TrueOriginal value: 1152212132742113031341143821425237122135152331101911382252343439823822375342733533352531643110211323422111328438103293409361217091313126978115143391171524205191776597211810071191510120592012222223110224105297202258423261032819172032928924301377970104327743204333764853411331053547277205374120638783810639355320640710507415437107172074360304008537543901086204868220871649620009214034410922674092092314271102443971102523197210110354111101211211102112321210312411310421351310514621410611471510711582154344144451451464714748148491495015012456891012131416171819202114567110121022021032033410451052051066FalseOriginal value: N106206306406506606806706710720730740750760780770781082083083408150826084708580879810992091030911409125091460915809167091710111022101310101410201510261010281020211103111203211431110441120451151204183113041931140420311504213116043217041321804232190433220044322104532563210573220583230593240510325051132605123270513328051432905153210051632110517321205183213051932140520321505213216053317051331805233190533320054332105533663310673320683330693340610335061133606123370613338061433906153310061633110617331206183313061933140620331506213316063417061341413162215131722161318221713192218132022191321222013232113123142231143232144233145234146235147236148237149238141023914112310141223111413231214142313141523141416231514172316141823171419231814202319142123201424211412415224115324215424315524415624515724615824715924815102491511241015122411151324121514241315152414151624151517241615182417151924181520241915212420402140234212223242526272812345678978803213331373513553533141261562295222129228111086527130610912012132611524137230333710132210611772611161712722712521171726437362011272102139213425125113102231323142291291213920229232101052056106206710720781082089109209101102101111121112112212131132131411421415115161161711718118191192012021121221222312324124251081691161092161017110117112171111812118112218131914119152191620171201822019212012121221222223122242222523261232722328242912430224312532125332253426351263622637273812739227402841128422284329112932295307130923011311131223143271326112067116811712107112207212831210941295122096121071211081221013211113112131113131241311251313141131142132142143141441411551421571415614116117221732184185118619711982209121102111221122213122142221523162417124182241912520225212622126232262427Not PreparedOriginal value: 21806201519062115200616210611672161073162074163075164076165077166078167079168071016907111610071216110713161207141613071516140716161507171616071816170719161807201619072116200717210711782171083172084173085174086175087176088177089178081017908111710081217110813171208141713081517140816171508171716081817170819171808201719082117200818210811892181093182523412533422543432553442563452573462583472593482510349251134102512341125133412251434132515341425163415251734162518341725193418252034192521342025352125135262351263352264353265354266355267356268357269358261035926113510261235112613351226143513261535142616351526173516261835172619351826203519262135202636212613627236127336227436327536427636527736330109372122255292011035(456.2) Revenues From Distribution of Electricity14133910715108209342245332228216512430233613420430530301203123331131217532531240222430105414033839184123224304128440136227159142434130128536429354243233223113663253311530524137119106126134365272412076111423623422132233127132182422052523789101112141101TOTAL2102103410451057107810810911011111211314115161161718118191192012021221222412425126272812829130313234125261262712728128291293013031131321323313334134351353613637137381383913940140123Purchases/Transfers:456791011121Purchases/Transfers:45678101120923225309332640913327509233286093429709134308092343190935321009135331109235341209361130913621409236315093741609137617093871809138819093992009139102109401110140121102511221012123102134103113510421361051471061148108214910915101010115111011215121012116131013216141014171510151171610162171710181818101911819102021820102119211023119112421911125120211262203112721411281215112922161130227114012212722712822829229130302301312313213233233341343513523511012013014015016017018019011001110112011301140115011601170118011901200121012201210220230240250260241862751872761882771892781810279181127101812271118132712181427131815271418162715181727161818271718192718182027191821272018282118128192281193282194283195284196285197286198287199288191028919112810191228111913281219142813191528141916281519172816191828171919281819202819192128201929211912920229120329220429320529420629520729620829720929820102992011291018836103537936401071036208140113654351236142151336432213143612219153642310163623943917363112418361206193642332036116421366112375428137104122372302363371148437382395372352263742613273723830837223524937118433103734011371332321237233341337427104143713810515378111637112116173713120183716193713520372821372263812213852823852633823543841538240638287382268382229383291038191138220123832413381262782541768346817313511237213383141418251936204721592461257101268201271130128124013113501321460133158013416235171023719202382130239244024055024166024210802431570244203462910347302034831303493240350TrueOriginal value: 1Duplicate fact discrepancy. Schedule: 106 - Schedule - Information on Formula Rates, Row: 1, Column: c, Value: 0345035116035227035380364476104187204318304329404531050454246047625804126105228205313054340565505776058980591170510C001306R22270223802123902223100212411022241202251302125140222515022616021261702226180227190212720022272102282202128322810329203129303229403305031306032307033180313190323110033211031321203331303133140323315033416031341703351803135190336200313621033741371043820413830439404139504406041407044180414190442100414211041020811112091112201011132011111420121115201311162014111720151118201611192017112020181121201911212011121211122112321112421212521312621412721512821612921712102181211219121221101213211112142112121521131216211412172115121821161219211712202118122121191222201212221122221332211342221352231362241372251382261392271310228131122913122210131322111314221213131315221229143813291538142916381529173816291838172919381829203819292138202939212913930239130339230439330539430639530739630839730939830103993011391030123911301339123014391330153914301639153017391630183917301939183020391930213920304021301403124013134023144033154043164053174063184073194083110409311140103112401131134012311440133115401431164015311740163118401940 C001306 5-29 2018-01-01 2018-12-31 C001306 2-13 2018-01-01 2018-12-31 C001306 6-1 2018-01-01 2018-12-31 C001306 3-30 2018-01-01 2018-12-31 C001306 4-31 2018-01-01 2018-12-31 C001306 1-11 2018-01-01 2018-12-31 C001306 15-20 2018-01-01 2018-12-31 C001306 9-6 2018-01-01 2018-12-31 C001306 0-13 2018-01-01 2018-12-31 C001306 1-15 2018-01-01 2018-12-31 C001306 0-6 2018-01-01 2018-12-31 C001306 11-39 2018-12-31 C001306 11-13 2018-01-01 2018-12-31 C001306 2-23 2018-01-01 2018-12-31 C001306 19-36 2018-01-01 2018-12-31 C001306 20-5 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-6 2018-12-31 C001306 17-37 2018-12-31 C001306 18-11 2018-01-01 2018-12-31 C001306 ferc:GasUtilityMember 0-10 2017-12-31 C001306 0-7 2018-01-01 2018-09-30 C001306 0-39 2018-01-01 2018-12-31 C001306 12-19 2018-12-31 C001306 4-29 2018-12-31 C001306 21-11 2018-01-01 2018-12-31 C001306 13-4 2018-12-31 C001306 2-14 2018-01-01 2018-12-31 C001306 1-12 2018-01-01 2018-12-31 C001306 0-21 2018-01-01 2018-12-31 C001306 5-26 2018-01-01 2018-12-31 C001306 0-29 2018-01-01 2018-12-31 C001306 11-33 2018-01-01 2018-12-31 C001306 0-31 2017-01-01 2017-12-31 C001306 0-1 2018-01-01 2018-12-31 C001306 2-2 2018-01-01 2018-12-31 C001306 1-37 2018-01-01 2018-12-31 C001306 0-76 2017-01-01 2017-12-31 C001306 5-15 2018-12-31 C001306 16-37 2018-01-01 2018-12-31 C001306 14-26 2018-01-01 2018-12-31 C001306 12-6 2018-01-01 2018-12-31 C001306 7-12 2018-12-31 C001306 0-5 2018-01-01 2018-12-31 C001306 7-13 2018-12-31 C001306 ferc:GenerationStudiesMember 3-33 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 2-36 2018-01-01 2018-12-31 C001306 15-34 2018-12-31 C001306 7-4 2018-01-01 2018-12-31 C001306 8-26 2018-01-01 2018-12-31 C001306 2-39 2018-12-31 C001306 ferc:GenerationStudiesMember 1-32 2018-01-01 2018-12-31 C001306 9-18 2018-01-01 2018-12-31 C001306 0-5 2018-12-31 C001306 3-33 2018-12-31 C001306 1-1 2018-01-01 2018-12-31 C001306 0-48 2018-01-01 2018-12-31 C001306 1-15 2018-01-01 2018-12-31 C001306 9-32 2018-12-31 C001306 0-3 2018-01-01 2018-12-31 C001306 0-11 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-7 2018-01-01 2018-12-31 C001306 7-1 2018-12-31 C001306 ferc:ElectricUtilityMember 2-27 2018-12-31 C001306 ferc:ElectricUtilityMember 0-30 2018-12-31 C001306 7-15 2018-12-31 C001306 2016-12-31 C001306 0-39 2018-12-31 C001306 ferc:ElectricUtilityMember 0-5 2018-12-31 C001306 13-23 2018-01-01 2018-12-31 C001306 16-30 2018-12-31 C001306 4-16 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-2 2018-12-31 C001306 3-32 2018-01-01 2018-12-31 C001306 0-35 2018-01-01 2018-12-31 C001306 0-8 2018-12-31 C001306 0-4 2018-01-01 2018-12-31 C001306 21-31 2018-12-31 C001306 ferc:ElectricUtilityMember 0-5 2018-01-01 2018-12-31 C001306 3-31 2018-01-01 2018-12-31 C001306 15-4 2018-12-31 C001306 11-13 2018-12-31 C001306 0-29 2017-12-31 C001306 0-34 2018-12-31 C001306 2-33 2018-01-01 2018-12-31 C001306 4-26 2018-01-01 2018-12-31 C001306 1-8 2018-01-01 2018-12-31 C001306 0-7 2018-12-31 C001306 8-11 2018-01-01 2018-12-31 C001306 0-32 2018-12-31 C001306 0-25 2018-01-01 2018-12-31 C001306 12-15 2018-01-01 2018-12-31 C001306 13-28 2018-12-31 C001306 ferc:GenerationStudiesMember 3-30 2018-01-01 2018-12-31 C001306 4-9 2018-01-01 2018-12-31 C001306 5-37 2018-01-01 2018-12-31 C001306 0-12 2018-01-01 2018-12-31 C001306 1-10 2018-01-01 2018-12-31 C001306 0-21 2018-01-01 2018-12-31 C001306 15-24 2018-01-01 2018-12-31 C001306 1-31 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-42 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 3-36 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 3-4 2018-12-31 C001306 1-19 2017-12-31 C001306 16-36 2018-01-01 2018-12-31 C001306 0-80 2018-01-01 2018-12-31 C001306 0-31 2018-01-01 2018-12-31 C001306 3-3 2018-01-01 2018-12-31 C001306 5-10 2018-12-31 C001306 ferc:GeneralPlantMember ferc:ElectricUtilityMember 2018-01-01 2018-12-31 C001306 5-31 2018-01-01 2018-12-31 C001306 18-3 2018-01-01 2018-12-31 C001306 1-13 2018-12-31 C001306 17-26 2018-12-31 C001306 1-33 2018-12-31 C001306 8-7 2018-12-31 C001306 1-4 2018-01-01 2018-12-31 C001306 ferc:GasUtilityMember 0-11 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-30 2018-12-31 C001306 0-25 2017-01-01 2017-12-31 C001306 13-36 2018-01-01 2018-12-31 C001306 0-11 2018-01-01 2018-12-31 C001306 2-15 2018-01-01 2018-12-31 C001306 3-11 2018-12-31 C001306 0-15 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-36 2018-01-01 2018-12-31 C001306 0-25 2018-01-01 2018-12-31 C001306 13-22 2018-12-31 C001306 19-30 2018-01-01 2018-12-31 C001306 7-2 2018-01-01 2018-12-31 C001306 2-35 2018-01-01 2018-12-31 C001306 1-9 2018-01-01 2018-12-31 C001306 20-6 2018-01-01 2018-12-31 C001306 2-34 2018-01-01 2018-12-31 C001306 0-17 2018-01-01 2018-12-31 C001306 0-16 2018-01-01 2018-12-31 C001306 1-40 2018-01-01 2018-12-31 C001306 4-18 2018-01-01 2018-12-31 C001306 0-47 2018-01-01 2018-12-31 C001306 2-25 2017-12-31 C001306 ferc:GasUtilityMember 2017-12-31 C001306 0-28 2018-01-01 2018-12-31 C001306 0-22 2018-01-01 2018-12-31 C001306 5-13 2018-01-01 2018-12-31 C001306 12-17 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 1-35 2018-01-01 2018-12-31 C001306 5-20 2018-12-31 C001306 9-21 2018-12-31 C001306 2-19 2018-12-31 C001306 10-5 2018-12-31 C001306 16-6 2018-12-31 C001306 21-11 2018-12-31 C001306 1-17 2018-01-01 2018-12-31 C001306 21-15 2018-01-01 2018-12-31 C001306 4 2018-01-01 2018-12-31 C001306 0-36 2018-12-31 C001306 ferc:ElectricUtilityMember 1-40 2018-12-31 C001306 20-40 2018-12-31 C001306 15-19 2018-12-31 C001306 0-7 2018-01-01 2018-12-31 C001306 0-33 2018-01-01 2018-12-31 C001306 1-5 2018-01-01 2018-12-31 C001306 5-6 2018-01-01 2018-12-31 C001306 1-3 2018-01-01 2018-12-31 C001306 0-17 2018-12-31 C001306 20-9 2018-12-31 C001306 ferc:JulyMember 0 2018-01-01 2018-12-31 C001306 1-19 2018-12-31 C001306 ferc:TransmissionStudiesMember 1-3 2018-01-01 2018-12-31 C001306 ferc:SchedulingSystemControlAndDispatchMember 2018-01-01 2018-12-31 C001306 2-36 2018-01-01 2018-12-31 C001306 0-35 2018-01-01 2018-12-31 C001306 1-12 2018-01-01 2018-12-31 C001306 2-28 2018-01-01 2018-12-31 C001306 3-6 2018-01-01 2018-12-31 C001306 0-35 2018-01-01 2018-12-31 C001306 18-16 2018-01-01 2018-12-31 C001306 1 2018-01-01 2018-12-31 C001306 0-10 2018-01-01 2018-12-31 C001306 14-4 2018-01-01 2018-12-31 C001306 10-26 2018-01-01 2018-12-31 C001306 4-37 2018-01-01 2018-12-31 C001306 3-31 2018-01-01 2018-12-31 C001306 10-21 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-29 2018-12-31 C001306 0-6 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-15 2018-01-01 2018-12-31 C001306 0-14 2018-01-01 2018-12-31 C001306 11-27 2018-12-31 C001306 18-22 2018-12-31 C001306 2-19 2018-01-01 2018-12-31 C001306 0-8 2018-12-31 C001306 20-38 2018-12-31 C001306 13-6 2018-12-31 C001306 2-10 2018-12-31 C001306 20-17 2018-12-31 C001306 ScheduleElectricPlantHeldForFutureUseAbstract 2018-01-01 2018-12-31 C001306 2-22 2018-12-31 C001306 ferc:ElectricUtilityMember 2-16 2018-12-31 C001306 6-37 2018-12-31 C001306 8-21 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-5 2018-12-31 C001306 ferc:GenerationStudiesMember 4-39 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 3-5 2018-12-31 C001306 3-25 2018-01-01 2018-12-31 C001306 2-22 2018-01-01 2018-12-31 C001306 0-29 2018-01-01 2018-12-31 C001306 4-12 2018-12-31 C001306 1-11 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-11 2018-12-31 C001306 ScheduleCapitalStockExpenseAbstract 2018-01-01 2018-12-31 C001306 3-5 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 1-38 2018-01-01 2018-12-31 C001306 4-27 2018-01-01 2018-12-31 C001306 5-7 2018-01-01 2018-12-31 C001306 0-4 2018-01-01 2018-12-31 C001306 17-24 2018-12-31 C001306 1-4 2018-01-01 2018-12-31 C001306 12-25 2018-12-31 C001306 16-33 2018-12-31 C001306 0-5 2017-12-31 C001306 2-2 2018-01-01 2018-12-31 C001306 0-78 2018-01-01 2018-12-31 C001306 0-11 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 2-39 2018-01-01 2018-12-31 C001306 0-9 2018-01-01 2018-12-31 C001306 20-16 2018-01-01 2018-12-31 C001306 6-18 2018-12-31 C001306 0-19 2018-01-01 2018-12-31 C001306 22-1 2018-12-31 C001306 0-1 2018-01-01 2018-12-31 C001306 1-23 2018-01-01 2018-12-31 C001306 3-10 2018-01-01 2018-12-31 C001306 19-29 2018-12-31 C001306 0-29 2018-01-01 2018-12-31 C001306 2-21 2018-01-01 2018-12-31 C001306 21-38 2018-01-01 2018-12-31 C001306 9-2 2018-01-01 2018-12-31 C001306 1-36 2018-01-01 2018-12-31 C001306 17-2 2018-01-01 2018-12-31 C001306 17-29 2018-12-31 C001306 2-13 2018-12-31 C001306 16-27 2018-12-31 C001306 ferc:GenerationStudiesMember 4-28 2018-01-01 2018-12-31 C001306 0-3 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-18 2018-01-01 2018-12-31 C001306 20-30 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-25 2018-01-01 2018-12-31 C001306 