13.01C 12.00C 10.97C 11.30C Gas Sales and Customers Sales thousands ofdth Residential space heating other Non-residential space heating other Total firm sales Interru tible sales Total system sales Sales to other utilities Total Sales Customers monthly average Residential space heating other iVon-residential space heating other Total firm customers Interru tible customers Cirstomers total monthly average Customers total at ear end Residential dth per customer Revenue cr dth Non-residential, firm dth per customer Revenue cr dth System dth per customer System revenue per dth 29,687 3,195 11,636 4,171 48,689 4,538 53,227 53,227 220,562 171,581 30,453 11,003 433,599 472 434,071 436,853 83.9 6.70 381.3 8
6.10 122.6 6.36 29,810 3,448 11,271 4,352 48,881 6,347 55,228 55,228 211,400 176,000 29,072 11,310 427,782 410 428,192 430,571 85.8 6.90 386.9 3
608 128.9 6.43 32,024 3,491 11,548 4,539 51,602 5,300 56,902 56,902 204,982 179,415 27 733 11,517 423,647 359 424,006 426,060 92.4 6.78 409.9 3
628 134.2 3
635 31,276 3,589 11,054 4,580 50,499 5,078 55,577 55,577 198,949 181,926 25,979 11,725 418,579 325 418,904 421,429 91.5 3
6.69 414.6 6.15 132.7 6.26 Table 6 29,239 3,952 10,055 4,389 47,635 6,456 54,091 2,218 56,309 192,550 184,411 24,234 11,778 412,973 301 413,274 415,629 88.0 6.84 401.1 3
635 136.3
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Electric 0 crations Energy millions of kWh Nct generation Power urchnsed and (sold) net Total system requirements Corn an use and unaccounted for System sales Sales to other utilities Total Energy Available Peak Demand mW Station coincident demand Purchased or (sold) net System Peak Demand System Capability mW LILCOstations Nine Mile Point 2 (LILCO's l8% share)
Firm urchascs net Total Capability Fuel Consumed for Electric Operations Oilthousands ofbarrels Gas thousands of dth Nuclear thousands of mW days Total billions of Btu Dollars per million Btu Cents per kWh of net generation Heat rate Btu per nct kWh Fuel Mix(Percentage ofs>stem requirements)
"Oil Gas Purchased Power
-"Nuclear Fuel Total 1991 135570 3,638 17,208 (1,895) 15,813 598 16,411 3,085 819 3,904 4,078 194 244 4,516 15,314 32,924 154 129,937 2.61 2.73 5 10,484 50o/o 18 25 7
100%
1990 13,981 2,989 16,970 (1,117) 15,853 532 16,385 3,260 426 3,686 4,077 194 300 4,571 16,401 36,477 108 139,874 3.07 3.24C 10,564 56o/o 20 20 1009o 1989 15,220 2,087 17,307 (1,138) 16,169 633 16,802 3,178 510 3,688 4,066 194 400 4,660 20,480 26,490 105 154,669 2.86 S
3.Q6C 10,704 67%
13 16 4.
100qo 1988 15,228 1,940 17,168 (1,128) 16,040 433 16,473 3,347 475 3,822 3,834 194 482 4,510 19,927 29,126 87 153,828 2.53 2.67C 10,545 68o/o 15 13 1009'o 1987 Table 7 14,004 2,516 16,520 (1,474) 15,046 239 15,285 3 333 243 3,576 3,799 550 18,624 29,762 146,S36 2.86 3.01C 10,509 69o/o 16 15 100'Yo Gas 0 erations Energy thousands ofdth Natural gns iManufactured as and chan e in stora e
Total Natural and Manufactured Gas Total system requirements Corn an use and unaccounted for System sales Sales to other utilities Total Energy Available Mnxinnun Dn Scndout dth System Capability dth per day Natural gas LNG manufactured or LP as Total Capability Calendar Degree Days
$65-year average 5,032) 55,579 60 55,639 55,639 (2,412) 53,227 53,227 435,050 507,344 128,200 635,544 4,378 55,407 (15) 55,392 55,392 (164) 55,228 55,228 406,177 507,344 128,200 635,544 4,139 60,359 53 60,412 60,412 (3,510) 56,902 56,902 462,610 461,788 145,600 60?,388 5,169 58,743 (18) 58,725 58,725 (3,148) 55,577 55,577 431,940 411,596 145,600 557,196 5,162 Table 8 58,832 (63) 58,769 56,551 (2,460) 54,091 2,218 56,309 404,679 388,400 145,60Q 534,000 4,805
Construction Ex enditurcs"'In tltousands o dollars) 1991 1990 1989 1988 1987 Table 9 Electric Production Transmission Distribution General (includes nuclear fuel)
Electric Total Gas Total Common Total Total Construction Expenditures S
32,541 12,452 74,770 9,880 129,648 89,950 17,958 287,551 36,400 23,418 82,975 (1,765) 141,028 78,766 12,671 232,465 59,880 9,022 66,679 3,615 139,196 49,847 11,007 200,050 419,028 453,544 13,379 23,668 64,653 32,209 17,227 19,689 514,287 529,110 37,518 34,270 9,352 17,795 561,157 581,175
- Includes non-cash allowance forotherfunds used dun'ng construction and excludes Sltoreltam post set tlemcnt costs.