ferc:TransmissionStudiesMember 0-4 2018-01-01 2018-12-31 C001306 0-37 2018-12-31 C001306 ferc:ElectricUtilityMember 0-40 2018-01-01 2018-12-31 C001306 1-34 2018-01-01 2018-12-31 C001306 0-12 2018-12-31 C001306 2-19 2017-12-31 C001306 9-5 2018-12-31 C001306 11-36 2018-01-01 2018-12-31 C001306 16-20 2018-01-01 2018-12-31 C001306 2-23 2018-01-01 2018-12-31 C001306 21-2 2018-12-31 C001306 3-7 2018-01-01 2018-12-31 C001306 15-11 2018-01-01 2018-12-31 C001306 9-30 2018-01-01 2018-12-31 C001306 9-26 2018-12-31 C001306 ferc:GenerationStudiesMember 4-26 2018-01-01 2018-12-31 C001306 1-27 2018-01-01 2018-12-31 C001306 14-12 2018-01-01 2018-12-31 C001306 1-5 2017-12-31 C001306 1-11 2018-01-01 2018-12-31 C001306 14-3 2018-01-01 2018-12-31 C001306 2-33 2018-01-01 2018-12-31 C001306 4-33 2018-12-31 C001306 0-21 2018-01-01 2018-12-31 C001306 0-6 2018-12-31 C001306 7-37 2018-12-31 C001306 5-39 2018-01-01 2018-12-31 C001306 0-12 2017-12-31 C001306 0-22 2018-01-01 2018-12-31 C001306 2-16 2018-12-31 C001306 0-6 2018-01-01 2018-12-31 C001306 17-16 2018-01-01 2018-12-31 C001306 6-10 2018-12-31 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2018-12-31 C001306 12-34 2018-01-01 2018-12-31 C001306 10-15 2018-12-31 C001306 11-36 2018-12-31 C001306 21-25 2018-12-31 C001306 0-22 2017-12-31 C001306 0-23 2018-12-31 C001306 11-32 2018-01-01 2018-12-31 C001306 18-29 2018-12-31 C001306 4-10 2018-01-01 2018-12-31 C001306 22-2 2018-12-31 C001306 0-42 2017-12-31 C001306 0-2 2018-01-01 2018-12-31 C001306 18-25 2018-12-31 C001306 1-37 2018-01-01 2018-12-31 C001306 1-20 2017-12-31 C001306 0-28 2018-01-01 2018-12-31 C001306 0-19 2017-12-31 C001306 0-28 2017-12-31 C001306 0-20 2018-01-01 2018-12-31 C001306 1-24 2018-01-01 2018-12-31 C001306 1-12 2018-01-01 2018-12-31 C001306 5-22 2018-01-01 2018-12-31 C001306 0-4 2018-01-01 2018-12-31 C001306 19-12 2018-01-01 2018-12-31 C001306 6-25 2018-01-01 2018-12-31 C001306 10-1 2018-01-01 2018-12-31 C001306 ferc:TransmissionStudiesMember 1-4 2018-01-01 2018-12-31 C001306 ferc:GasUtilityMember 0-14 2017-12-31 C001306 2-30 2018-12-31 C001306 0-3 2018-12-31 C001306 4-13 2018-12-31 C001306 0-7 2018-01-01 2018-12-31 C001306 1-18 2018-01-01 2018-12-31 C001306 16-31 2018-12-31 C001306 ferc:ElectricUtilityMember 1-28 2018-12-31 C001306 ferc:GenerationStudiesMember 5-33 2018-01-01 2018-12-31 C001306 1-4 2018-12-31 C001306 3-1 2018-01-01 2018-12-31 C001306 21-6 2018-12-31 C001306 14-8 2018-01-01 2018-12-31 C001306 0-6 2018-01-01 2018-12-31 C001306 5-16 2018-12-31 C001306 0-6 2017-12-31 C001306 ferc:GasUtilityMember 0-12 2018-01-01 2018-12-31 C001306 1-6 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 5-34 2018-01-01 2018-12-31 C001306 12-22 2018-01-01 2018-12-31 C001306 2-31 2018-01-01 2018-12-31 C001306 0-6 2018-12-31 C001306 19-21 2018-01-01 2018-12-31 C001306 2-8 2018-01-01 2018-12-31 C001306 1-13 2018-01-01 2018-12-31 C001306 0-18 2018-01-01 2018-12-31 C001306 19-5 2018-01-01 2018-12-31 C001306 15-14 2018-01-01 2018-12-31 C001306 3-15 2018-01-01 2018-12-31 C001306 2-28 2018-01-01 2018-12-31 C001306 6-33 2018-12-31 C001306 0-25 2018-12-31 C001306 10-32 2018-12-31 C001306 1-8 2018-12-31 C001306 10-11 2018-01-01 2018-12-31 C001306 0-16 2018-12-31 C001306 ferc:ElectricUtilityMember 2-33 2018-01-01 2018-12-31 C001306 4-36 2018-01-01 2018-12-31 C001306 2-24 2018-12-31 C001306 20-6 2018-12-31 C001306 3-7 2018-12-31 C001306 ferc:ElectricUtilityMember 2-11 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-2 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-14 2018-12-31 C001306 2-3 2018-01-01 2018-12-31 C001306 17-29 2018-01-01 2018-12-31 C001306 7-31 2018-01-01 2018-12-31 C001306 0-25 2018-01-01 2018-12-31 C001306 0-33 2018-01-01 2018-12-31 C001306 4-16 2018-12-31 C001306 18-35 2018-12-31 C001306 0-31 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-1 2018-12-31 C001306 2-22 2018-01-01 2018-12-31 C001306 0-14 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-26 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 3-35 2018-01-01 2018-12-31 C001306 2-6 2018-12-31 C001306 9-28 2018-01-01 2018-12-31 C001306 0-24 2018-01-01 2018-12-31 C001306 6-11 2018-01-01 2018-12-31 C001306 0-3 2017-12-31 C001306 ferc:ElectricUtilityMember 0-8 2018-01-01 2018-12-31 C001306 20-40 2018-01-01 2018-12-31 C001306 10-40 2018-12-31 C001306 13-27 2018-01-01 2018-12-31 C001306 14-22 2018-12-31 C001306 0-26 2018-01-01 2018-12-31 C001306 2-2 2018-12-31 C001306 0-32 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 5-24 2018-01-01 2018-12-31 C001306 15-26 2018-12-31 C001306 19-23 2018-12-31 C001306 1-3 2018-12-31 C001306 5-1 2018-01-01 2018-12-31 C001306 1-30 2018-01-01 2018-12-31 C001306 16-21 2018-01-01 2018-12-31 C001306 2-30 2018-01-01 2018-12-31 C001306 9-13 2018-01-01 2018-12-31 C001306 1-41 2018-01-01 2018-12-31 C001306 0-12 2018-01-01 2018-12-31 C001306 0-32 2017-01-01 2017-12-31 C001306 5-13 2018-12-31 C001306 0-4 2018-12-31 C001306 ferc:ElectricUtilityMember 1-33 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-11 2018-01-01 2018-12-31 C001306 0-2 2018-01-01 2018-12-31 C001306 1-44 2018-01-01 2018-12-31 C001306 2-1 2018-01-01 2018-12-31 C001306 11-33 2018-12-31 C001306 0-14 2018-01-01 2018-12-31 C001306 0-10 2018-12-31 C001306 20-2 2018-01-01 2018-12-31 C001306 7-18 2018-01-01 2018-12-31 C001306 2-31 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-11 2018-12-31 C001306 17-39 2018-12-31 C001306 1-37 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-30 2018-01-01 2018-12-31 C001306 0-16 2018-01-01 2018-12-31 C001306 10-17 2018-01-01 2018-12-31 C001306 7-27 2018-01-01 2018-12-31 C001306 0-1 2017-12-31 C001306 1-29 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-41 2018-12-31 C001306 0-10 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember ferc:OtherProductionPlantMember 2018-01-01 2018-12-31 C001306 10-38 2018-01-01 2018-12-31 C001306 8-13 2018-01-01 2018-12-31 C001306 1-28 2018-01-01 2018-12-31 C001306 15-24 2018-12-31 C001306 0-30 2018-01-01 2018-12-31 C001306 17-14 2018-12-31 C001306 7-29 2018-12-31 C001306 21-30 2018-01-01 2018-12-31 C001306 7-18 2018-12-31 C001306 0-22 2018-01-01 2018-12-31 C001306 2-9 2018-01-01 2018-12-31 C001306 18-37 2018-12-31 C001306 ferc:TransmissionStudiesMember 0-2 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 4-36 2018-01-01 2018-12-31 C001306 0-25 2018-12-31 C001306 4-11 2018-01-01 2018-12-31 C001306 2-41 2018-01-01 2018-12-31 C001306 0-16 2018-01-01 2018-12-31 C001306 ferc:ReactiveSupplyAndVoltageMember 2018-01-01 2018-12-31 C001306 12-32 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 1-31 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 5-35 2018-01-01 2018-12-31 C001306 1-19 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-24 2018-01-01 2018-12-31 C001306 14-35 2018-01-01 2018-12-31 C001306 0-40 2018-01-01 2018-12-31 C001306 0-36 2018-01-01 2018-12-31 C001306 1-16 2018-01-01 2018-12-31 C001306 13-26 2018-12-31 C001306 1-40 2018-12-31 C001306 2-21 2018-01-01 2018-12-31 C001306 0-27 2018-01-01 2018-12-31 C001306 15-40 2018-01-01 2018-12-31 C001306 2-31 2018-01-01 2018-12-31 C001306 9-27 2018-01-01 2018-12-31 C001306 0-1 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-6 2017-12-31 C001306 16-17 2018-12-31 C001306 1-31 2018-01-01 2018-12-31 C001306 1-38 2018-12-31 C001306 2-27 2018-12-31 C001306 0-16 2018-12-31 C001306 15-25 2018-12-31 C001306 0-8 2018-01-01 2018-12-31 C001306 0-5 2018-01-01 2018-12-31 C001306 3-16 2018-12-31 C001306 0-38 2018-01-01 2018-12-31 C001306 14-19 2018-12-31 C001306 0-34 2018-01-01 2018-12-31 C001306 6-3 2018-01-01 2018-12-31 C001306 0-42 2018-01-01 2018-12-31 C001306 2-34 2018-01-01 2018-12-31 C001306 18-25 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-15 2018-12-31 C001306 8-10 2018-12-31 C001306 0-40 2018-01-01 2018-12-31 C001306 0-31 2018-01-01 2018-12-31 C001306 0-6 2018-01-01 2018-12-31 C001306 16-7 2018-01-01 2018-12-31 C001306 1-35 2017-12-31 C001306 0-26 2017-12-31 C001306 5-36 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 3-1 2018-01-01 2018-12-31 C001306 1-6 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-39 2018-01-01 2018-12-31 C001306 1-39 2017-12-31 C001306 10-32 2018-01-01 2018-12-31 C001306 2-13 2018-01-01 2018-12-31 C001306 0-18 2018-01-01 2018-12-31 C001306 0-28 2018-12-31 C001306 0-20 2018-01-01 2018-12-31 C001306 14-13 2018-01-01 2018-12-31 C001306 1-36 2018-01-01 2018-12-31 C001306 2-11 2018-12-31 C001306 ferc:ElectricUtilityMember 0-7 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-31 2018-01-01 2018-12-31 C001306 14-14 2018-12-31 C001306 20-32 2018-12-31 C001306 0-54 2017-01-01 2017-12-31 C001306 0-26 2018-01-01 2018-12-31 C001306 7-14 2018-01-01 2018-12-31 C001306 8-24 2018-12-31 C001306 3-40 2018-12-31 C001306 0-33 2018-01-01 2018-12-31 C001306 10-29 2018-12-31 C001306 ferc:ElectricUtilityMember 2-25 2018-01-01 2018-12-31 C001306 0-8 2018-01-01 2018-12-31 C001306 18-32 2018-12-31 C001306 0-10 2018-01-01 2018-12-31 C001306 13-13 2018-12-31 C001306 2-40 2018-01-01 2018-12-31 C001306 1-2 2018-12-31 C001306 3-34 2018-01-01 2018-12-31 C001306 0-26 2018-12-31 C001306 13-29 2018-12-31 C001306 11-8 2018-01-01 2018-12-31 C001306 2-24 2018-01-01 2018-12-31 C001306 0-22 2018-01-01 2018-12-31 C001306 1-24 2018-12-31 C001306 14-8 2018-12-31 C001306 ferc:ElectricUtilityMember 1-29 2018-01-01 2018-12-31 C001306 4-4 2018-01-01 2018-12-31 C001306 ferc:NitrogenOxideMember ferc:CurrentYearMember 2017-12-31 C001306 1-23 2018-01-01 2018-12-31 C001306 0-33 2017-12-31 C001306 4-4 2018-01-01 2018-12-31 C001306 0-2 2018-01-01 2018-12-31 C001306 16-7 2018-12-31 C001306 18-1 2018-12-31 C001306 0-6 2018-01-01 2018-12-31 C001306 12-4 2018-01-01 2018-12-31 C001306 8-12 2018-01-01 2018-12-31 C001306 17-37 2018-01-01 2018-12-31 C001306 16-2 2018-12-31 C001306 1-6 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-7 2018-01-01 2018-12-31 C001306 4-21 2018-01-01 2018-12-31 C001306 2-33 2018-12-31 C001306 0-40 2018-01-01 2018-12-31 C001306 3-2 2018-01-01 2018-12-31 C001306 20-2 2018-12-31 C001306 1-3 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 3-37 2018-01-01 2018-12-31 C001306 ScheduleExtraordinaryPropertyLossesAbstract 2018-01-01 2018-12-31 C001306 0-27 2018-01-01 2018-12-31 C001306 5-12 2018-12-31 C001306 11-29 2018-12-31 C001306 3-29 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-26 2018-01-01 2018-12-31 C001306 3-30 2018-01-01 2018-12-31 C001306 11-1 2018-01-01 2018-12-31 C001306 16-10 2018-01-01 2018-12-31 C001306 6-35 2018-01-01 2018-12-31 C001306 2-1 2018-01-01 2018-12-31 C001306 0-1 2018-01-01 2018-12-31 C001306 1-9 2018-12-31 C001306 0-33 2018-12-31 C001306 1-15 2018-12-31 C001306 0-15 2018-01-01 2018-12-31 C001306 6-14 2018-01-01 2018-12-31 C001306 1-4 2018-01-01 2018-12-31 C001306 1-29 2018-12-31 C001306 ferc:ElectricUtilityMember 0-23 2018-12-31 C001306 0-10 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 2-27 2018-01-01 2018-12-31 C001306 5-34 2018-12-31 C001306 ferc:GenerationStudiesMember 0-30 2018-01-01 2018-12-31 C001306 0-1 2018-12-31 C001306 13-14 2018-12-31 C001306 4-35 2018-12-31 C001306 7-11 2018-01-01 2018-12-31 C001306 21-28 2018-01-01 2018-12-31 C001306 3-5 2018-12-31 C001306 5-22 2018-01-01 2018-12-31 C001306 0-15 2018-01-01 2018-12-31 C001306 0-7 2018-01-01 2018-12-31 C001306 12-34 2018-12-31 C001306 19-1 2018-12-31 C001306 15-5 2018-12-31 C001306 19-37 2018-12-31 C001306 2-25 2018-01-01 2018-12-31 C001306 0-11 2017-12-31 C001306 10-33 2018-01-01 2018-12-31 C001306 0-5 2018-01-01 2018-12-31 C001306 0-33 2018-01-01 2018-12-31 C001306 13-19 2018-12-31 C001306 1-12 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-7 2018-12-31 C001306 0-2 2018-12-31 C001306 15-29 2018-01-01 2018-12-31 C001306 0-12 2018-01-01 2018-12-31 C001306 0-38 2018-12-31 C001306 5-1 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-30 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 3-26 2018-01-01 2018-12-31 C001306 6-17 2018-01-01 2018-12-31 C001306 2-5 2018-01-01 2018-12-31 C001306 0-17 2018-01-01 2018-12-31 C001306 7-39 2018-12-31 C001306 1-22 2017-12-31 C001306 ferc:GenerationStudiesMember 0-24 2018-01-01 2018-12-31 C001306 16-18 2018-01-01 2018-12-31 C001306 4-34 2018-01-01 2018-12-31 C001306 4-17 2018-01-01 2018-12-31 C001306 21-19 2018-01-01 2018-12-31 C001306 2-10 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-8 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-26 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-32 2018-01-01 2018-12-31 C001306 13-3 2018-01-01 2018-12-31 C001306 17-33 2018-01-01 2018-12-31 C001306 12-10 2018-01-01 2018-12-31 C001306 ferc:OtherUtilityOrNonutilityMember 0-15 2018-12-31 C001306 1-15 2017-12-31 C001306 6-37 2018-01-01 2018-12-31 C001306 20-25 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-21 2018-01-01 2018-12-31 C001306 16-34 2018-01-01 2018-12-31 C001306 6-13 2018-12-31 C001306 21-15 2018-12-31 C001306 ferc:AllocationOfPayrollChargedForClearingAccountsMember 0-78 2018-01-01 2018-12-31 C001306 1-12 2018-01-01 2018-12-31 C001306 0-47 2018-01-01 2018-12-31 C001306 9-35 2018-01-01 2018-12-31 C001306 0-14 2018-01-01 2018-12-31 C001306 15-25 2018-01-01 2018-12-31 C001306 1-2 2018-01-01 2018-12-31 C001306 0-4 2018-01-01 2018-12-31 C001306 1-11 2018-01-01 2018-12-31 C001306 0-9 2018-01-01 2018-12-31 C001306 0-24 2017-01-01 2017-12-31 C001306 ferc:ElectricUtilityMember 1-41 2018-01-01 2018-12-31 C001306 11-6 2018-01-01 2018-12-31 C001306 1-5 2018-01-01 2018-12-31 C001306 2-14 2018-12-31 C001306 6-38 2018-01-01 2018-12-31 C001306 1-11 2018-12-31 C001306 0-7 2018-12-31 C001306 ferc:ElectricUtilityMember 0-3 2018-01-01 2018-12-31 C001306 6-23 2018-12-31 C001306 2-18 2018-12-31 C001306 1-15 2018-01-01 2018-12-31 C001306 0-6 2017-12-31 C001306 9-3 2018-12-31 C001306 13-5 2018-01-01 2018-12-31 C001306 0-15 2018-01-01 2018-12-31 C001306 0-24 2018-01-01 2018-12-31 C001306 0-19 2018-01-01 2018-12-31 C001306 6-3 2018-12-31 C001306 0-19 2018-01-01 2018-12-31 C001306 ferc:GasUtilityMember 0-13 2017-12-31 C001306 16-17 2018-01-01 2018-12-31 C001306 13-13 2018-01-01 2018-12-31 C001306 8-14 2018-01-01 2018-12-31 C001306 8-18 2018-01-01 2018-12-31 C001306 0-7 2018-01-01 2018-12-31 C001306 4-14 2018-01-01 2018-12-31 C001306 ferc:TransmissionStudiesMember 0-10 2018-01-01 2018-12-31 C001306 0-6 2018-01-01 2018-12-31 C001306 2-20 2018-01-01 2018-12-31 C001306 15-23 2018-12-31 C001306 ferc:ElectricUtilityMember 2-10 2018-12-31 C001306 5 2018-01-01 2018-12-31 C001306 20-11 2018-12-31 C001306 0-39 2018-01-01 2018-12-31 C001306 8-22 2018-01-01 2018-12-31 C001306 1-34 2018-01-01 2018-12-31 C001306 18-34 2018-12-31 C001306 1-11 2018-01-01 2018-12-31 C001306 19-28 2018-12-31 C001306 12-39 2018-12-31 C001306 11-10 2018-12-31 C001306 17-25 2018-12-31 C001306 19-31 2018-12-31 C001306 1-32 2017-12-31 C001306 10-23 2018-01-01 2018-12-31 C001306 10-16 2018-01-01 2018-12-31 C001306 14-36 2018-12-31 C001306 1-1 2018-01-01 2018-12-31 C001306 2-10 2018-01-01 2018-12-31 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C001306 13-21 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-17 2018-01-01 2018-12-31 C001306 13-15 2018-12-31 C001306 0-27 2018-01-01 2018-12-31 C001306 21-18 2018-12-31 C001306 5-33 2018-01-01 2018-12-31 C001306 1-7 2018-01-01 2018-12-31 C001306 0-11 2018-01-01 2018-12-31 C001306 2-21 2018-12-31 C001306 16-3 2018-12-31 C001306 2-26 2018-12-31 C001306 0-30 2018-01-01 2018-12-31 C001306 21-37 2018-12-31 C001306 1-18 2018-01-01 2018-12-31 C001306 12-40 2018-12-31 C001306 2-37 2018-12-31 C001306 0-34 2018-01-01 2018-12-31 C001306 9-23 2018-12-31 C001306 16-29 2018-01-01 2018-12-31 C001306 18-14 2018-12-31 C001306 3-1 2018-01-01 2018-12-31 C001306 1-26 2018-01-01 2018-12-31 C001306 7-17 2018-12-31 C001306 20-8 2018-12-31 C001306 0-23 2018-01-01 2018-12-31 C001306 2-5 2018-12-31 C001306 1-16 2018-01-01 2018-12-31 C001306 4-39 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-32 2018-01-01 2018-12-31 C001306 2-29 2018-01-01 2018-12-31 C001306 0-13 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 4-33 2018-01-01 2018-12-31 C001306 2-30 2018-01-01 2018-12-31 C001306 0-26 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-26 2018-12-31 C001306 2-14 2018-01-01 2018-12-31 C001306 0-20 2018-01-01 2018-12-31 C001306 0-18 2018-01-01 2018-12-31 C001306 20-13 2018-12-31 C001306 1-12 2017-12-31 C001306 12-17 2018-12-31 C001306 2-24 2018-01-01 2018-12-31 C001306 0-3 2017-12-31 C001306 0-18 2018-12-31 C001306 3-26 2018-12-31 C001306 11-4 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-21 2018-12-31 C001306 5-6 2018-12-31 C001306 7-8 2018-01-01 2018-12-31 C001306 11-26 2018-12-31 C001306 0-31 2018-01-01 2018-12-31 C001306 19-17 2018-12-31 C001306 3-12 2018-12-31 C001306 0-7 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-1 2018-01-01 2018-12-31 C001306 0-40 2018-12-31 C001306 16-31 2018-01-01 2018-12-31 C001306 19-22 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 3-28 2018-01-01 2018-12-31 C001306 8-4 2018-01-01 2018-12-31 C001306 2-22 2018-01-01 2018-12-31 C001306 7-12 2018-01-01 2018-12-31 C001306 0-12 2018-01-01 2018-12-31 C001306 0-49 2018-01-01 2018-12-31 C001306 7-16 2018-12-31 C001306 ScheduleAllowanceInventoryAbstract 2018-01-01 2018-12-31 C001306 0-23 2018-01-01 2018-12-31 C001306 9-23 2018-01-01 2018-12-31 C001306 17-32 2018-01-01 2018-12-31 C001306 1-33 2018-01-01 2018-12-31 C001306 11-17 2018-12-31 C001306 0-8 2018-01-01 2018-12-31 C001306 21-9 2018-01-01 2018-12-31 C001306 8-37 2018-01-01 2018-12-31 C001306 12-22 2018-12-31 C001306 2-3 2018-01-01 2018-12-31 C001306 1-15 2018-01-01 2018-12-31 C001306 0-4 2018-01-01 2018-12-31 C001306 8-38 2018-12-31 C001306 0-23 2018-01-01 2018-12-31 C001306 0-9 2018-12-31 C001306 2-13 2018-01-01 2018-12-31 C001306 2-7 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 0-39 2018-01-01 2018-12-31 C001306 2-16 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-13 2018-12-31 C001306 0-5 2018-12-31 C001306 6-35 2018-12-31 C001306 ferc:GenerationStudiesMember 3-38 2018-01-01 2018-12-31 C001306 1-30 2018-12-31 C001306 ferc:GenerationStudiesMember 4-24 2018-01-01 2018-12-31 C001306 0-18 2018-01-01 2018-12-31 C001306 0-30 2018-12-31 C001306 6-29 2018-12-31 C001306 ferc:ElectricUtilityMember 2-5 2018-12-31 C001306 1-28 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-8 2018-01-01 2018-12-31 C001306 20-19 2018-01-01 2018-12-31 C001306 4-35 2018-01-01 2018-12-31 C001306 1-27 2018-01-01 2018-12-31 C001306 17-28 2018-01-01 2018-12-31 C001306 ferc:ElectricPlantInServiceMember ferc:ElectricUtilityMember 2018-01-01 2018-12-31 C001306 0-31 2018-01-01 2018-12-31 C001306 0-10 2018-01-01 2018-12-31 C001306 2-10 2018-01-01 2018-12-31 C001306 1-31 2018-01-01 2018-12-31 C001306 1-15 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 0-22 2018-01-01 2018-12-31 C001306 1-17 2018-01-01 2018-12-31 C001306 9-12 2018-01-01 2018-12-31 C001306 0-38 2018-01-01 2018-12-31 C001306 19-7 2018-01-01 2018-12-31 C001306 1-39 2018-01-01 2018-12-31 C001306 0-14 2018-12-31 C001306 2-6 2018-01-01 2018-12-31 C001306 0-4 2018-01-01 2018-12-31 C001306 12-36 2018-01-01 2018-12-31 C001306 0-30 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-5 2018-01-01 2018-12-31 C001306 2-17 2018-01-01 2018-12-31 C001306 18-14 2018-01-01 2018-12-31 C001306 2-21 2018-12-31 C001306 0-12 2018-01-01 2018-12-31 C001306 2-33 2018-12-31 C001306 0-9 2018-01-01 2018-12-31 C001306 2-13 2018-01-01 2018-12-31 C001306 1-6 2018-01-01 2018-12-31 C001306 0-12 2018-01-01 2018-12-31 C001306 ferc:TransmissionStudiesMember 0-20 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-23 2018-01-01 2018-12-31 C001306 15-36 2018-01-01 2018-12-31 C001306 2-29 2018-12-31 C001306 16-14 2018-12-31 C001306 0-20 2018-01-01 2018-12-31 C001306 1-24 2018-01-01 2018-12-31 C001306 17-35 2018-12-31 C001306 14-1 2018-12-31 C001306 ferc:ElectricUtilityMember 1-31 2018-12-31 C001306 16-4 2018-01-01 2018-12-31 C001306 9-4 2018-01-01 2018-12-31 C001306 9-32 2018-01-01 2018-12-31 C001306 6 2018-01-01 2018-12-31 C001306 17-4 2018-01-01 2018-12-31 C001306 20-38 2018-01-01 2018-12-31 C001306 1-40 2018-01-01 2018-12-31 C001306 1-22 2018-12-31 C001306 1-28 2018-01-01 2018-12-31 C001306 4-10 2018-01-01 2018-12-31 C001306 1-4 2018-01-01 2018-12-31 C001306 0-11 2017-12-31 C001306 0-25 2018-01-01 2018-12-31 C001306 0-19 2018-12-31 C001306 10-10 2018-12-31 C001306 20-35 2018-12-31 C001306 21-8 2018-01-01 2018-12-31 C001306 3-14 2018-01-01 2018-12-31 C001306 0-9 2018-01-01 2018-12-31 C001306 0-28 2018-01-01 2018-12-31 C001306 4-9 2018-12-31 C001306 10-36 2018-01-01 2018-12-31 C001306 2-18 2018-12-31 C001306 7-6 2018-01-01 2018-12-31 C001306 0-37 2018-01-01 2018-12-31 C001306 2-18 2018-01-01 2018-12-31 C001306 1-2 2018-01-01 2018-12-31 C001306 13-35 2018-01-01 2018-12-31 C001306 ferc:GasUtilityMember 0-13 2018-12-31 C001306 0-11 2018-01-01 2018-12-31 C001306 0-38 2018-12-31 C001306 0-37 2018-12-31 C001306 ferc:ElectricUtilityMember 0-2 2017-12-31 C001306 0-5 2018-01-01 2018-12-31 C001306 14-34 2018-12-31 C001306 5-32 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-36 2018-01-01 2018-12-31 C001306 14-37 2018-01-01 2018-12-31 C001306 11-19 2018-01-01 2018-12-31 C001306 10-6 2018-01-01 2018-12-31 C001306 0-34 2018-01-01 2018-12-31 C001306 2-40 2018-01-01 2018-12-31 C001306 1-35 2018-01-01 2018-12-31 C001306 0-37 2018-12-31 C001306 10-9 2018-01-01 2018-12-31 C001306 12-37 2018-12-31 C001306 16-16 2018-12-31 C001306 0-4 2018-01-01 2018-12-31 C001306 1-8 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-21 2018-01-01 2018-12-31 C001306 0-35 2017-12-31 C001306 3-38 2018-01-01 2018-12-31 C001306 11-24 2018-12-31 C001306 ferc:ElectricUtilityMember 0-2 2018-01-01 2018-12-31 C001306 9-37 2018-01-01 2018-12-31 C001306 15-7 2018-01-01 2018-12-31 C001306 12-19 2018-01-01 2018-12-31 C001306 1-47 2018-01-01 2018-12-31 C001306 19-36 2018-12-31 C001306 5-31 2018-12-31 C001306 0-24 2018-01-01 2018-12-31 C001306 4-25 2018-01-01 2018-12-31 C001306 0-26 2018-01-01 2018-12-31 C001306 2-11 2018-01-01 2018-12-31 C001306 1-3 2018-12-31 C001306 18-28 2018-12-31 C001306 ScheduleTransmissionLinesAddedAbstract 2018-01-01 2018-12-31 C001306 10-1 2018-12-31 C001306 1-37 2018-01-01 2018-12-31 C001306 16-5 2018-12-31 C001306 7-7 2018-01-01 2018-12-31 C001306 0-27 2018-01-01 2018-12-31 C001306 10-30 2018-12-31 C001306 18-28 2018-01-01 2018-12-31 C001306 3-23 2018-01-01 2018-12-31 C001306 0-5 2018-01-01 2018-12-31 C001306 1-11 2017-12-31 C001306 12-3 2018-01-01 2018-12-31 C001306 19-3 2018-01-01 2018-12-31 C001306 2-9 2018-01-01 2018-12-31 C001306 1 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 1-33 2018-01-01 2018-12-31 C001306 11-5 2018-01-01 2018-12-31 C001306 0-6 2018-12-31 C001306 0-7 2018-01-01 2018-12-31 C001306 0-13 2018-01-01 2018-12-31 C001306 17-23 2018-01-01 2018-12-31 C001306 1-11 2018-01-01 2018-12-31 C001306 7-4 2018-12-31 C001306 1-32 2018-01-01 2018-12-31 C001306 21-39 2018-01-01 2018-12-31 C001306 1-14 2018-01-01 2018-12-31 C001306 19-21 2018-12-31 C001306 0-1 2017-12-31 C001306 0-9 2018-01-01 2018-12-31 C001306 0-37 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 1-27 2018-01-01 2018-12-31 C001306 16-15 2018-12-31 C001306 18-30 2018-01-01 2018-12-31 C001306 ferc:OtherUtilityOrNonutilityMember 0-11 2018-01-01 2018-12-31 C001306 17-17 2018-12-31 C001306 20-33 2018-12-31 C001306 0-5 2018-12-31 C001306 0-28 2018-01-01 2018-12-31 C001306 0-24 2018-01-01 2018-12-31 C001306 17-13 2018-01-01 2018-12-31 C001306 1-16 2018-01-01 2018-12-31 C001306 0-23 2018-01-01 2018-12-31 C001306 19-15 2018-12-31 C001306 14-9 2018-12-31 C001306 4-35 2018-01-01 2018-12-31 C001306 0-12 2018-01-01 2018-12-31 C001306 0-15 2018-01-01 2018-12-31 C001306 1-30 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 3-27 2018-01-01 2018-12-31 C001306 13-9 2018-12-31 C001306 13-24 2018-01-01 2018-12-31 C001306 2-34 2018-01-01 2018-12-31 C001306 0-23 2017-12-31 C001306 0-5 2017-01-01 2017-12-31 C001306 11-7 2018-12-31 C001306 ferc:ElectricUtilityMember 2-18 2018-01-01 2018-12-31 C001306 2-26 2018-12-31 C001306 5-11 2018-12-31 C001306 0-7 2018-01-01 2018-12-31 C001306 1-2 2018-12-31 C001306 0-28 2018-01-01 2018-12-31 C001306 10-7 2018-12-31 C001306 0-17 2018-12-31 C001306 1-21 2018-01-01 2018-12-31 C001306 7-10 2018-01-01 2018-12-31 C001306 20-24 2018-01-01 2018-12-31 C001306 1-33 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-34 2018-12-31 C001306 0-2 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 3-2 2018-12-31 C001306 ferc:ElectricPlantInServiceMember ferc:ElectricUtilityMember 2017-12-31 C001306 0-16 2018-01-01 2018-12-31 C001306 1-40 2018-01-01 2018-12-31 C001306 1-2 2018-01-01 2018-12-31 C001306 4-5 2018-01-01 2018-12-31 C001306 10-18 2018-12-31 C001306 17-32 2018-12-31 C001306 0-4 2018-01-01 2018-12-31 C001306 8-5 2018-01-01 2018-12-31 C001306 1-30 2017-12-31 C001306 10-24 2018-12-31 C001306 1-33 2018-01-01 2018-12-31 C001306 13-10 2018-12-31 C001306 15-15 2018-12-31 C001306 0-4 2018-01-01 2018-12-31 C001306 8-6 2018-12-31 C001306 0-41 2018-12-31 C001306 2-17 2018-01-01 2018-12-31 C001306 0-21 2018-01-01 2018-12-31 C001306 ScheduleHydroelectricGeneratingPlantStatisticsAbstract 2018-01-01 2018-12-31 C001306 3-7 2018-01-01 2018-12-31 C001306 1-26 2018-01-01 2018-12-31 C001306 0-2 2018-12-31 C001306 1-4 2017-12-31 C001306 1-10 2018-01-01 2018-12-31 C001306 0-18 2018-12-31 C001306 0-14 2018-12-31 C001306 ferc:TransmissionStudiesMember 0-7 2018-01-01 2018-12-31 C001306 0-16 2017-12-31 C001306 0-30 2018-01-01 2018-12-31 C001306 10-7 2018-01-01 2018-12-31 C001306 8-1 2018-12-31 C001306 21-3 2018-12-31 C001306 2-33 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 3-32 2018-01-01 2018-12-31 C001306 ferc:TransmissionStudiesMember 1-6 2018-01-01 2018-12-31 C001306 6-14 2018-12-31 C001306 0-25 2018-12-31 C001306 0-7 2017-12-31 C001306 ferc:IntangiblePlantMember ferc:ElectricUtilityMember 2018-01-01 2018-12-31 C001306 8-12 2018-12-31 C001306 ferc:ElectricUtilityMember 2-21 2018-01-01 2018-12-31 C001306 13-28 2018-01-01 2018-12-31 C001306 3-5 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-14 2018-01-01 2018-12-31 C001306 1-34 2018-01-01 2018-12-31 C001306 0-10 2018-01-01 2018-12-31 C001306 0-21 2018-01-01 2018-12-31 C001306 21-13 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 3-1 2018-12-31 C001306 2-4 2018-01-01 2018-12-31 C001306 7-12 2018-01-01 2018-12-31 C001306 3-25 2018-01-01 2018-12-31 C001306 0-11 2018-01-01 2018-12-31 C001306 1-8 2017-12-31 C001306 0-3 2018-12-31 C001306 2-18 2017-12-31 C001306 1-16 2018-01-01 2018-12-31 C001306 8-33 2018-12-31 C001306 ferc:ElectricUtilityMember 2-20 2018-01-01 2018-12-31 C001306 8-20 2018-01-01 2018-12-31 C001306 18-31 2018-12-31 C001306 1-21 2018-01-01 2018-12-31 C001306 19-15 2018-01-01 2018-12-31 C001306 0-37 2018-01-01 2018-12-31 C001306 3-37 2018-01-01 2018-12-31 C001306 20-37 2018-12-31 C001306 0-9 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember ferc:ElectricPlantInServiceMember 0-16 2018-01-01 2018-12-31 C001306 0-14 2018-01-01 2018-12-31 C001306 1-32 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-42 2018-12-31 C001306 ferc:ElectricUtilityMember 1-22 2018-01-01 2018-12-31 C001306 1-9 2018-01-01 2018-12-31 C001306 5-3 2018-01-01 2018-12-31 C001306 9-24 2018-12-31 C001306 1-30 2018-01-01 2018-12-31 C001306 20-23 2018-01-01 2018-12-31 C001306 19-23 2018-01-01 2018-12-31 C001306 ferc:NitrogenOxideMember 1 2018-01-01 2018-12-31 C001306 1-12 2018-01-01 2018-12-31 C001306 ferc:TransmissionStudiesMember 0-16 2018-01-01 2018-12-31 C001306 4-28 2018-12-31 C001306 0-34 2018-01-01 2018-12-31 C001306 0-33 2018-01-01 2018-12-31 C001306 2-22 2018-01-01 2018-12-31 C001306 2017-01-01 2017-12-31 C001306 0-3 2018-01-01 2018-12-31 C001306 1-25 2017-12-31 C001306 9-22 2018-12-31 C001306 ferc:TransmissionStudiesMember 1-10 2018-01-01 2018-12-31 C001306 1-14 2018-01-01 2018-12-31 C001306 13-6 2018-01-01 2018-12-31 C001306 15-30 2018-01-01 2018-12-31 C001306 1-33 2018-01-01 2018-12-31 C001306 ferc:DecemberMember 0 2018-01-01 2018-12-31 C001306 5-5 2018-01-01 2018-12-31 C001306 12-18 2018-12-31 C001306 ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract 2018-01-01 2018-12-31 C001306 5-23 2018-01-01 2018-12-31 C001306 4-25 2018-01-01 2018-12-31 C001306 17-9 2018-12-31 C001306 21-23 2018-12-31 C001306 0-28 2018-01-01 2018-12-31 C001306 6-32 2018-01-01 2018-12-31 C001306 15-32 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 2-30 2018-01-01 2018-12-31 C001306 0-23 2018-01-01 2018-12-31 C001306 0-22 2018-01-01 2018-12-31 C001306 1-9 2018-01-01 2018-12-31 C001306 2-24 2017-12-31 C001306 1-36 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-16 2018-01-01 2018-12-31 C001306 0-8 2018-01-01 2018-12-31 C001306 3-13 2018-01-01 2018-12-31 C001306 ferc:GenerationStudiesMember 2-33 2018-01-01 2018-12-31 C001306 0-31 2018-12-31 C001306 2-20 2018-01-01 2018-12-31 C001306 3 2018-01-01 2018-12-31 C001306 0-12 2018-01-01 2018-12-31 C001306 ferc:TransmissionStudiesMember 0-9 2018-01-01 2018-12-31 C001306 0-14 2018-01-01 2018-12-31 C001306 13-34 2018-01-01 2018-12-31 C001306 1-38 2018-01-01 2018-12-31 C001306 1-5 2018-12-31 C001306 16-13 2018-12-31 C001306 ferc:ElectricUtilityMember 1-23 2018-12-31 C001306 0-5 2018-12-31 C001306 15-1 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-19 2018-01-01 2018-12-31 C001306 6-26 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 2-27 2018-01-01 2018-12-31 C001306 2-1 2018-12-31 C001306 17-3 2018-12-31 C001306 ferc:GenerationStudiesMember 3-22 2018-01-01 2018-12-31 C001306 5-35 2018-01-01 2018-12-31 C001306 0-11 2018-01-01 2018-12-31 C001306 3-36 2018-12-31 C001306 6-36 2018-01-01 2018-12-31 C001306 1-6 2017-12-31 C001306 0-19 2018-01-01 2018-12-31 C001306 9-8 2018-01-01 2018-12-31 C001306 0-34 2018-01-01 2018-12-31 C001306 12-28 2018-12-31 C001306 3-3 2018-12-31 C001306 9-22 2018-01-01 2018-12-31 C001306 7-33 2018-12-31 C001306 0-7 2018-01-01 2018-12-31 C001306 0-3 2018-12-31 C001306 6-6 2018-01-01 2018-12-31 C001306 ferc:ElectricUtilityMember 0-22 2018-01-01 2018-12-31 C001306 16-2 2018-01-01 2018-12-31 C001306 2-5 2018-01-01 2018-12-31 C001306 1-31 2018-01-01 2018-12-31 C001306 1-18 2018-01-01 2018-12-31 utr:MW utr:kWh utr:kV utr:mi shares iso4217:USD utr:MWh ferc:MVa iso4217:USD shares pure iso4217:USD utr:kWh
THIS FILING IS
Item 1:
An Initial (Original) Submission
OR
Resubmission No.