Balance Sheet (In tltousands o dollars)
Assets Utilityplant Less Accumulated depreciation, de letion and amortization
$ 4,334,73G 1,332,003
$ 4,150,822 1,262,743
$ 3,939,410 1,158,253 Table 10
$ 8,017,047
$ 9,274,103 1,071,923 980,066 Total Net UtilityPlant Regulatory asset Nonutilityproperty and other investments Current assets Deferred charges Rate moderation component Shoreham post settlement costs Shoreharn nuclear fuel Accumulated deferred income taxes Other Total Deferred Char es 3,0029783 3,786,408 9,788 884,017 602,053 378,386 79,760 439,235 360,92G 1,860,360 2,888,079 3,887,373 6,381 726,060 411,443 225,818 92,069 359,768 245,693 1,334,791 2,781,157 3,988,344 6,050 982,032 102,971 75,044 97,925 262,298 224,217 762,455 6,945,124 69,271 571,934 525,029 214,979 740,008 8,294,037 68,763 606,579 127,061 227,247 354,308 Total Assets
$ 9,543,301
$ 8,842,684
$ 8,520,038
$ 8,326,337
$ 9,323,687 Capitalization and Liabilities Capitalization Long-term debt Unamortized premium and (discount) on debt Preferred stock redemption required Preferred stock no redemption required Treasury stock, at cost Retained earnings restricted for preferred stock dividend requirements Cerumen stock and premium Capital stock expense Retained earnin s
( 14,850) 524,912 154,371 1,550,334 (40,216) 620,873 (23,125) 527,550 154,674 1,549,505 (42,676) 560,405 (28,587) 541,187 155,592 1,547,971 (42,916) 436,690 (25,011) 513,924 221,050 (58,430) 341,008 1,557,293 (56,151) 679,579 (26,646) 520,788 221,051 (40,881) 265,288 1,556,928 (56,144) 1,801,919
$ 5,001,016
$ 4,556,016
$ 4,560,01G
$ 3,449,821
$ 3,724,601 Total Ca italization Current Liabilities Deferred Credits 1989 Settlement credits Class Settlement Accumulated deferred income taxes Other Total Deferred Credits Reserves for Claims, Damages, Pensions and Benefits Total Capitalization and Liabilities 7,795,940 492,895 173,507 178,564 816,058 84,035 1,247,159 7,307
$ 9,543,801 7,282,349 449,830 182,720 167,569 634,704 117,172 1,102,165 8,340
$ 8,842,684 7,169,953 470,885 191,933 164,040 430,933 81,443 868,349 10,851
$ 8,520,038 6,G23,083 7,966,904 583,017 339,573 963,975 921,397 144,015 83,217 1,107,990 1,004,614 12,247 12,596
$ 8,326,337
$ 9,323,687
Capitalization Ratios+
Long-tenn debt Preferred stock Common e uit 1991 64%
9 27 1990 62%
10 28 1989 63%
10 27 1988 53%
15 32 1987 Table 11 47%
12 41 Total Capitalization 100%
100%
100%
100%
100%
- Includes current maturi ties oflong-tenn debt and current redemption requirements ofprcfened stock.
Comlnorl and Preferred Stock Prices Table 12 The Common Stock of the Company is traded on the New York Stock Exchange and thc Pacific Stock Exchange. The Preferred Stock $ 100 par value, Series 8, E, I, J, K and S and the Preferred Stock $25 par value, Series 0, P, Y and Z of the Company arc, and Series T was traded on the New York Stock Exchange. The table below indicates the high and low prices on the New York Stock Exchange listing of composite transactions for the years 1991 and 1990.
1991 1990 Quarter Quarter First Second Third Fourth First Second Third Fourth Corllnloll Stock Preferred Stock Series 8 5.00%
Series E 4.35%
Series l 5 /4%
Series J 8.12/o Series K 8.30%
Series 0 $2.47 Series P $2.43 Series S
9.80%
Series T $3.31 Series Y $2.65 Series Z 32.35 High Low Fligh Low High Low High Low lligh Low High Low High Low High Low High Lolv High Low High Low Hlgl1 Low 23 l/i 23/s 24 th 25 20'/>
19s/s 21s/s 21e/s 19 21'h 221/e 231/e 18s/s 17%
17s/i 17lh 53'h 54 56s/e 58 507/e 49~/s 50 49'h 48 51'h 53 52 49 46 48 47s/e 47 46'/i 49 52 44s/4 42'h 44 44'h 43th 441/e 45 47ih 42 40l/e 41 41 1/g 136 131 136 141e/e 116 112 118 115 125 131 134 139 110'h 109 114 109 85'h 86 91 94 82 79 81e/1 78T/
78 82s/~
83 887/e 77 74 75 77 85 88 91 97 85 79s/i 83 81 78 83'h 85 91 78 77'h 78'h 77'h 25e/,
26ih 27 27s/s 247/s 247/s 25'/~
25'h 24'/~
24s/i 25 26 23s/i 23s/i 24s/s 23s/i 25s/i 27ih 27s/e 28 251/
24 25 24e/4 24lh 24s/s 25lh 26s/e 23s/s 22s/i 217/s 23lh 99/s 101 102 h 105 97/s 96'h 99/s 97 96ih 100 101 102 93s/s 92 95 94 27s/i 27'/~
26'/i 26s/s 26~/s 27 26 26/s
25/,
25'/e 25 /i 25/e 27 271/,
28 28lh 26s/s 26 26s/s 261/
25 25/s 26/e 26/s 24 /4 24/s 24/>
24 /e 25'h 26/e 28/s 25i/s 247/s Thc Prcfcned Stock WOO par value, Scrics D 4.25% is traded in the over-the-counter market and no pric data is availablc. The Preened Stock 8100 pai value, Senes F, II, IMand ll Prcfencd Stock are held privately.