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and other sanctions as provided by law. The Federal Energy Regulatory Commission does not consider these reports to be of confidential nature
Exact Legal Name of Respondent (Company)

Niagara Mohawk Power Corporation
Year/Period of Report

End of:
2018
/
Q4


INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

  1. Purpose

    FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q)is a quarterly regulatory requirement which supplements the annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be non-confidential public use forms.
  2. Who Must Submit

    Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).

    Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
    1. one million megawatt hours of total annual sales,
    2. 100 megawatt hours of annual sales for resale,
    3. 500 megawatt hours of annual power exchanges delivered, or
    4. 500 megawatt hours of annual wheeling for others (deliveries plus losses).
  3. What and Where to Submit

    1. Submit FERC Forms 1 and 3-Q electronically through the forms submission software. Retain one copy of each report for your files. Any electronic submission must be created by using the forms submission software provided free by the Commission at its web site: http://www.ferc.gov/docs-filing/forms/form-1/elec-subm-soft.asp. The software is used to submit the electronic filing to the Commission via the Internet.
    2. The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
    3. Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the Commission at:
      Secretary
      Federal Energy Regulatory Commission 888 First Street, NE
      Washington, DC 20426
    4. For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the Secretary of the Commission at the address above.

      The CPA Certification Statement should:
      1. Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and
      2. Be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18 C.F.R. §§ 41.10-41.12 for specific qualifications.)

        Schedules
        Pages
        Comparative Balance Sheet 110-113
        Statement of Income 114-117
        Statement of Retained Earnings 118-119
        Statement of Cash Flows 120-121
        Notes to Financial Statements 122-123
    5. The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.

      “In connection with our regular examination of the financial statements of for the year ended on which we have reported separately under date of , we have also reviewed schedules of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.

      Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below) conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.
    6. Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. To further that effort, new selections, “Annual Report to Stockholders,” and “CPA Certification Statement” have been added to the dropdown “pick list” from which companies must choose when eFiling. Further instructions are found on the Commission’s website at http://www.ferc.gov/help/how-to.asp.
    7. Federal, State and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Q free of charge from http://www.ferc.gov/docs-filing/forms/form-1/form-1.pdf and http://www.ferc.gov/docs-filing/forms.asp#3Q-gas .
  4. When to Submit

    FERC Forms 1 and 3-Q must be filed by the following schedule:

    1. FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and
    2. FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).
  5. Where to Send Comments on Public Reporting Burden.

    The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to average 168 hours per response.

    Send comments regarding these burden estimates or any aspect of these collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 (Attention: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information does not display a valid control number (44 U.S.C. § 3512 (a)).

GENERAL INSTRUCTIONS

  1. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and phrases in accordance with the USofA.
  2. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year's year to date amounts.
  3. Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely states the fact.
  4. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on the List of Schedules, pages 2 and 3.
  5. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed only for resubmissions (see VII. below).
  6. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
  7. For any resubmissions, submit the electronic filing using the form submission software only. Please explain the reason for the resubmission in a footnote to the data field.
  8. Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
  9. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different figures were used.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:

FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self" means the respondent.

FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.

LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.

OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.

SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the duration of each period of reservation is less than one-year.

NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions.

OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in a footnote for each entry.

AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment.

DEFINITIONS
  1. Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the commission whose authorization was obtained and give date of the authorization.
  2. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is made.

EXCERPTS FROM THE LAW

Federal Power Act, 16 U.S.C. § 791a-825r

Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:

  1. ’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter defined;
  2. 'Person' means an individual or a corporation;
  3. 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor in interest thereof;
  1. 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ......
  1. "project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distribution system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit;

"Sec. 4. The Commission is hereby authorized and empowered
  1. 'To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity, development -costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the purposes of this Act."

"Sec. 304.
  1. Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission may be rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports salt be made, and require from such persons specific answers to all questions upon which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise specifies*.10
"Sec. 309.
  1. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within which they shall be field..."

GENERAL PENALTIES

The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).


FERC FORM NO.
1

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent

Niagara Mohawk Power Corporation
02 Year/ Period of Report


End of:
2018
/
Q4
03 Previous Name and Date of Change (If name changed during year)

/
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)

300 Erie Boulevard West, Syracuse, NY 13202
05 Name of Contact Person

Romina Feduzi-Lopez
06 Title of Contact Person

NY Assistant Controller
07 Address of Contact Person (Street, City, State, Zip Code)

One Metrotech Center, Brooklyn, NY 11201
08 Telephone of Contact Person, Including Area Code

(929) 324-4211
09 This Report is An Original / A Resubmission

(1)
An Original

(2)
A Resubmission
10 Date of Report (Mo, Da, Yr)

04/17/2019
Annual Corporate Officer Certification
The undersigned officer certifies that:

I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material respects to the Uniform System of Accounts.

01 Name

George Carlin
02 Title

Vice President, NY Controller
03 Signature

04 Date Signed (Mo, Da, Yr)

04/17/2019
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any false, fictitious or fraudulent statements as to any matter within its jurisdiction.


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
LIST OF SCHEDULES (Electric Utility)

Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".

Line No.
Title of Schedule
(a)
Reference Page No.
(b)
Remarks
(c)
ScheduleIdentificationAbstract
Identification
1
ScheduleListOfSchedulesAbstract
List of Schedules
2
1
ScheduleGeneralInformationAbstract
General Information
101
2
ScheduleControlOverRespondentAbstract
Control Over Respondent
102
3
ScheduleCorporationsControlledByRespondentAbstract
Corporations Controlled by Respondent
103
4
ScheduleOfficersAbstract
Officers
104
5
ScheduleDirectorsAbstract
Directors
105
6
ScheduleInformationOnFormulaRatesAbstract
Information on Formula Rates
106
7
ScheduleImportantChangesDuringTheQuarterYearAbstract
Important Changes During the Year
108
8
ScheduleComparativeBalanceSheetAbstract
Comparative Balance Sheet
110
9
ScheduleStatementOfIncomeAbstract
Statement of Income for the Year
114
10
ScheduleRetainedEarningsAbstract
Statement of Retained Earnings for the Year
118
11
ScheduleStatementOfCashFlowsAbstract
Statement of Cash Flows
120
12
ScheduleNotesToFinancialStatementsAbstract
Notes to Financial Statements
122
13
ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract
Statement of Accum Other Comp Income, Comp Income, and Hedging Activities
122a
14
ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract
Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep
200
15
ScheduleNuclearFuelMaterialsAbstract
Nuclear Fuel Materials
202
NONE
16
ScheduleElectricPlantInServiceAbstract
Electric Plant in Service
204
17
ScheduleElectricPropertyLeasedToOthersAbstract
Electric Plant Leased to Others
213
18
ScheduleElectricPlantHeldForFutureUseAbstract
Electric Plant Held for Future Use
214
NONE
19
ScheduleConstructionWorkInProgressElectricAbstract
Construction Work in Progress-Electric
216
20
ScheduleAccumulatedProvisionForDepreciationOfElectricUtilityPlantAbstract
Accumulated Provision for Depreciation of Electric Utility Plant
219
21
ScheduleInvestmentsInSubsidiaryCompaniesAbstract
Investment of Subsidiary Companies
224
22
ScheduleMaterialsAndSuppliesAbstract
Materials and Supplies
227
23
ScheduleAllowanceInventoryAbstract
Allowances
228
NONE
24
ScheduleExtraordinaryPropertyLossesAbstract
Extraordinary Property Losses
230a
NONE
25
ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract
Unrecovered Plant and Regulatory Study Costs
230b
NONE
26
ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract
Transmission Service and Generation Interconnection Study Costs
231
27
ScheduleOtherRegulatoryAssetsAbstract
Other Regulatory Assets
232
28
ScheduleMiscellaneousDeferredDebitsAbstract
Miscellaneous Deferred Debits
233
29
ScheduleAccumulatedDeferredIncomeTaxesAbstract
Accumulated Deferred Income Taxes
234
30
ScheduleCapitalStockAbstract
Capital Stock
250
31
ScheduleOtherPaidInCapitalAbstract
Other Paid-in Capital
253
32
ScheduleCapitalStockExpenseAbstract
Capital Stock Expense
254b
NONE
33
ScheduleLongTermDebtAbstract
Long-Term Debt
256
34
ScheduleReconciliationOfReportedNetIncomeWithTaxableIncomeForFederalIncomeTaxesAbstract
Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax
261
35
ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract
Taxes Accrued, Prepaid and Charged During the Year
262
36
ScheduleAccumulatedDeferredInvestmentTaxCreditsAbstract
Accumulated Deferred Investment Tax Credits
266
37
ScheduleOtherDeferredCreditsAbstract
Other Deferred Credits
269
38
ScheduleAccumulatedDeferredIncomeTaxesAcceleratedAmortizationPropertyAbstract
Accumulated Deferred Income Taxes-Accelerated Amortization Property
272
NONE
39
ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract
Accumulated Deferred Income Taxes-Other Property
274
40
ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract
Accumulated Deferred Income Taxes-Other
276
41
ScheduleOtherRegulatoryLiabilitiesAbstract
Other Regulatory Liabilities
278
42
ScheduleElectricOperatingRevenuesAbstract
Electric Operating Revenues
300
43
ScheduleRegionalTransmissionServiceRevenuesAbstract
Regional Transmission Service Revenues (Account 457.1)
302
NONE
44
ScheduleSalesOfElectricityByRateSchedulesAbstract
Sales of Electricity by Rate Schedules
304
45
ScheduleSalesForResaleAbstract
Sales for Resale
310
46
ScheduleElectricOperationsAndMaintenanceExpensesAbstract
Electric Operation and Maintenance Expenses
320
47
SchedulePurchasedPowerAbstract
Purchased Power
326
48
ScheduleTransmissionOfElectricityForOthersAbstract
Transmission of Electricity for Others
328
49
ScheduleTransmissionOfElectricityByIsoOrRtoAbstract
Transmission of Electricity by ISO/RTOs
331
50
ScheduleTransmissionOfElectricityByOthersAbstract
Transmission of Electricity by Others
332
51
ScheduleMiscellaneousGeneralExpensesAbstract
Miscellaneous General Expenses-Electric
335
52
ScheduleDepreciationDepletionAndAmortizationAbstract
Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
336
53
ScheduleRegulatoryCommissionExpensesAbstract
Regulatory Commission Expenses
350
54
ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract
Research, Development and Demonstration Activities
352
55
ScheduleDistributionOfSalariesAndWagesAbstract
Distribution of Salaries and Wages
354
56
ScheduleCommonUtilityPlantAndExpensesAbstract
Common Utility Plant and Expenses
356
57
ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract
Amounts included in ISO/RTO Settlement Statements
397
58
SchedulePurchasesSalesOfAncillaryServicesAbstract
Purchase and Sale of Ancillary Services
398
59
ScheduleMonthlyTransmissionSystemPeakLoadAbstract
Monthly Transmission System Peak Load
400
60
ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract
Monthly ISO/RTO Transmission System Peak Load
400a
NONE
61
ScheduleElectricEnergyAccountAbstract
Electric Energy Account
401a
62
ScheduleMonthlyPeakAndOutputAbstract
Monthly Peaks and Output
401b
63
ScheduleSteamElectricGeneratingPlantStatisticsAbstract
Steam Electric Generating Plant Statistics
402
NONE
64
ScheduleHydroelectricGeneratingPlantStatisticsAbstract
Hydroelectric Generating Plant Statistics
406
NONE
65
SchedulePumpedStorageGeneratingPlantStatisticsAbstract
Pumped Storage Generating Plant Statistics
408
NONE
66
ScheduleGeneratingPlantStatisticsAbstract
Generating Plant Statistics Pages
410
NONE
0
ScheduleEnergyStorageOperationsLargePlantsAbstract
Energy Storage Operations (Large Plants)
414
67
ScheduleTransmissionLineStatisticsAbstract
Transmission Line Statistics Pages
422
68
ScheduleTransmissionLinesAddedAbstract
Transmission Lines Added During Year
424
NONE
69
ScheduleSubstationsAbstract
Substations
426
70
ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract
Transactions with Associated (Affiliated) Companies
429
71
FootnoteDataAbstract
Footnote Data
450
StockholdersReportsAbstract
Stockholders' Reports (check appropriate box)
Stockholders' Reports Check appropriate box:

Two copies will be submitted

No annual report to stockholders is prepared


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept, and address of office where any other corporate books of account are kept, if different from that where the general corporate books are kept.

George Carlin - VP, NY Controller The Official books of record are kept at: One Metrotech Center Niagara Mohawk - A National Grid Company Brooklyn, NY 11201 300 Erie Boulevard West Syracuse, NY 13202

2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation. If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type of organization and the date organized.

New York - Certificate of Consolidation filed January 5, 1950, pursuant to sections 26-a and 86 of the Stock Corporation Law and to Subdivision 4 of Section II of the Transportation Corporation Law of the State of New York.

State of Incorporation:

Date of Incorporation:

Incorporated Under Special Law:

3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased.

Not applicable.

(a) Name of Receiver or Trustee Holding Property of the Respondent:

(b) Date Receiver took Possession of Respondent Property:

(c) Authority by which the Receivership or Trusteeship was created:

(d) Date when possession by receiver or trustee ceased:
4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.

Purchase, transmission, distribution and sale of electricity and purchase, transmission, distribution and sale of natural gas in the State of New York.
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not the principal accountant for your previous year's certified financial statements?
(1)
Yes

(2)
No


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent at the end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If control was in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control was held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiaries for whom trust was maintained, and purpose of the trust.
On March 18, 1999, Niagara Mohawk Power Corporation ("Niagara Mohawk") was reorganized into a holding company structure in accordance with an Agreement and Plan of Exchange between Niagara Mohawk and Niagara Mohawk Holdings, Inc. ("Holdings"). Niagara Mohawk's outstanding common stock was exchanged on a share-for-share basis for Holdings' common stock making Niagara Mohawk a wholly-owned subsidiary of Holdings. Niagara Mohawk's preferred stock and debt were not exchanged as part of the share exchange and continue as obligations of Niagara Mohawk. On January 30, 2002, Holdings was acquired by National Grid USA ("NGUSA") for approximately $3 billion in cash and American Depository shares in exchange for all of Holdings common outstanding shares. NGUSA is a wholly-owned subsidiary of National Grid plc.


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
CORPORATIONS CONTROLLED BY RESPONDENT
  1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
  2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved.
  3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
  1. See the Uniform System of Accounts for a definition of control.
  2. Direct control is that which is exercised without interposition of an intermediary.
  3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
  4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line No.
NameOfCompanyControlledByRespondent
Name of Company Controlled
(a)
CompanyControlledByRespondentKindOfBusinessDescription
Kind of Business
(b)
VotingStockOwnedByRespondentPercentage
Percent Voting Stock Owned
(c)
FootnoteReferences
Footnote Ref.
(d)
1
NM Properties, Inc.
2
1) A real estate subsidiary operating
3
exclusively in the State of New York that owns
4
100% of Land Management and Development, Inc.;
5
Landwest, Inc.; Upper Hudson
6
Development, Inc.; and 65 Willis Lane, Inc.
7
Land Management and Development, Inc. owns
8
controlling interest in Port of the Islands
9
North LLC.


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
OFFICERS
  1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions.
  2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made.
Line No.
OfficerTitle
Title
(a)
OfficerName
Name of Officer
(b)
OfficerSalary
Salary for Year
(c)
DateOfficerIncumbencyStarted
Date Started in Period
(d)
DateOfficerIncumbencyEnded
Date Ended in Period
(e)
1
Chief Finanical Officer
David Doxsee
(a)
70,998
2
Senior Vice President
Jeannette Mills
(b)
77,696
3
Senior Vice President
Ross Turrini
(c)
27,549
4
Senior Vice President
Ronald Macklin
(d)
72,192
5
Vice President, NY Controller
George Carlin
(e)
77,282
6
Appointments
7
----------------------------------------------
8
President
John Bruckner - 5/31/2018
(f)
37,376
9
Senior Vice President
Christopher Kelly - 5/31/2018
(g)
81,853
10
Senior Vice President
David Way - 6/12/2018
(h)
64,881
11
Chief Operating Officer, Electric
Kenneth Daly - 5/31/2018
(i)
141,598
12
Resignations
13
----------------------------------------------
14
Senior Vice President
John Bruckner - 5/31/2018
15
President & Director
Kenneth Daly - 5/31/2018


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: OfficerSalary

Salary disclosure includes amounts that have been allocated to Niagara Mohawk Power Corporation (reporting entity). The salary amount allocated to other companies was $144,354. These salary amounts exclude incentive compensation payments and reflect base salary paid by the Company from 01/01/2018 through 12/31/2018.

(b) Concept: OfficerSalary

Salary disclosure includes amounts that have been allocated to Niagara Mohawk Power Corporation (reporting entity). The salary amount allocated to other companies was $211,675. These salary amounts exclude incentive compensation payments and reflect base salary paid by the Company from 01/01/2018 through 12/31/2018.

(c) Concept: OfficerSalary

Salary disclosure includes amounts that have been allocated to Niagara Mohawk Power Corporation (reporting entity). The salary amount allocated to other companies was $248,496. These salary amounts exclude incentive compensation payments and reflect base salary paid by the Company from 01/01/2018 through 12/31/2018.

(d) Concept: OfficerSalary

Salary disclosure includes amounts that have been allocated to Niagara Mohawk Power Corporation (reporting entity). The salary amount allocated to other companies was $209,149. These salary amounts exclude incentive compensation payments and reflect base salary paid by the Company from 01/01/2018 through 12/31/2018.

(e) Concept: OfficerSalary

Salary disclosure includes amounts that have been allocated to Niagara Mohawk Power Corporation (reporting entity). The salary amount allocated to other companies was $115,657. These salary amounts exclude incentive compensation payments and reflect base salary paid by the Company from 01/01/2018 through 12/31/2018.

(f) Concept: OfficerSalary

Salary disclosure includes amounts that have been allocated to Niagara Mohawk Power Corporation (reporting entity). The salary amount allocated to other companies was $268,483. These salary amounts exclude incentive compensation payments and reflect base salary paid by the Company from 01/01/2018 through 12/31/2018.

(g) Concept: OfficerSalary

Salary disclosure includes amounts that have been allocated to Niagara Mohawk Power Corporation (reporting entity). The salary amount allocated to other companies was $155,953. These salary amounts exclude incentive compensation payments and reflect base salary paid by the Company from 01/01/2018 through 12/31/2018.

(h) Concept: OfficerSalary

Salary disclosure includes amounts that have been allocated to Niagara Mohawk Power Corporation (reporting entity). The salary amount allocated to other companies was $168,237. These salary amounts exclude incentive compensation payments and reflect base salary paid by the Company from 01/01/2018 through 12/31/2018.

(i) Concept: OfficerSalary

Salary disclosure includes amounts that have been allocated to Niagara Mohawk Power Corporation (reporting entity). The salary amount allocated to other companies was $230,246. These salary amounts exclude incentive compensation payments and reflect base salary paid by the Company from 01/01/2018 through 12/31/2018.


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
DIRECTORS
  1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated titles of the directors who are officers of the respondent.
  2. Designate members of the Executive Committee in column (c) and the Chairman of the Executive Committee in column (d).
Line No.
NameAndTitleOfDirector
Name (and Title) of Director
(a)
PrincipalBusinessAddress
Principal Business Address
(b)
MemberOfTheExecutiveCommittee
Member of the Executive Committee
(c)
ChairmanOfTheExecutiveCommittee
Chairman of the Executive Committee
(d)
1
David Doxsee (Chief Financial Officer)
Brooklyn, New York 11201
2
John Bruckner (President)
Melville, New York 11747


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
INFORMATION ON FORMULA RATES
Does the respondent have formula rates?
Yes

No
  1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No) accepting the rate(s) or changes in the accepted rate.
Line No.
RateScheduleTariffNumber
FERC Rate Schedule or Tariff Number
(a)
ProceedingDocketNumber
FERC Proceeding
(b)
1
NYISO FERC Electric Tariff No. 1
Docket No. ER08-552-000 / ER12-1394-000 /
2
ER13-1182-000 / ER14-543-000
3
Attachment H Annual Transmission Revenue
Docket No. ER14-543-000/ER15-1911-000/
4
Requirement
ER97-1523-000/23 and OA97-470-000/021
5
NYISO OATT Western New York Facilities Charge
ER17-1629-000
6
NYISO Rate Schedule 308
ER01-1986-ER02-2495
7
NYISO Ferc Electric Tariff Vol. 1 LGIA No. 1954
ER13-01000-000
8
NYISO Ferc Electric Tariff Vol. 1 LGIA No. 1970
ER13-01077-000
9
NYISO Service Agreement 2076
ER14-1286-000
10
Agrmt no 1757 among NYISO, NMPC, NYSEG
11
and NMP, 1.0.0
ER12-1869-000
12
NYISO Ferc Electric Tariff Vol. 1, Service
13
Agreement 1325
ER11-2499-000
14
NYISO Ferc Electric Tariff Vol. 1, Service
15
Agreement 1407
ER09-905-000
16
NYISO Ferc Electric Tariff Vol. 1, Service
17
Agreement 1483
ER09-1693-000
18
NYISO Ferc Electric Tariff Vol. 1, Service
19
Agreement 1676
ER11-2533-000
20
NYISO Ferc Electric Tariff Vol. 1, Service
21
Agreement 1698
ER11-2946-000
22
NYISO Ferc Electric Tariff Vol. 1, Service
23
Agreement 1530
ER11-3788-000
24
NYISO Ferc Electric Tariff Vol. 1, Service
25
Agreement 1916
ER13-160-000
26
NYISO Ferc Electric Tariff Vol. 1, Second Amended
27
Service Agreement 1168
ER13-300-000
28
NYISO FERC Electric Tariff Vol. 2, Service
29
Agreement 1952
ER13-1390-000
30
NYISO FERC Electric Tariff Vol. 1, Service
31
Agreement 2056
ER14-444
32
NYISO FERC Electric Tariff Vol. 1, Service
33
Agreement 2135
ER14-2506
34
NYISO FERC Electric Tariff Vol. 1, Service
35
Agreement 2076
ER14-1286
36
NYISO FERC Electric Tariff Vol. 1, Service
37
Agreement 2128
ER14-2406
38
NYISO FERC Electric Tariff Vol. 1, Service
39
Agreement 2161
ER15-8-000
40
NYISO FERC Electric Tariff Vol. 1, Service
41
Agreement 2223
ER15-2128
42
NYISO FERC Electric Tariff Vol. 1, Service
43
Agreement 2177
ER15-674
44
NYISO FERC Electric Tariff Vol. 1, Service
45
Agreement 2135
ER15-2152
46
NYISO FERC Electric Tariff Vol. 1, Service
47
Agreement 2204
ER15-971
48
NYISO FERC Electric Tariff Vol. 1, Service
49
Agreement 2211
ER15-1709
50
NYISO FERC Electric Tariff Vol. 1, Service
51
Agreement 2205
ER15-1083
52
NYISO FERC Electric Tariff Vol. 1, Service
53
Agreement 337
ER15-1742
54
NYISO FERC Electric Tariff Vol. 1, Service
55
Agreement 2220
ER15-1835
56
NYISO FERC Electric Tariff Vol. 1, Service
57
Agreement 1160
ER15-2127
58
NYISO FERC Electric Tariff Vol. 1, Service
59
Agreement 2219
ER15-2285
60
NYISO FERC Electric Tariff Vol. 1, Service
61
Agreement 334
ER16-979
62
NYISO FERC Electric Tariff Vol. 1, Service
63
Agreement 2177
ER16-666
64
NYISO FERC Electric Tariff Vol. 1, Service
65
Agreement 2283
ER16-1957
66
NYISO FERC Electric Tariff Vol. 1, Service
67
Agreement 2264
ER16-2625
68
NYISO FERC Electric Tariff Vol. 1, Service
69
Agreement 2260
ER16-925-001
70
NYISO FERC Electric Tariff Vol. 1, Service
71
Agreement 1698
ER16-1664
72
NYISO FERC Electric Tariff Vol. 1, Service
73
Agreement 2293
ER16-2287-001
74
NYISO FERC Electric Tariff Vol. 1, Service
75
Agreement 2334
ER17-1703-000
76
NYISO FERC Electric Tariff Vol. 1, Service
77
Agreement 2341
ER17-1872
78
NYISO FERC Electric Tariff Vol. 1, Service
79
Agreement 2345
ER17-2051
80
NYISO FERC Electric Tariff Vol. 1, Service
81
Agreement 2356
ER17-2334-000
82
NYISO FERC Electric Tariff Vol. 1, Service
83
Agreement 2324
ER17-566
84
NYISO FERC Electric Tariff Vol. 1, Service
85
Agreement 2335
ER17-1545
86
NYISO FERC Electric Tariff Vol. 1, Service
87
Agreement 2386
ER18-279
88
NYISO FERC Electric Tariff Vol. 1, Service
89
Agreement 2347
ER19-253
90
NYISO FERC Electric Tariff Vol. 1, Service
91
Agreement 2416
ER18-1451
92
NYISO FERC Electric Tariff Vol. 1, Service
93
Agreement 2219
ER18-1994


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)?
Yes

No
  1. If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
Line No.
AccessionNumber
Accession No.
(a)
DocumentDate
Document Date / Filed Date
(b)
DocketNumber
Docket No.
(c)
DescriptionOfFiling
Description
(d)
RateScheduleTariffNumber
Formula Rate FERC Rate Schedule Number or Tariff Number
(e)
1
06/14/2018
ER08-552-000
Informational filing of
NYISO FERC Electric Tariff
2
Niagara Mohawk Power
No. 1
3
Corporation of the
4
Annual Update to the
5
Formula Transmission
6
Service Charge under
7
the NYISO OATT
8
10/17/2018
ER19-132-000
Filing to revise
NYISO FERC Electric Tariff
9
Niagara Mohawk
No. 1
10
depreciation rates
11
under the NYISO OATT


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
INFORMATION ON FORMULA RATES - Formula Rate Variances
  1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1.
  2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1.
  3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.
  4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line No.
PageNumberOfFormulaRateVariances
Page No(s).
(a)
ScheduleOfFormulaRateVariances
Schedule
(b)
ColumnOfFormulaRateVariances
Column
(c)
LineNumberOfFormulaRateVariances
Line No.
(d)
1
Not applicable.


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR

Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.

  1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the franchise rights were acquired. If acquired without the payment of consideration, state that fact.
  2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to Commission authorization.
  3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were submitted to the Commission.
  4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give reference to such authorization.
  5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
  6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee.
  7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
  8. State the estimated annual effect and nature of any important wage scale changes during the year.
  9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings culminated during the year.
  10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director, security holder reported on Page 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known associate of any of these persons was a party or in which any such person had a material interest.
  11. (Reserved.)
  12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
  13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period.
  14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.

1. Changes in Franchise Rights:

None

 

2. Information on consolidations, mergers, and reorganizations:

None

 

3. Purchase or sale of an operating unit or system:

None

 

4. Important Leaseholds:

None

 

5. Important extension or reduction of transmission or distribution system:

None

 

6. Issuance of securities or assumption of liabilities or guarantees:

The settlement of the Company’s various transactions with NGUSA and certain affiliates generally occurs via

the intercompany money pool. The Company is a participant in the Regulated Money Pool and can both borrow and lend

funds. Borrowings from the Regulated Money Pool bear interest in accordance with the terms of the intercompany money

pool agreement. As the Company fully participates in the Regulated Money Pool rather than settling intercompany charges

with cash, all changes in the intercompany money pool balance and accounts receivable and payable from affiliate

balances, are reflected as investing or financing activities in the accompanying statements of cash flows. In addition, for

the purpose of presentation in the statement of cash flows, it is assumed all amounts settled through intercompany money

pool are constructive cash receipts and payments, and therefore are presented as such.

 

7. Changes in Articles of Incorporation:

None

 

8. Wage Scale Increase:

Local 97: 2.5% effective April 1, 2018.

Local 97C: 2.0% effective April 1, 2018.

 

9. Status of Legal Proceedings:

Refer to Page 123 - Notes to Financial Statements - Note 13. Commitments and Contingencies

 

10. Additional Material Transactions Not Reported Elsewhere in this Report:

None

 

11. Reserved:

None

 

12. N/A

 

13. Changes in General Officers:

John Bruckner resigned as Senior Vice President and appointed as President and Director effective May 31, 2018.

Kenneth Daly resigned as President and Director and appointed as Chief Operating Officer, Electric effective May 31, 2018.

Christopher Kelly appointed as Senior Vice President effective May 31, 2018.

David Way appointed as Senior Vice President effective June 12, 2018.

 

14. N/A


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
1
UtilityPlantAbstract
UTILITY PLANT
2
UtilityPlant
Utility Plant (101-106, 114)
200
13,857,153,684
13,233,042,192
3
ConstructionWorkInProgress
Construction Work in Progress (107)
200
438,319,836
370,698,538
4
UtilityPlantAndConstructionWorkInProgress
TOTAL Utility Plant (Enter Total of lines 2 and 3)
14,295,473,520
13,603,740,730
5
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)
200
3,964,093,617
3,771,246,116
6
UtilityPlantNet
Net Utility Plant (Enter Total of line 4 less 5)
10,331,379,903
9,832,494,614
7
NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication
Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)
202
8
NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly
Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9
NuclearFuelAssembliesInReactorMajorOnly
Nuclear Fuel Assemblies in Reactor (120.3)
10
SpentNuclearFuelMajorOnly
Spent Nuclear Fuel (120.4)
11
NuclearFuelUnderCapitalLeases
Nuclear Fuel Under Capital Leases (120.6)
12
AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies
(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)
202
13
NuclearFuelNet
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
14
UtilityPlantAndNuclearFuelNet
Net Utility Plant (Enter Total of lines 6 and 13)
10,331,379,903
9,832,494,614
15
OtherElectricPlantAdjustments
Utility Plant Adjustments (116)
16
GasStoredUndergroundNoncurrent
Gas Stored Underground - Noncurrent (117)
17
OtherPropertyAndInvestmentsAbstract
OTHER PROPERTY AND INVESTMENTS
18
NonutilityProperty
Nonutility Property (121)
11,562,002
11,562,002
19
AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty
(Less) Accum. Prov. for Depr. and Amort. (122)
27,785
53,623
20
InvestmentInAssociatedCompanies
Investments in Associated Companies (123)
21
InvestmentInSubsidiaryCompanies
Investment in Subsidiary Companies (123.1)
224
733,807
778,606
23
NoncurrentPortionOfAllowances
Noncurrent Portion of Allowances
228
24
OtherInvestments
Other Investments (124)
6,472,690
5,882,286
25
SinkingFunds
Sinking Funds (125)
26
DepreciationFund
Depreciation Fund (126)
27
AmortizationFundFederal
Amortization Fund - Federal (127)
28
OtherSpecialFunds
Other Special Funds (128)
33,923,410
34,447,353
29
SpecialFunds
Special Funds (Non Major Only) (129)
30
DerivativeInstrumentAssetsLongTerm
Long-Term Portion of Derivative Assets (175)
16,332,122
855,619
31
DerivativeInstrumentAssetsHedgesLongTerm
Long-Term Portion of Derivative Assets - Hedges (176)
32
OtherPropertyAndInvestments
TOTAL Other Property and Investments (Lines 18-21 and 23-31)
68,996,246
53,472,243
33
CurrentAndAccruedAssetsAbstract
CURRENT AND ACCRUED ASSETS
34
CashAndWorkingFunds
Cash and Working Funds (Non-major Only) (130)
35
Cash
Cash (131)
7,367,468
1,081,689
36
SpecialDeposits
Special Deposits (132-134)
2,733,610
20,515,417
37
WorkingFunds
Working Fund (135)
38
TemporaryCashInvestments
Temporary Cash Investments (136)
39
NotesReceivable
Notes Receivable (141)
40
CustomerAccountsReceivable
Customer Accounts Receivable (142)
479,302,227
462,947,677
41
OtherAccountsReceivable
Other Accounts Receivable (143)
55,756,400
65,398,251
42
AccumulatedProvisionForUncollectibleAccountsCredit
(Less) Accum. Prov. for Uncollectible Acct.-Credit (144)
148,775,435
148,613,954
43
NotesReceivableFromAssociatedCompanies
Notes Receivable from Associated Companies (145)
600,501,047
182,917,175
44
AccountsReceivableFromAssociatedCompanies
Accounts Receivable from Assoc. Companies (146)
11,643,673
72,469,078
45
FuelStock
Fuel Stock (151)
227
46
FuelStockExpensesUndistributed
Fuel Stock Expenses Undistributed (152)
227
47
Residuals
Residuals (Elec) and Extracted Products (153)
227
48
PlantMaterialsAndOperatingSupplies
Plant Materials and Operating Supplies (154)
227
45,016,786
47,053,177
49
Merchandise
Merchandise (155)
227
50
OtherMaterialsAndSupplies
Other Materials and Supplies (156)
227
51
NuclearMaterialsHeldForSale
Nuclear Materials Held for Sale (157)
202/227
52
AllowanceInventoryAndWithheld
Allowances (158.1 and 158.2)
228
51,506
53
NoncurrentPortionOfAllowances
(Less) Noncurrent Portion of Allowances
228
54
StoresExpenseUndistributed
Stores Expense Undistributed (163)
227
55
GasStoredCurrent
Gas Stored Underground - Current (164.1)
35,365,060
26,965,736
56
LiquefiedNaturalGasStoredAndHeldForProcessing
Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57
Prepayments
Prepayments (165)
36,953,969
45,836,349
58
AdvancesForGas
Advances for Gas (166-167)
59
InterestAndDividendsReceivable
Interest and Dividends Receivable (171)
60
RentsReceivable
Rents Receivable (172)
12,782,749
7,033,617
61
AccruedUtilityRevenues
Accrued Utility Revenues (173)
131,832,567
144,367,294
62
MiscellaneousCurrentAndAccruedAssets
Miscellaneous Current and Accrued Assets (174)
29,411,231
6,767,364
63
DerivativeInstrumentAssets
Derivative Instrument Assets (175)
64
DerivativeInstrumentAssetsLongTerm
(Less) Long-Term Portion of Derivative Instrument Assets (175)
16,332,122
855,619
65
DerivativeInstrumentAssetsHedges
Derivative Instrument Assets - Hedges (176)
14,522,018
7,118,732
66
DerivativeInstrumentAssetsHedgesLongTerm
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67
CurrentAndAccruedAssets
Total Current and Accrued Assets (Lines 34 through 66)
1,314,464,876
941,857,602
68
DeferredDebitsAbstract
DEFERRED DEBITS
69
UnamortizedDebtExpense
Unamortized Debt Expenses (181)
19,547,486
17,453,503
70
ExtraordinaryPropertyLosses
Extraordinary Property Losses (182.1)
230a
71
UnrecoveredPlantAndRegulatoryStudyCosts
Unrecovered Plant and Regulatory Study Costs (182.2)
230b
3,461,250
72
OtherRegulatoryAssets
Other Regulatory Assets (182.3)
232
554,749,053
1,150,654,773
73
PreliminarySurveyAndInvestigationCharges
Prelim. Survey and Investigation Charges (Electric) (183)
25,589,460
24,659,470
74
PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges
Preliminary Natural Gas Survey and Investigation Charges 183.1)
75
OtherPreliminarySurveyAndInvestigationCharges
Other Preliminary Survey and Investigation Charges (183.2)
76
ClearingAccounts
Clearing Accounts (184)
124,558
104,919
77
TemporaryFacilities
Temporary Facilities (185)
78
MiscellaneousDeferredDebits
Miscellaneous Deferred Debits (186)
233
373,261,283
339,690,537
79
DeferredLossesFromDispositionOfUtilityPlant
Def. Losses from Disposition of Utility Plt. (187)
80
ResearchDevelopmentAndDemonstrationExpenditures
Research, Devel. and Demonstration Expend. (188)
352
81
UnamortizedLossOnReacquiredDebt
Unamortized Loss on Reaquired Debt (189)
8,128,349
9,653,989
82
AccumulatedDeferredIncomeTaxes
Accumulated Deferred Income Taxes (190)
234
736,311,601
741,319,453
83
UnrecoveredPurchasedGasCosts
Unrecovered Purchased Gas Costs (191)
84
DeferredDebits
Total Deferred Debits (lines 69 through 83)
1,720,923,924
2,283,326,806
85
AssetsAndOtherDebits
TOTAL ASSETS (lines 14-16, 32, 67, and 84)
13,435,764,949
13,111,151,265


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line No.
Title of Account
(a)
Ref. Page No.
(b)
Current Year End of Quarter/Year Balance
(c)
Prior Year End Balance 12/31
(d)
1
ProprietaryCapitalAbstract
PROPRIETARY CAPITAL
2
CommonStockIssued
Common Stock Issued (201)
250
187,364,863
187,364,863
3
PreferredStockIssued
Preferred Stock Issued (204)
250
28,984,701
28,984,701
4
CapitalStockSubscribed
Capital Stock Subscribed (202, 205)
5
StockLiabilityForConversion
Stock Liability for Conversion (203, 206)
6
PremiumOnCapitalStock
Premium on Capital Stock (207)
7
OtherPaidInCapital
Other Paid-In Capital (208-211)
253
3,099,495,838
3,062,617,385
8
InstallmentsReceivedOnCapitalStock
Installments Received on Capital Stock (212)
252
9
DiscountOnCapitalStock
(Less) Discount on Capital Stock (213)
254
10
CapitalStockExpense
(Less) Capital Stock Expense (214)
254b
11
RetainedEarnings
Retained Earnings (215, 215.1, 216)
118
1,386,230,139
1,188,971,762
12
UnappropriatedUndistributedSubsidiaryEarnings
Unappropriated Undistributed Subsidiary Earnings (216.1)
118
2,746,968
2,736,209
13
ReacquiredCapitalStock
(Less) Reaquired Capital Stock (217)
250
14
NoncorporateProprietorship
Noncorporate Proprietorship (Non-major only) (218)
15
AccumulatedOtherComprehensiveIncome
Accumulated Other Comprehensive Income (219)
122(a)(b)
34,293
2,441,133
16
ProprietaryCapital
Total Proprietary Capital (lines 2 through 15)
4,699,362,866
4,467,643,635
17
LongTermDebtAbstract
LONG-TERM DEBT
18
Bonds
Bonds (221)
256
3,274,165,000
2,465,705,000
19
ReacquiredBonds
(Less) Reaquired Bonds (222)
256
20
AdvancesFromAssociatedCompanies
Advances from Associated Companies (223)
256
21
OtherLongTermDebt
Other Long-Term Debt (224)
256
313,760,000
22
UnamortizedPremiumOnLongTermDebt
Unamortized Premium on Long-Term Debt (225)
23
UnamortizedDiscountOnLongTermDebtDebit
(Less) Unamortized Discount on Long-Term Debt-Debit (226)
10,982
6,716
24
LongTermDebt
Total Long-Term Debt (lines 18 through 23)
3,274,154,018
2,779,458,284
25
OtherNoncurrentLiabilitiesAbstract
OTHER NONCURRENT LIABILITIES
26
ObligationsUnderCapitalLeaseNoncurrent
Obligations Under Capital Leases - Noncurrent (227)
27
AccumulatedProvisionForPropertyInsurance
Accumulated Provision for Property Insurance (228.1)
28
AccumulatedProvisionForInjuriesAndDamages
Accumulated Provision for Injuries and Damages (228.2)
25,178,765
25,554,080
29
AccumulatedProvisionForPensionsAndBenefits
Accumulated Provision for Pensions and Benefits (228.3)
272,246,591
359,077,929
30
AccumulatedMiscellaneousOperatingProvisions
Accumulated Miscellaneous Operating Provisions (228.4)
339,789,898
359,631,704
31
AccumulatedProvisionForRateRefunds
Accumulated Provision for Rate Refunds (229)
32
LongTermPortionOfDerivativeInstrumentLiabilities
Long-Term Portion of Derivative Instrument Liabilities
1,131,038
11,913,778
33
LongTermPortionOfDerivativeInstrumentLiabilitiesHedges
Long-Term Portion of Derivative Instrument Liabilities - Hedges
34
AssetRetirementObligations
Asset Retirement Obligations (230)
14,533,068
15,437,087
35
OtherNoncurrentLiabilities
Total Other Noncurrent Liabilities (lines 26 through 34)
652,879,360
771,614,578
36
CurrentAndAccruedLiabilitiesAbstract
CURRENT AND ACCRUED LIABILITIES
37
NotesPayable
Notes Payable (231)
38
AccountsPayable
Accounts Payable (232)
227,168,684
175,251,699
39
NotesPayableToAssociatedCompanies
Notes Payable to Associated Companies (233)
40
AccountsPayableToAssociatedCompanies
Accounts Payable to Associated Companies (234)
124,590,032
168,963,574
41
CustomerDeposits
Customer Deposits (235)
30,695,721
32,184,023
42
TaxesAccrued
Taxes Accrued (236)
262
71,122,143
121,385,382
43
InterestAccrued
Interest Accrued (237)
30,833,981
26,708,077
44
DividendsDeclared
Dividends Declared (238)
45
MaturedLongTermDebt
Matured Long-Term Debt (239)
46
MaturedInterest
Matured Interest (240)
47
TaxCollectionsPayable
Tax Collections Payable (241)
1,273,992
48
MiscellaneousCurrentAndAccruedLiabilities
Miscellaneous Current and Accrued Liabilities (242)
241,861,035
184,163,770
49
ObligationsUnderCapitalLeasesCurrent
Obligations Under Capital Leases-Current (243)
50
DerivativesInstrumentLiabilities
Derivative Instrument Liabilities (244)
5,552,387
14,526,710
51
LongTermPortionOfDerivativeInstrumentLiabilities
(Less) Long-Term Portion of Derivative Instrument Liabilities
1,131,038
11,913,778
52
DerivativeInstrumentLiabilitiesHedges
Derivative Instrument Liabilities - Hedges (245)
2,026,656
1,954,832
53
LongTermPortionOfDerivativeInstrumentLiabilitiesHedges
(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54
CurrentAndAccruedLiabilities
Total Current and Accrued Liabilities (lines 37 through 53)
732,576,647
725,138,067
55
DeferredCreditsAbstract
DEFERRED CREDITS
56
CustomerAdvancesForConstruction
Customer Advances for Construction (252)
3,839,233
4,961,398
57
AccumulatedDeferredInvestmentTaxCredits
Accumulated Deferred Investment Tax Credits (255)
266
13,518,460
14,346,995
58
DeferredGainsFromDispositionOfUtilityPlant
Deferred Gains from Disposition of Utility Plant (256)
59
OtherDeferredCredits
Other Deferred Credits (253)
269
244,992,205
224,733,072
60
OtherRegulatoryLiabilities
Other Regulatory Liabilities (254)
278
1,972,760,825
2,299,569,151
61
UnamortizedGainOnReacquiredDebt
Unamortized Gain on Reaquired Debt (257)
62
AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty
Accum. Deferred Income Taxes-Accel. Amort.(281)
272
63
AccumulatedDeferredIncomeTaxesOtherProperty
Accum. Deferred Income Taxes-Other Property (282)
1,684,099,162
1,629,931,217
64
AccumulatedDeferredIncomeTaxesOther
Accum. Deferred Income Taxes-Other (283)
157,582,173
193,754,868
65
DeferredCredits
Total Deferred Credits (lines 56 through 64)
4,076,792,058
4,367,296,701
66
LiabilitiesAndOtherCredits
TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)
13,435,764,949
13,111,151,265