Corporate Information Executive Offices 175 East Old Country Road Hicksville, NY 11801 Common Stock Listed New York Stock Exchange Pacific Stock Exchange Ticker Symbol: LIL Transfer Agent and Registrar Common Stock and Preferred Stock The Bank of New York Shareholder Services Dept.
11th Floor 101 Barclay Street New York, NY 10286-1258 1-800-524-4458 Sliareowncrs'gent for Automatic Dividend Reinvestmcnt Plan The Bank of New York Dividend Reinvestment Dept.
11th Floor 101 Barclay Street New York, NY 10286-1258 1-800-524-4458 Annual Meeting The Annual Meeting ol'harcowners will be held on Monday, April 13, 1992 at 3:00 p.m. In connection with this meeting, proxies willbe solicited by thc Company. A notice ol'thc meeting, a proxy statement and a proxy will be mailed to shareowners in rl'larch.
Form 10-K Annual Rcport The Company will I'urnish, without charge, a copy of the Company's Annual Report, Form 10-K, as filed with the Securities and Excliange Commission, upon written request to: Long Island Lighting Company, Investor Relations, 175 East Old Country Road, Hicksville, NY 11801
I
- Directors-
,"William-J. Catacosinos Char'rrnan ofthe Board anil Chief Executive-OHicer'ong Island L'ighting'Company
. A; 'James'Barxtesi
- .Dean '
School>fPublic and'nvironmental Affairs Indiana University George Bugliarello PxcsMe'nt
-'olytechnic University A'nthonyF; Earley, Jr.
- President qnd
-'hief Operating Officerong Island L'ightingCompriny
~
~ 'WinfieldE. Fromm'
. Retired;-Vice Prcsident-
., -Eaton Corporation Electrical Errgineering Basil A. Paterson,
,.; Partner
" 14cyci,Suozzi, English
~
8r Klein, PC Law
- Eben W,Pyne Corporate Director:
and'Gonsultant "Vf'.R. Grace and Company
. Retired Senior Vice President Citiba'nk~KA.
"'ichard L. Schmalensee Director Center for Energy and Environmental Policy Research Massachusetts Institute ofTechnology
, George J. Sxderis, Retired Senior Vice President Finance
- Long Island Lighting Company
. John H. Talmagq..
Pa'rtner H.R. Talinage 5 Son
", Agriculture Phyllis S. Vineyard Director-
,Long Islarid Community Foundation Officers WilliamJ."'Catacosinos Ch'aiiman ofthe Board and.
ChiefExccutrvc OQieer Anthony 'F.'Earley, Jr.
I rqsIdent atrd '-
. Chief Operatirrg.OAicer E
', "James T:,Flynn Group Vice President-Errgineerinj'and Operation's Ralph T. Brandifxno.
"Vi'cePresident::.
Finance Arthur C. Marquardt Vice President
- 'Strategic Business Plannin'g Brian R. McCaffrey Vice President
': 'Administration Joseph W'.'McDonnell Vice'Jgesidellt-Communications".
'WilliamG. Schiffmacher Vice President
~ Electric Operatiorls Robert B. Stejer
-', Vice President Fossil Production WilliamE. Steiger,'r."
Vice President
,. Engineering and Construction-William'¹Dimoulas Vice President '
,Infoimatron',Systems" and. Technology,
~
',Rober t X, Kellelier.
Vice President, Human Resources John D. Leonard; Jr;-
Vice Presr'dent; Corporate Services and
.Nuclear Operations
. Adam M.,llIadsen Vice President Corporate Plarining
~ '.
Clxristian G. Wilding Vice President Conservation and
'K,oad Management.
'Walter'F. Wilm,Jr Vjce President Gas Operations c'
~ -",
Edward J:Youngling-,'ice Pr'esident
'ustomer Relations e
Vxctor.A. Staffxerx General'Counsel and Corporate Secretary
.-'Andrew R. Ragogna
'reasurer
'Thomas J. Vanely, IH Controller-Herbert M Leiman, Assistant Gen'eral Counsel and Assistant Corporate
- Secretary Kathleeri A. Marion Assistant Corporate
'ecretary and Assistant to the Chairman 1
Docket 0r~ ~~~
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