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
STATEMENT OF INCOME

Quarterly

  1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
  2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.
  3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k) the quarter to date amounts for other utility function for the current year quarter.
  4. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter.
  5. If additional columns are needed, place them in a footnote.

Annual or Quarterly if applicable

  1. Do not report fourth quarter data in columns (e) and (f)
  2. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
  3. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
  4. Use page 122 for important notes regarding the statement of income for any account thereof.
  5. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
  6. Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income, and expense accounts.
  7. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
  8. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
  9. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
  10. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Line No.
Title of Account
(a)
(Ref.) Page No.
(b)
Total Current Year to Date Balance for Quarter/Year
(c)
Total Prior Year to Date Balance for Quarter/Year
(d)
Current 3 Months Ended - Quarterly Only - No 4th Quarter
(e)
Prior 3 Months Ended - Quarterly Only - No 4th Quarter
(f)
Electric Utility Current Year to Date (in dollars)
(g)
Electric Utility Previous Year to Date (in dollars)
(h)
Gas Utiity Current Year to Date (in dollars)
(i)
Gas Utility Previous Year to Date (in dollars)
(j)
Other Utility Current Year to Date (in dollars)
(k)
Other Utility Previous Year to Date (in dollars)
(l)
1
UtilityOperatingIncomeAbstract
UTILITY OPERATING INCOME
2
OperatingRevenues
Operating Revenues (400)
300
3,227,348,951
3,004,236,020
2,601,981,039
2,446,693,772
623,143,301
557,449,458
2,224,611
92,790
3
OperatingExpensesAbstract
Operating Expenses
4
OperationExpense
Operation Expenses (401)
320
1,917,531,633
1,709,742,231
1,514,398,831
1,370,294,748
403,132,802
339,447,483
5
MaintenanceExpense
Maintenance Expenses (402)
320
302,266,487
246,921,687
272,687,524
220,190,899
29,578,963
26,730,788
6
DepreciationExpense
Depreciation Expense (403)
336
281,723,486
259,698,083
229,639,100
209,689,197
52,084,386
50,008,886
7
DepreciationExpenseForAssetRetirementCosts
Depreciation Expense for Asset Retirement Costs (403.1)
336
8
AmortizationAndDepletionOfUtilityPlant
Amort. & Depl. of Utility Plant (404-405)
336
1,366,556
1,177,786
1,304,094
1,130,866
62,462
46,920
9
AmortizationOfElectricPlantAcquisitionAdjustments
Amort. of Utility Plant Acq. Adj. (406)
336
10
AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11
AmortizationOfConversionExpenses
Amort. of Conversion Expenses (407.2)
1,153,750
1,153,750
12
RegulatoryDebits
Regulatory Debits (407.3)
30,919,339
2,255,806
32,863,449
35,887
1,944,110
2,219,919
13
RegulatoryCredits
(Less) Regulatory Credits (407.4)
4,650,000
11,465,839
4,650,000
11,362,606
103,233
14
TaxesOtherThanIncomeTaxesUtilityOperatingIncome
Taxes Other Than Income Taxes (408.1)
262
286,281,176
270,877,270
228,499,659
218,049,708
57,781,517
52,827,562
15
IncomeTaxesOperatingIncome
Income Taxes - Federal (409.1)
262
42,480,745
114,486,458
28,851,151
99,829,773
13,629,594
14,656,685
16
IncomeTaxesUtilityOperatingIncomeOther
Income Taxes - Other (409.1)
262
12,105,885
24,534,453
8,595,750
21,416,476
3,510,135
3,117,977
17
ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome
Provision for Deferred Income Taxes (410.1)
234, 272
11,865,151
11,602,931
14,999,272
14,981,325
3,134,121
3,378,394
18
ProvisionForDeferredIncomeTaxesCreditOperatingIncome
(Less) Provision for Deferred Income Taxes-Cr. (411.1)
234, 272
19
InvestmentTaxCreditAdjustments
Investment Tax Credit Adj. - Net (411.4)
266
20
GainsFromDispositionOfPlant
(Less) Gains from Disp. of Utility Plant (411.6)
290,785
290,785
21
LossesFromDispositionOfServiceCompanyPlant
Losses from Disp. of Utility Plant (411.7)
305
39,277
305
39,277
22
GainsFromDispositionOfAllowances
(Less) Gains from Disposition of Allowances (411.8)
23
LossesFromDispositionOfAllowances
Losses from Disposition of Allowances (411.9)
24
AccretionExpense
Accretion Expense (411.10)
25
UtilityOperatingExpenses
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)
2,883,043,903
2,606,373,496
2,328,342,275
2,114,002,838
554,701,628
492,370,658
27
NetUtilityOperatingIncome
Net Util Oper Inc (Enter Tot line 2 less 25)
344,305,048
397,862,524
273,638,764
332,690,934
68,441,673
65,078,800
2,224,611
92,790
28
OtherIncomeAndDeductionsAbstract
Other Income and Deductions
29
OtherIncomeAbstract
Other Income
30
NonutilityOperatingIncomeAbstract
Nonutilty Operating Income
31
RevenuesFromMerchandisingJobbingAndContractWork
Revenues From Merchandising, Jobbing and Contract Work (415)
32
CostsAndExpensesOfMerchandisingJobbingAndContractWork
(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
33
RevenuesFromNonutilityOperations
Revenues From Nonutility Operations (417)
34
ExpensesOfNonutilityOperations
(Less) Expenses of Nonutility Operations (417.1)
5,920,012
7,711,592
35
NonoperatingRentalIncome
Nonoperating Rental Income (418)
23,187
43,437
36
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings of Subsidiary Companies (418.1)
119
10,759
89,247
37
InterestAndDividendIncome
Interest and Dividend Income (419)
8,007,020
22,165,637
38
AllowanceForOtherFundsUsedDuringConstruction
Allowance for Other Funds Used During Construction (419.1)
13,602,040
11,831,665
39
MiscellaneousNonoperatingIncome
Miscellaneous Nonoperating Income (421)
1,332,383
2,093,486
40
GainOnDispositionOfProperty
Gain on Disposition of Property (421.1)
41
OtherIncome
TOTAL Other Income (Enter Total of lines 31 thru 40)
17,033,859
28,333,386
42
OtherIncomeDeductionsAbstract
Other Income Deductions
43
LossOnDispositionOfProperty
Loss on Disposition of Property (421.2)
3,501
44
MiscellaneousAmortization
Miscellaneous Amortization (425)
45
Donations
Donations (426.1)
2,496,367
2,417,420
46
LifeInsurance
Life Insurance (426.2)
129,923
1,448,011
47
Penalties
Penalties (426.3)
43,715
124,484
48
ExpendituresForCertainCivicPoliticalAndRelatedActivities
Exp. for Certain Civic, Political & Related Activities (426.4)
570,347
285,487
49
OtherDeductions
Other Deductions (426.5)
7,878,837
2,242,672
50
OtherIncomeDeductions
TOTAL Other Income Deductions (Total of lines 43 thru 49)
11,119,189
2,036,231
51
TaxesApplicableToOtherIncomeAndDeductionsAbstract
Taxes Applic. to Other Income and Deductions
52
TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions
Taxes Other Than Income Taxes (408.2)
262
558,425
556,312
53
IncomeTaxesFederal
Income Taxes-Federal (409.2)
262
2,072,570
3,794,185
54
IncomeTaxesOther
Income Taxes-Other (409.2)
262
515,799
874,970
55
ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions
Provision for Deferred Inc. Taxes (410.2)
234, 272
1,169,520
56
ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions
(Less) Provision for Deferred Income Taxes-Cr. (411.2)
234, 272
57
InvestmentTaxCreditAdjustmentsNonutilityOperations
Investment Tax Credit Adj.-Net (411.5)
58
InvestmentTaxCredits
(Less) Investment Tax Credits (420)
828,536
1,788,219
59
TaxesOnOtherIncomeAndDeductions
TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)
4,028,000
3,437,248
60
NetOtherIncomeAndDeductions
Net Other Income and Deductions (Total of lines 41, 50, 59)
9,942,670
22,859,907
61
InterestChargesAbstract
Interest Charges
62
InterestOnLongTermDebt
Interest on Long-Term Debt (427)
115,084,668
107,692,297
63
AmortizationOfDebtDiscountAndExpense
Amort. of Debt Disc. and Expense (428)
2,766,118
3,021,923
64
AmortizationOfLossOnReacquiredDebt
Amortization of Loss on Reaquired Debt (428.1)
1,422,427
1,422,427
65
AmortizationOfPremiumOnDebtCredit
(Less) Amort. of Premium on Debt-Credit (429)
66
AmortizationOfGainOnReacquiredDebtCredit
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67
InterestOnDebtToAssociatedCompanies
Interest on Debt to Assoc. Companies (430)
68
OtherInterestExpense
Other Interest Expense (431)
41,821,891
56,478,867
69
AllowanceForBorrowedFundsUsedDuringConstructionCredit
(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
5,155,501
3,866,455
70
NetInterestCharges
Net Interest Charges (Total of lines 62 thru 69)
155,939,603
164,749,059
71
IncomeBeforeExtraordinaryItems
Income Before Extraordinary Items (Total of lines 27, 60 and 70)
198,308,115
255,973,372
72
ExtraordinaryItemsAbstract
Extraordinary Items
73
ExtraordinaryIncome
Extraordinary Income (434)
74
ExtraordinaryDeductions
(Less) Extraordinary Deductions (435)
75
NetExtraordinaryItems
Net Extraordinary Items (Total of line 73 less line 74)
76
IncomeTaxesExtraordinaryItems
Income Taxes-Federal and Other (409.3)
262
77
ExtraordinaryItemsAfterTaxes
Extraordinary Items After Taxes (line 75 less line 76)
78
NetIncomeLoss
Net Income (Total of line 71 and 77)
198,308,115
255,973,372


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report


End of:
2018
/
Q4
STATEMENT OF RETAINED EARNINGS
  1. Do not report Lines 49-53 on the quarterly report.
  2. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year.
  3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436-439 inclusive). Show the contra primary account affected in column (b).
  4. State the purpose and amount for each reservation or appropriation of retained earnings.
  5. List first Account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow by credit, then debit items, in that order.
  6. Show dividends for each class and series of capital stock.
  7. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings.
  8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
  9. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122-123.
Line No.
Item
(a)
Contra Primary Account Affected
(b)
Current Quarter/Year Year to Date Balance
(c)
Previous Quarter/Year Year to Date Balance
(d)
UnappropriatedRetainedEarningsAbstract
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1
UnappropriatedRetainedEarnings
Balance-Beginning of Period
1,188,971,762
1,483,969,640
2
ChangesAbstract
Changes
3
AdjustmentsToRetainedEarningsAbstract
Adjustments to Retained Earnings (Account 439)
4
AdjustmentsToRetainedEarningsCreditAbstract
Adjustments to Retained Earnings Credit
4.1
AdjustmentsToRetainedEarningsCredit
4.2
AdjustmentsToRetainedEarningsCredit
4.3
AdjustmentsToRetainedEarningsCredit
4.4
AdjustmentsToRetainedEarningsCredit
4.5
AdjustmentsToRetainedEarningsCredit
4.6
AdjustmentsToRetainedEarningsCredit
4.7
AdjustmentsToRetainedEarningsCredit
4.8
AdjustmentsToRetainedEarningsCredit
4.9
AdjustmentsToRetainedEarningsCredit
4.10
AdjustmentsToRetainedEarningsCredit
9
AdjustmentsToRetainedEarningsCredit
TOTAL Credits to Retained Earnings (Acct. 439)
10
AdjustmentsToRetainedEarningsDebitAbstract
Adjustments to Retained Earnings Debit
10.1
AdjustmentsToRetainedEarningsDebit
10.2
AdjustmentsToRetainedEarningsDebit
10.3
AdjustmentsToRetainedEarningsDebit
10.4
AdjustmentsToRetainedEarningsDebit
10.5
AdjustmentsToRetainedEarningsDebit
10.6
AdjustmentsToRetainedEarningsDebit
10.7
AdjustmentsToRetainedEarningsDebit
10.8
AdjustmentsToRetainedEarningsDebit
10.9
AdjustmentsToRetainedEarningsDebit
10.10
AdjustmentsToRetainedEarningsDebit
15
AdjustmentsToRetainedEarningsDebit
TOTAL Debits to Retained Earnings (Acct. 439)
16
BalanceTransferredFromIncome
Balance Transferred from Income (Account 433 less Account 418.1)
198,318,874
256,062,619
17
AppropriationsOfRetainedEarningsAbstract
Appropriations of Retained Earnings (Acct. 436)
17.1
AppropriationsOfRetainedEarnings
17.2
AppropriationsOfRetainedEarnings
17.3
AppropriationsOfRetainedEarnings
17.4
AppropriationsOfRetainedEarnings
22
AppropriationsOfRetainedEarnings
TOTAL Appropriations of Retained Earnings (Acct. 436)
23
DividendsDeclaredPreferredStockAbstract
Dividends Declared-Preferred Stock (Account 437)
23.1
DividendsDeclaredPreferredStock
Dividends Declared-Preferred Stock
1,060,497
1,060,497
23.2
DividendsDeclaredPreferredStock
23.3
DividendsDeclaredPreferredStock
23.4
DividendsDeclaredPreferredStock
23.5
DividendsDeclaredPreferredStock
29
DividendsDeclaredPreferredStock
TOTAL Dividends Declared-Preferred Stock (Acct. 437)
1,060,497
1,060,497
30
DividendsDeclaredCommonStockAbstract
Dividends Declared-Common Stock (Account 438)
30.1
DividendsDeclaredCommonStock
Dividends Declared-Common Stock (Account 438)
550,000,000
30.2
DividendsDeclaredCommonStock
30.3
DividendsDeclaredCommonStock
30.4
DividendsDeclaredCommonStock
30.5
DividendsDeclaredCommonStock
36
DividendsDeclaredCommonStock
TOTAL Dividends Declared-Common Stock (Acct. 438)
550,000,000
37
TransfersFromUnappropriatedUndistributedSubsidiaryEarnings
Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38
UnappropriatedRetainedEarnings
Balance - End of Period (Total 1,9,15,16,22,29,36,37)
1,386,230,139
1,188,971,762
AppropriatedRetainedEarningsAbstract
APPROPRIATED RETAINED EARNINGS (Account 215)
.1
AppropriatedRetainedEarnings
.2
AppropriatedRetainedEarnings
.3
AppropriatedRetainedEarnings
.4
AppropriatedRetainedEarnings
.5
AppropriatedRetainedEarnings
.6
AppropriatedRetainedEarnings
.7
AppropriatedRetainedEarnings
.8
AppropriatedRetainedEarnings
.9
AppropriatedRetainedEarnings
.10
AppropriatedRetainedEarnings
.11
AppropriatedRetainedEarnings
.12
AppropriatedRetainedEarnings
.13
AppropriatedRetainedEarnings
.14
AppropriatedRetainedEarnings
45
AppropriatedRetainedEarnings
TOTAL Appropriated Retained Earnings (Account 215)
AppropriatedRetainedEarningsAmortizationReserveFederalAbstract
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46
AppropriatedRetainedEarningsAmortizationReserveFederal
TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47
AppropriatedRetainedEarningsIncludingReserveAmortization
TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48
RetainedEarnings
TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
1,386,230,139
1,188,971,762
UnappropriatedUndistributedSubsidiaryEarningsAbstract
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49
UnappropriatedUndistributedSubsidiaryEarnings
Balance-Beginning of Year (Debit or Credit)
2,736,209
2,646,962
50
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings for Year (Credit) (Account 418.1)
10,759
89,247
51
DividendsReceived
(Less) Dividends Received (Debit)
52
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
52.1
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
53
UnappropriatedUndistributedSubsidiaryEarnings
Balance-End of Year (Total lines 49 thru 52)
2,746,968
2,736,209


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
STATEMENT OF CASH FLOWS
  1. Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc.
  2. Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
  3. Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
  4. Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.
Line No.
Description (See Instructions No.1 for explanation of codes)
(a)
Current Year to Date Quarter/Year
(b)
Previous Year to Date Quarter/Year
(c)
1
NetCashFlowFromOperatingActivitiesAbstract
Net Cash Flow from Operating Activities
2
NetIncomeLoss
Net Income (Line 78(c) on page 117)
198,308,115
255,973,372
3
NoncashChargesCreditsToIncomeAbstract
Noncash Charges (Credits) to Income:
4
DepreciationAndDepletion
Depreciation and Depletion
283,090,042
260,875,869
5
NoncashAdjustmentsToCashFlowsFromOperatingActivities
Amortization of (Specify) (footnote details)
5.1
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Amortization of Debt Discount and Expense
2,766,118
3,021,923
5.2
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Amortization of Loss on Reacquired Debt
1,422,427
1,422,427
5.3
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Amortization of Regulatory Debits and Credits, Net
26,269,339
9,210,033
8
DeferredIncomeTaxesNet
Deferred Income Taxes (Net)
10,695,631
11,602,931
9
InvestmentTaxCreditAdjustmentsNet
Investment Tax Credit Adjustment (Net)
828,535
1,788,219
10
NetIncreaseDecreaseInReceivablesOperatingActivities
Net (Increase) Decrease in Receivables
(a)
234,377
(r)
52,314,616
11
NetIncreaseDecreaseInInventoryOperatingActivities
Net (Increase) Decrease in Inventory
(b)
6,362,933
(s)
7,732,444
12
NetIncreaseDecreaseInAllowancesInventoryOperatingActivities
Net (Increase) Decrease in Allowances Inventory
(c)
51,506
13
NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
95,885,669
156,014,865
14
NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Net (Increase) Decrease in Other Regulatory Assets
(d)
242,331,199
(t)
121,793,421
15
NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities
Net Increase (Decrease) in Other Regulatory Liabilities
160,467,477
319,259,339
16
AllowanceForOtherFundsUsedDuringConstructionOperatingActivities
(Less) Allowance for Other Funds Used During Construction
13,602,040
11,831,665
17
UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities
(Less) Undistributed Earnings from Subsidiary Companies
10,759
89,247
18
OtherAdjustmentsToCashFlowsFromOperatingActivities
Other (provide details in footnote):
18.1
OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Other (provide details in footnote):
(e)
30,734,623
(u)
64,309,002
22
NetCashFlowFromOperatingActivities
Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)
648,966,562
716,074,711
24
CashFlowsFromInvestmentActivitiesAbstract
Cash Flows from Investment Activities:
25
ConstructionAndAcquisitionOfPlantIncludingLandAbstract
Construction and Acquisition of Plant (including land):
26
GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Gross Additions to Utility Plant (less nuclear fuel)
(f)
709,369,498
(v)
577,694,274
27
GrossAdditionsToNuclearFuelInvestingActivities
Gross Additions to Nuclear Fuel
28
GrossAdditionsToCommonUtilityPlantInvestingActivities
Gross Additions to Common Utility Plant
(g)
8,083,200
(w)
8,754,982
29
GrossAdditionsToNonutilityPlantInvestingActivities
Gross Additions to Nonutility Plant
30
AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
(Less) Allowance for Other Funds Used During Construction
(h)
13,602,040
(x)
11,831,665
31
OtherConstructionAndAcquisitionOfPlantInvestmentActivities
Other (provide details in footnote):
31.1
OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription
Other (provide details in footnote):
(i)(j)
1,796,127
(y)
846,926
31.2
OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription
Cost of Removal
(k)
44,025,032
53,942,988
34
CashOutflowsForPlant
Cash Outflows for Plant (Total of lines 26 thru 33)
(l)
749,671,817
(z)
629,407,505
36
AcquisitionOfOtherNoncurrentAssets
Acquisition of Other Noncurrent Assets (d)
37
ProceedsFromDisposalOfNoncurrentAssets
Proceeds from Disposal of Noncurrent Assets (d)
39
InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Investments in and Advances to Assoc. and Subsidiary Companies
40
ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies
Contributions and Advances from Assoc. and Subsidiary Companies
41
DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract
Disposition of Investments in (and Advances to)
42
DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44
PurchaseOfInvestmentSecurities
Purchase of Investment Securities (a)
45
ProceedsFromSalesOfInvestmentSecurities
Proceeds from Sales of Investment Securities (a)
46
LoansMadeOrPurchased
Loans Made or Purchased
47
CollectionsOnLoans
Collections on Loans
49
NetIncreaseDecreaseInReceivablesInvestingActivities
Net (Increase) Decrease in Receivables
50
NetIncreaseDecreaseInInventoryInvestingActivities
Net (Increase) Decrease in Inventory
51
NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities
Net (Increase) Decrease in Allowances Held for Speculation
52
NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
53
OtherAdjustmentsToCashFlowsFromInvestmentActivities
Other (provide details in footnote):
53.1
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Other (provide details in footnote):
(m)
3,298,267
(aa)
2,466,448
53.2
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Affiliate Moneypool Lending and Receivables/Payables, Net
401,132,009
438,236,861
57
CashFlowsProvidedFromUsedInInvestmentActivities
Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)
1,154,102,093
193,637,092
59
CashFlowsFromFinancingActivitiesAbstract
Cash Flows from Financing Activities:
60
ProceedsFromIssuanceAbstract
Proceeds from Issuance of:
61
ProceedsFromIssuanceOfLongTermDebtFinancingActivities
Long-Term Debt (b)
500,000,000
62
ProceedsFromIssuanceOfPreferredStockFinancingActivities
Preferred Stock
63
ProceedsFromIssuanceOfCommonStockFinancingActivities
Common Stock
64
OtherAdjustmentsToCashFlowsFromFinancingActivities
Other (provide details in footnote):
66
NetIncreaseInShortTermDebt
Net Increase in Short-Term Debt (c)
67
OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Other (provide details in footnote):
70
CashProvidedByOutsideSources
Cash Provided by Outside Sources (Total 61 thru 69)
500,000,000
72
PaymentsForRetirementAbstract
Payments for Retirement of:
73
PaymentsForRetirementOfLongTermDebtFinancingActivities
Long-term Debt (b)
(n)
5,300,000
74
PaymentsForRetirementOfPreferredStockFinancingActivities
Preferred Stock
75
PaymentsForRetirementOfCommonStockFinancingActivities
Common Stock
76
OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Other (provide details in footnote):
76.1
DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities
Other (provide details in footnote):
(ab)(ac)
32,719,935
78
NetDecreaseInShortTermDebt
Net Decrease in Short-Term Debt (c)
80
DividendsOnPreferredStock
Dividends on Preferred Stock
(o)
1,060,497
1,060,497
81
DividendsOnCommonStock
Dividends on Common Stock
550,000,000
83
CashFlowsProvidedFromUsedInFinancingActivities
Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)
493,639,503
518,340,562
85
NetIncreaseDecreaseInCashAndCashEquivalentsAbstract
Net Increase (Decrease) in Cash and Cash Equivalents
86
NetIncreaseDecreaseInCashAndCashEquivalents
Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)
11,496,028
4,097,057
88
CashAndCashEquivalents
Cash and Cash Equivalents at Beginning of Period
(p)
21,597,106
17,500,049
90
CashAndCashEquivalents
Cash and Cash Equivalents at End of Period
(q)
10,101,078
(ad)
21,597,106


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: 234377
(b) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: -6362933
(c) Concept: NetIncreaseDecreaseInAllowancesInventoryOperatingActivities
Original value: -51506
(d) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: 242331199
(e) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

 

 

2018

Operating Activities - Other

 

Change in Derivative Instrument Assets

(22,879,789)

Change in Prepayments

8,882,380

Change in Miscellaneous Current and Accrued Assets

(22,643,867)

Change in Unamortized Debt Expense

(4,860,101)

Change in Unrecovered Plant and Regulatory Study Costs

(3,461,250)

Change in Preliminary Survey and Investigation Charges

(929,990)

Change in Clearing Accounts

19,639

Change in Miscellaneous Deferred Debits

(33,570,746)

Change in Unamortized Loss on Reacquired Debt

103,213

Change in Share Based Compensation

(243,135)

Change in (Less) Unamortized Discount on Long-Term Debt

(4,266)

Change in Accumulated Provision for Injuries and Damages

(375,315)

Change in Accumulated Provision for Pensions and Benefits

59,313,731

Change in Miscellaneous Operating Provisions

(8,632,837)

Change in Asset Retirement Obligations

(904,019)

Change in Derivative Instrument Liabilities

(19,685,239)

Change in Customer Advances for Construction

(1,122,165)

Change in Other Deferred Credits

20,259,133

 

 

(30,734,623)

 

(f) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -709369498
(g) Concept: GrossAdditionsToCommonUtilityPlantInvestingActivities
Original value: -8083200
(h) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -13602040
(i) Concept: OtherConstructionAndAcquisitionOfPlantInvestmentActivities

 

 

2018

Investing Activities - Other

 

Change in Utility Plant - Other

(1,796,127)

 

 

(1,796,127)

 

(j) Concept: OtherConstructionAndAcquisitionOfPlantInvestmentActivities
Original value: -1796127
(k) Concept: OtherConstructionAndAcquisitionOfPlantInvestmentActivities
Original value: -44025032
(l) Concept: CashOutflowsForPlant
Original value: -749671817
(m) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

 

 

2018

Investing Activities - Other

 

Change in Other Investments

(590,404)

Change in Special Funds

523,943

Property Tax Reimbursement

34,040

Change in Accumulated Other Comprehensive Income

(3,265,846)

 

 

(3,298,267)

 

(n) Concept: PaymentsForRetirementOfLongTermDebtFinancingActivities
Original value: -5300000
(o) Concept: DividendsOnPreferredStock
Original value: -1060497
(p) Concept: CashAndCashEquivalents

This consists of the following:

 

 

 

2017

Cash (131)

 

1,081,689

Special Deposits (132-134)

20,515,417

 

 

21,597,106

 

 

 

 

(q) Concept: CashAndCashEquivalents

This consists of the following:

 

 

 

2018

Cash (131)

 

7,367,468

Special Deposits (132-134)

2,733,610

 

 

10,101,078

 

(r) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: -52314616
(s) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: -7732444
(t) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -121793421
(u) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

 

 

2017

Operating Activities - Other

 

Change in Derivative Instrument Assets

317,871

Change in Prepayments

(28,315,199)

Change in Miscellaneous Current and Accrued Assets

(4,841,922)

Change in Unamortized Debt Expense

(930,987)

Change in Preliminary Survey and Investigation Charges

(701,777)

Change in Clearing Accounts

(120,782)

Change in Miscellaneous Deferred Debits

(87,230,560)

Change in Unamortized Loss on Reacquired Debt

103,214

Change in Share Based Compensation

329,040

Change in (Less) Unamortized Discount on Long-Term Debt

700

Change in Accumulated Provision for Injuries and Damages

1,955,485

Change in Accumulated Provision for Pensions and Benefits

79,570,162

Change in Miscellaneous Operating Provisions

(11,806,636)

Change in Asset Retirement Obligations

(224,974)

Change in Derivative Instrument Liabilities

(18,872,991)

Change in Customer Advances for Construction

542,602

Change in Other Deferred Credits

5,917,752

 

 

(64,309,002)

 

(v) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -577694274
(w) Concept: GrossAdditionsToCommonUtilityPlantInvestingActivities
Original value: -8754982
(x) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -11831665
(y) Concept: OtherConstructionAndAcquisitionOfPlantInvestmentActivities

 

 

2017

Investing Activities - Other

 

Change in Utility Plant - Other

(846,926)

 

 

(846,926)

 

(z) Concept: CashOutflowsForPlant
Original value: -629407505
(aa) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

 

 

2017

Investing Activities - Other

 

Change in Other Investments

(965,308)

Change in Special Funds

(3,027,567)

Change in Accumulated Other Comprehensive Income

1,526,427

 

 

(2,466,448)

 

(ab) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities

 

 

2017

Financing Activities - Other

 

Parent Tax Loss Allocation

32,719,935

 

 

32,719,935

 

(ac) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: 32719935
(ad) Concept: CashAndCashEquivalents

This consists of the following:

 

 

 

2017

Cash (131)

 

1,081,689

Special Deposits (132-134)

20,515,417

 

 

21,597,106

 

 

 

 


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
NOTES TO FINANCIAL STATEMENTS
  1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement.
  2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
  3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
  4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
  5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
  6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
  7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted.
  8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred.
  9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.

NIAGARA MOHAWK POWER CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

 

 

  1. NATURE OF OPERATIONS AND BASIS OF PRESENTATION

 

Niagara Mohawk Power Corporation (“the Company”), a New York Corporation, is engaged principally in the regulated energy delivery business in New York State (“NYS”). The Company provides electric service to approximately 1.7 million customers in the areas of eastern, central, northern, and western New York and sells, distributes, and transports natural gas to approximately 0.6 million customers in the areas of central, northern, and eastern New York.

 

The Company is a wholly-owned subsidiary of Niagara Mohawk Holdings, Inc. (“NMHI”), which is a wholly-owned subsidiary of National Grid USA (“NGUSA” or the “Parent”), a public utility holding company with regulated subsidiaries engaged in the generation of electricity and the transmission, distribution, and sale of both natural gas and electricity. NGUSA is a direct wholly-owned subsidiary of National Grid North America Inc. (“NGNA”) and an indirect wholly-owned subsidiary of National Grid plc, a public limited company incorporated under the laws of England and Wales.

 

The accompanying financial statements are unaudited and prepared in accordance with the accounting requirements of the Federal Energy Regulatory Commission (“FERC”) as set forth in its applicable Uniform System of Accounts. This is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America (“U.S. GAAP”). The primary differences consist of the following:

 

  • For FERC reporting, regulatory assets and liabilities are classified as non-current. For U.S. GAAP reporting, regulatory assets and liabilities are classified as current or long-term as applicable.

 

  • The accumulated amounts collected in rates for cost of removal over spending are included within accumulated depreciation for FERC reporting, but are presented as a regulatory liability for U.S. GAAP reporting.

 

  • All debt is classified as long-term in the balance sheet for FERC reporting. Under U.S. GAAP, the presentation reflects current and long-term debt separately.

 

  • For FERC reporting, the debt issuance costs related to term loans are presented in the balance sheet within deferred charges and other assets. Under U.S. GAAP, this is presented in the balance sheet as a direct deduction from the carrying value of debt.

 

  • Goodwill is included within utility plant for FERC reporting, but is presented as other non-current assets for U.S. GAAP reporting.

 

  • For FERC reporting, the liability for uncertain tax positions related to temporary differences is not recognized pursuant to FERC guidance and deferred taxes are recognized based on the difference between positions taken in filed tax returns and amounts reported in the financial statements. For U.S. GAAP reporting, the liability for uncertain tax positions related to temporary differences is recognized and deferred taxes are recognized based on the difference between the positions taken in filed tax returns adjusted for uncertain tax positions related to temporary differences and amounts reported in the financial statements.

 

  • For FERC reporting, deferred tax assets and liabilities are presented on a gross basis. For U.S. GAAP reporting, deferred tax assets and liabilities are presented on a net basis.

 

  • For FERC reporting, certain revenues or expenses are classified as either utility or non-utility in nature. For GAAP reporting, no distinction between utility and non-utility is made.

 

 

 

 

Supplemental Cash Flow Information

 

[image]

 

The Company has evaluated subsequent events and transactions through April 17, 2019, the date of issuance of these financial statements, and concluded that there were no events or transactions that require adjustment to, or disclosure in, the financial statements as of and for the year ended December 31, 2018.

 

  1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Use of Estimates

 

In preparing financial statements that conform to FERC requirements, the Company must make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses, and the disclosure of contingent assets and liabilities included in the financial statements. Actual results could differ from those estimates.

 

Regulatory Accounting

 

The FERC and the New York Public Service Commission (“NYPSC”) regulate the rates the Company charges its customers. In certain cases, the rate actions of the FERC and NYPSC can result in accounting that differs from non-regulated companies. In these cases, the Company defers costs (as regulatory assets) or recognizes obligations (as regulatory liabilities) if it is probable that such amounts will be recovered from, or refunded to, customers through future rates. Regulatory assets and liabilities are reflected on the balance sheet consistent with the treatment of the related costs in the ratemaking process.

 

Revenue Recognition

 

Revenues are recognized for energy service provided on a monthly billing cycle basis. The Company records unbilled revenues for the estimated amount of services rendered from the time meters were last read to the end of the accounting period.

 

As approved by the NYPSC, the Company is allowed to pass through commodity-related costs to customers and also bills for approved rate adjustment mechanisms. In addition, the Company has separate revenue decoupling mechanisms for gas and electric which allow for annual adjustments to the Company’s delivery rates as a result of the reconciliation between allowed revenue and billed revenue. Any difference between the allowed revenue and the billed revenue is recorded as a regulatory asset or regulatory liability.

 

 

 

 

 

 

 

Transmission Formula Rate

 

The Company’s wholesale transmission service charge (“TSC”) rates are established based on a FERC-approved formula. The Company is required to make an informational filing annually to update certain components of the TSC formula rate. The revenue requirement component of the annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement in effect in the prior year and the actual revenue requirement for that year.

 

Other Taxes

 

The Company collects taxes and fees from customers such as sales taxes, other taxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. The Company accounts for taxes that are imposed on customers (such as sales taxes) on a net basis (excluded from revenues), while taxes imposed on the Company, such as excise taxes, are recognized on a gross basis. Excise taxes collected and paid for the years ended December 31, 2018 and 2017 were $39.7 million and $35.5 million, respectively.

 

The state of New York imposes on corporations a franchise tax that is computed as the higher of a tax based on income or a tax based on capital. To the extent the Company’s state tax based on capital is in excess of the state tax based on income, the Company reports such excess in other taxes and taxes accrued in the accompanying financial statements.

 

The Company’s policy is to accrue for property taxes on a calendar year basis, taking into account the assessment period. The Company had prepaid property taxes of $0.3 million and zero at December 31, 2018 and 2017, respectively.

 

Income Taxes

 

Federal and state income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferred tax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Deferred income taxes also reflect the tax effect of net operating losses, capital losses, and general business credit carryforwards. The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that the Company will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount.

 

The effects of tax positions are recognized in the financial statements when it is more likely than not that the position taken, or expected to be taken, in a tax return will be sustained upon examination by taxing authorities based on the technical merits of the position. The financial effect of changes in tax laws or rates is accounted for in the period of enactment. Deferred investment tax credits are amortized over the useful life of the underlying property.

 

NGNA files consolidated federal tax returns including all of the activities of its subsidiaries. Each subsidiary determines its tax provision based on the separate return method, modified by a benefits-for-loss allocation pursuant to a tax sharing agreement between NGNA and its subsidiaries. The benefit of consolidated tax losses and credits are allocated to the NGNA subsidiaries giving rise to such benefits in determining each subsidiary’s tax expense in the year that the loss or credit arises. In a year that a consolidated loss or credit carryforward is utilized, the tax benefit utilized in consolidation is paid proportionately to the subsidiaries that gave rise to the benefit regardless of whether that subsidiary would have utilized the benefit. The tax sharing agreement also requires NGNA to allocate its parent tax losses, excluding deductions from acquisition indebtedness, to each subsidiary in the consolidated federal tax return with taxable income. The allocation of NGNA’s parent tax losses to its subsidiaries is accounted for as a capital contribution and is performed in conjunction with the annual intercompany cash settlement process following the filing of the federal tax return.

 

 

Cash and Cash Equivalents

 

Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Cash and cash equivalents are carried at cost which approximates fair value.

 

Special Deposits

 

Special deposits primarily consist of collateral paid to the Company’s counterparties for outstanding derivative instruments, a release of property account for mortgaged property under a mortgage trust indenture, and a reserve for potential environmental violations.

 

Accounts Receivable and Accumulated Provision for Uncollectible Accounts

 

The Company recognizes an accumulated provision for uncollectible accounts to record accounts receivable at estimated net realizable value. The provision is determined based on a variety of factors including, for each type of receivable, applying an estimated reserve percentage to each aging category, taking into account historical collection and write-off experience, and management's assessment of collectability from individual customers, as appropriate. The collectability of receivables is continuously assessed and, if circumstances change, the provision is adjusted accordingly. Receivable balances are written off against the provision for uncollectible accounts when the accounts are disconnected and/or terminated and the balances are deemed to be uncollectible.

 

Plant Materials and Operating Supplies and Gas Stored Underground

 

Plant materials and operating supplies are stated at weighted average cost, which represents net realizable value, and are expensed or capitalized as used. The Company’s policy is to write-off obsolete plant materials and operating supplies; there were no material write-offs of obsolete plant materials and operating supplies for the years ended December 31, 2018 or 2017.

 

Gas stored underground is stated at weighted average cost and the related cost is recognized when delivered to customers. Existing rate orders allow the Company to pass directly through to customers the cost of gas purchased, along with any applicable authorized delivery surcharge adjustments. Gas costs passed through to customers are subject to regulatory approvals and are audited annually by the NYPSC.

 

Derivative Instruments

 

The Company uses various derivative instruments to manage commodity price risk. All derivative instruments, except those that qualify for the normal purchase normal sale exception, are recorded on the balance sheet at their fair value. All commodity costs, including the impact of derivative instruments, are passed on to customers through the Company’s commodity rate adjustment mechanisms. Therefore, gains or losses on the settlement of these contracts are initially deferred and then refunded to, or collected from, customers consistent with regulatory requirements.

 

The Company has certain non-trading instruments for the physical purchase of electricity that qualify for the normal purchase normal sale exception and are accounted for upon settlement. If the Company were to determine that a contract no longer qualifies for the normal purchase normal sale exception, then the Company would recognize the fair value of the contract in accordance with the regulatory accounting described above.

 

The Company’s accounting policy is to not offset fair value amounts recognized for derivative instruments and related cash collateral receivable or payable with the same counterparty under a master netting agreement, but rather to record and present the fair value of the derivative instrument on a gross basis, with related cash collateral recorded within special deposits on the balance sheet.

 

Power Purchase Agreements

 

The Company enters into power purchase agreements to procure commodity to serve its electric service customers. The Company evaluates whether such agreements are leases, derivative instruments, or executory contracts. Power purchase agreements that do not qualify as leases or derivative instruments are accounted for as executory contracts and are, therefore, recognized as the electricity is purchased. In making its determination of the accounting for power purchase agreements, the Company considers many factors, including: the source of the electricity; the level of output from any specified facility that the Company is taking under the contract; the involvement, if any, that the Company has in operating the specified facility; and the pricing mechanisms in the contract.

 

Natural Gas Long-Term Arrangements

 

The Company enters into long-term gas contracts to procure commodity to serve its gas customers. Those contracts include Asset Management Agreements, Baseload, and Peaking gas contracts. Similar to the power purchase agreements noted above, the Company evaluates whether such agreements are derivative instruments or executory contracts and applies the appropriate accounting treatment.

 

Fair Value Measurements

 

The Company measures derivative instruments and available-for-sale securities at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The following is the fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value:

 

  • Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities that a company has the ability to access as of the reporting date;

  • Level 2: inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data;

  • Level 3: unobservable inputs, such as internally-developed forward curves and pricing models for the asset or liability due to little or no market activity for the asset or liability with low correlation to observable market inputs; and

  • Not categorized: certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair value.

 

The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. The Company uses valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

 

Utility Plant

 

Utility plant is stated at original cost. The cost of repairs and maintenance is charged to expense and the cost of renewals and betterments that extend the useful life of utility plant is capitalized. The capitalized cost of additions to utility plant includes costs such as direct material, labor and benefits, and an allowance for funds used during construction (“AFUDC”).

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation is computed over the estimated useful life of the asset using the composite straight-line method. Depreciation studies are conducted periodically to update the composite rates and are approved by the NYPSC. The average composite rates for the years ended December 31, 2018 and 2017 are as follows:

 

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Depreciation expense includes a component for estimated future cost of removal, which is recovered through rates charged to customers.

 

Allowance for Funds Used During Construction

 

The Company records AFUDC, which represents the debt and equity costs of financing the construction of new utility plant. AFUDC equity is reported in the statements of income as non-cash income and AFUDC debt is reported as a non-cash offset to interest expense. After construction is completed, the Company is permitted to recover these costs through their inclusion in rate base and corresponding depreciation expense. The Company recorded AFUDC related to equity of $13.6 million and $11.8 million and AFUDC related to debt of $5.2 million and $3.9 million for the years ended December 31, 2018 and 2017, respectively. The average AFUDC rates for the years ended December 31, 2018 and 2017 were 6.8%.

 

Impairment of Long-Lived Assets

 

The Company tests the impairment of long-lived assets annually or when events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. The recoverability of an asset is determined by comparing its carrying value to the future undiscounted cash flows that the asset is expected to generate. If the comparison indicates that the carrying value is not recoverable, an impairment loss is recognized for the excess of the carrying value over the estimated fair value. For the years ended December 31, 2018 and 2017, there were no impairment losses recognized for long-lived assets. 

 

Goodwill

 

The Company tests goodwill for impairment annually on January 1, and when events occur or circumstances change that would more likely than not reduce the fair value of each of the Company’s respective reporting units below its carrying amount. The Company has early adopted Accounting Standards Update (“ASU”) 2017-04, “Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment,” which eliminates step two from the two-step goodwill impairment test. The one-step approach requires a recoverability test performed based on the comparison of the Company’s estimated fair value with its carrying value, including goodwill. If the estimated fair value exceeds the carrying value, then goodwill is considered not impaired. If the carrying value exceeds the estimated fair value, the Company is required to recognize an impairment charge for such excess, limited to the allocated amount of goodwill.

 

The fair value of the Company was calculated in the annual goodwill impairment test for the year ended December 31, 2018 utilizing both income and market approaches. The Company uses a 50% weighting for each valuation methodology, as it believes that each methodology provides equally valuable information. Based on the resulting fair value from the annual analyses, the Company determined that no adjustment of the goodwill carrying value was required at December 31, 2018 or 2017.

 

 

 

 

Available-For-Sale Securities

 

The Company provides certain executives with nonqualified retirement and deferred compensation benefits which have been partially secured through separate fund arrangements. As a result, the Company holds available-for-sale securities that include equities, municipal bonds, and corporate bonds. These investments are recorded at fair value and are included in other special funds on the balance sheet. Changes in the fair value of these assets are recorded within other comprehensive income.

 

Asset Retirement Obligations

 

Asset retirement obligations are recognized for legal obligations associated with the retirement of utility plant, primarily associated with the Company’s distribution facilities. Asset retirement obligations are recorded at fair value in the period in which the obligation is incurred, if the fair value can be reasonably estimated. In the period in which new asset retirement obligations, or changes to the timing or amount of existing retirement obligations are recorded, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. In each subsequent period the asset retirement obligation is accreted to its present value. The Company applies regulatory accounting guidance and both the depreciation and accretion costs associated with asset retirement obligation are recorded as increases to regulatory assets on the balance sheet. These regulatory assets represent timing differences between the recognition of costs in accordance with FERC reporting and costs recovered through the ratemaking process.

 

The following table represents the changes in the Company’s asset retirement obligations:

 

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The Company had a current portion of asset retirement obligations of $0.4 million included in miscellaneous current and accrued liabilities on the balance sheet at December 31, 2018.

 

Employee Benefits

 

The Company has defined benefit pension plans and postretirement benefit other than pension (“PBOP”) plans for its employees. The Company recognizes all pension and PBOP plans’ funded status on the balance sheet as a net liability or asset with an offsetting adjustment to accumulated other comprehensive income (“AOCI”) in shareholders’ equity. The cost of providing these plans is recovered through rates; therefore, the net funded status is offset by a regulatory asset or liability. The Company measures and records its pension and PBOP funded status at the year-end date. Pension and PBOP plan assets are measured at fair value, using the year-end market value of those assets.

 

Supplemental Executive Retirement Plans

 

The Company has corporate assets included in other non-current assets on the balance sheet representing funds designated for Supplemental Executive Retirement Plans. These funds are invested in corporate owned life insurance policies and available-for-sale securities primarily consisting of equity investments and investments in municipal and corporate bonds. The corporate owned life insurance investments are measured at cash surrender value with increases and decreases in the value of these assets recorded in the accompanying statements of income.

 

New and Recent Accounting Guidance

 

Accounting Guidance Recently Adopted

 

Pension and Postretirement Benefits

 

In March 2017, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2017-07, “Compensation Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” which changes certain presentation and disclosure requirements for employers that sponsor defined benefit pension and other postretirement benefit plans. For U.S. GAAP reporting, the ASU requires the service cost component of the net benefit cost to be in the same line item as other compensation in operating income and the other components of net benefit cost to be presented outside of operating income on a retrospective basis. For FERC reporting purposes, all costs will continue to be reported in operating expenses. In addition, only the service cost component will be eligible for capitalization when applicable, on a prospective basis. For the Company, the requirements of the new standard are effective for the current fiscal year ending March 31, 2019 and interim periods therein. The application of the new guidance did not have a material impact on the results of the Company’s operations, cash flows, and financial position since the Company defers the difference between actual pension costs and the amounts used to establish rates (See Note 7 “Employee Benefits” for additional details).

 

Statement of Cash Flows

 

In November 2016, the FASB issued ASU No. 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)," which requires entities to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents in the statement of cash flows.

 

In August 2016, the FASB issued ASU No. 2016-15, "Classification of Certain Cash Receipts and Cash Payments (Topic 230)," which provides guidance about the classification of certain cash receipts and payments within the statement of cash flows, including debt prepayment or extinguishment costs, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims and policies, and distributions received from equity method investments.

 

Both accounting updates are effective for the current fiscal year ending March 31, 2019 and interim periods therein. The application of ASU No. 2016-18 resulted only in a change in presentation on the Company’s statement of cash flows. Movements in restricted cash were previously included as investing activities. The application of ASU No. 2016-15 did not have a material impact on the Company’s cash flows.

 

Income Taxes

 

In October 2016, the FASB issued ASU No. 2016-16, "Income Taxes (Topic 740): Intra­Entity Transfers of Assets Other Than Inventory," which eliminates the exception for all intra-entity sales of assets other than inventory. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. For the Company, the requirements of the new standard are effective for the current fiscal year ending March 31, 2019 and interim periods therein. The application of this guidance did not have a material impact on the results of operations, cash flows, or financial position of the Company.

 

Revenue Recognition

 

In May 2014, the FASB issued ASU No. 2014-09: “Revenue from Contracts with Customers (Topic 606).” The underlying principle of this ASU is that an entity will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to, in exchange for those goods or services. For the Company, the new guidance is effective for the fiscal year ending March 31, 2019 and interim periods therein, and was adopted using a modified retrospective approach.

 

The FASB has issued a number of additional recent ASUs related to revenue recognition, whose effective date and transition requirements are the same as those for ASU No. 2014-09. In March 2016, the FASB issued ASU No. 2016-08, “Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” which clarifies the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued ASU No. 2016-10, "Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing," which provides guidance in the new revenue standard on identifying performance obligations and accounting for licenses of intellectual property. In May 2016, the FASB issued ASU No. 2016-12, “Revenue from Contracts with Customers (ASC 606) Narrow-Scope Improvements and Practical Expedients,” providing additional clarity on various aspects of Topic 606, including a) Assessing the Collectability Criterion and Accounting for Contracts That Do Not Meet the Criteria for Step 1, b) Presentation of Sales Taxes and Other Similar Taxes Collected from Customers, c) Noncash Consideration, d) Contract Modifications at Transition, e) Completed Contracts at Transition, and f) Technical Correction. Lastly, in December 2016, the FASB issued ASU No. 2016-20, "Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers." The amendments in this update cover a variety of corrections and improvements to the Codification related to the new revenue recognition standard (ASU No. 2014-09).

 

The Company performed detailed reviews of its revenue arrangements to ensure compliance with the new standard effective for the current fiscal year ending March 31, 2019 and interim periods therein. The adoption of ASC 606 did not have a material impact on the presentation of the Company’s results of operations, cash flows, or financial position. However, the Company has added additional qualitative and quantitative financial statement disclosures per requirements under ASC 606 pertaining to its revenue earning mechanisms (See Note 3, “Revenue” for additional details).

 

Financial Instruments – Classification and Measurement

 

In January 2016, the FASB issued ASU No. 2016-01, “Financial Instruments – Overall: Recognition and Measurement of Financial Assets and Financial Liabilities.” The new guidance principally affects the accounting for equity investments and financial liabilities where the fair value option has been elected, as well as the disclosure requirements for financial instruments. For the Company, the new guidance is effective for the fiscal year ending March 31, 2019 and interim periods therein. The adoption of this ASU did not have a material impact on the presentation, results of operations, cash flows, and financial position of the Company.

 

Goodwill

 

In January 2017, the FASB issued ASU No. 2017-04, which eliminates Step 2 from the goodwill impairment test. For the Company, the requirements of the new standard will be effective for the fiscal year ending March 31, 2022, with early adoption permitted. The Company early adopted the ASU in the year ended March 31, 2018 for its annual goodwill impairment testing. Based on the resulting fair value from the annual analyses, the Company determined that no adjustment to the goodwill carrying value was required at March 31, 2018 or 2017.

 

Stock Compensation

 

In May 2017, the FASB issued ASU No. 2017-09, “Stock Compensation (Topic 718): Scope of Modification Accounting,” which provides clarity on the application of modification accounting upon a change to the terms or conditions of a share-based payment award. For the Company, the new guidance is effective for the fiscal year ending March 31, 2019 and interim periods therein. The adoption of this ASU did not have a material impact on the presentation, results of operations, cash flows, and financial position of the Company.

 

Accounting Guidance Not Yet Adopted

 

Derivatives and Hedging

 

In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities,” which will be effective for the fiscal year ending March 31, 2020, with early adoption permitted. The amendments in this update expand and refine hedge accounting for both financial and nonfinancial risk components and align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. This update also includes changes to certain targeted improvements to ease the application of current guidance related to the assessment of hedge effectiveness. The Company is currently evaluating the impact of the new guidance on the results of its operations, cash flows, and financial position.

 

Leases

 

In February 2016, the FASB issued ASU 2016-02 “Leases” (codified as Topic 842) related to lease accounting, effective January 1, 2019 for public entities. For the Company, the new standard is effective for the fiscal year ending March 31, 2020, and interim periods within, with early adoption permitted. Under the new standard, a lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified assets for a period of time in exchange for consideration. Lessees will need to recognize leases on the balance sheet as a right-of-use asset and a related lease liability and classify the leases as either operating or finance. The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustments, such as initial direct costs.

 

The standard will also require lessors to allocate (rather than recognize as currently required) certain variable payments to the lease and non-lease components when the changes in facts and circumstances on which the variable payment is based occur.

 

The standard will require the Company to recognize and measure the cumulative effect of the new standard at the beginning of the earliest period presented using a modified retrospective approach.

 

The Company’s operating leases portfolio includes mainly real estate, fleet vehicles and telecommunication towers. These operating leases will result in straight-line expense while finance leases will result in a higher initial expense pattern due to the interest component. The Company, as a regulated entity, is permitted to continue to recognize expense using the timing that conforms to the regulatory rate treatment. Additionally, lessees can elect to exclude from the balance sheet short-term contracts of one year or less. The Company is currently assessing its alternatives for electing the options allowed for lessees by the standard setters including the impact of short-term lease considerations.

 

The new standard provides the Company with transition practical expedients including a package of three expedients that must be taken together and allows the Company to: not reassess whether existing contracts contain leases, carryforward the existing classification of any leases, and not reassess initial direct costs associated with existing leases. The Company is still evaluating its options related to the package of practical expedients.

 

The standard permits an entity to elect an optional transition practical expedient to not evaluate under Topic 842 land easements that exist or expire before the Company’s adoption of Topic 842, that were not previously accounted for as leases under Topic 840. The Company will exercise its option to elect this expedient.

 

The standard permits lessors, as an accounting policy election, to not evaluate whether certain sales taxes and other similar taxes are lessor costs or lessee costs. Instead, those lessors will account for those costs as if they are lessee costs. The company is assessing its alternatives for electing this option. The standard also allows lessors to exclude certain costs from variable payments, and therefore revenue, for lessor costs paid by lessees directly to third parties. The Company is assessing its alternatives for electing this option.

 

We have established a cross-functional team to assess and implement the new standard. Our assessment is substantially complete, and the Company is currently finalizing its adoption options allowed for lessees and lessors by the new standard.

 

The adoption of this standard will increase right-of-use assets and lease liabilities on the Company’s consolidated balance sheet and require more robust disclosures related to leases. The Company is currently implementing a new lease accounting system and is evaluating the impact this standard will have on the results of operations, financial position, and lease disclosures of the Company.

 

Related Party

 

In October 2018, the FASB issued ASU No. 2018-17 “Consolidation (Topic 810), Targeted Improvements to Related Party Guidance for Variable Interest Entities (“VIE”)” which allows a private company (reporting entity) not to apply VIE guidance to legal entities under common control (including common control leasing arrangements) if both the parent and the legal entity being evaluated for consolidation are not public business entities. Also, indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. For the Company, the requirements in this update are effective for the fiscal year ending March 31, 2021 and interim periods within. The Company is currently assessing the application of the standard to determine if it will have a material impact on the presentation, results of operations, cash flows, and financial position of the Company.

 

Intangibles - Goodwill and Other

 

In August 2018, the FASB issued ASU No. 2018-15 “Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40), Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract” to help entities evaluate the accounting for fees paid by a customer. The amendment will align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. For the Company, the requirements in this update are effective for the fiscal year ending March 31, 2021 and interim periods within. The Company is currently assessing the application of the standard to determine if it will have a material impact on the presentation, results of operations, cash flows, and financial position of the Company.

 

Compensation

 

In August 2018, the FASB issued ASU No. 2018-14 “Compensation – Retirement Benefits – Defined Benefit Plans – General (Subtopic 715-20), Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans” which modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For the Company, the requirements in this update are effective for the fiscal year ending March 31, 2022 and interim periods within. The Company is currently assessing the application of the standard to determine if it will have a material impact on the presentation, results of operations, cash flows, and financial position of the Company.

 

In June 2018, the FASB issued ASU No. 2018-07 “Compensation – Stock Compensation (Topic 718), Improvements to Nonemployee Share-Based Payment Accounting” which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. For the Company, the requirements in this update are effective for the fiscal year ending March 31, 2020 and interim periods within. The Company is currently assessing the application of the standard to determine if it will have a material impact on the presentation, results of operations, cash flows, and financial position of the Company.

 

Fair Value

 

In August 2018, the FASB issued ASU No. 2018-13 “Fair Value Measurement (Topic 820), Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement” which modifies the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement, based on the concepts in the Concepts Statement, including the consideration of costs and benefits. For the Company, the requirements in this update are effective for the fiscal year ending March 31, 2021 and interim periods within. The Company is currently assessing the application of the standard to determine if it will have a material impact on the presentation, results of operations, cash flows, and financial position of the Company.

 

Financial Instruments

 

In November 2018, the FASB issued ASU No. 2018-19 “Codification Improvements to Topic 326, Financial Instruments – Credit Losses” which mitigates the transition complexity by requiring that for nonpublic business entities the amendments in update 2016-13 are effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. The amendment clarifies that receivables arising from operating leases are not within the scope of Subtopic 326-20. Instead, impairment of receivables arising from operating leases should be accounted for in accordance with Topic 842. For the Company, the requirements in this update are effective for the fiscal year ending March 31, 2021 and interim periods within. The Company is currently assessing the application of the standard to determine if it will have a material impact on the presentation, results of operations, cash flows, and financial position of the Company.

 

In June 2016, the FASB issued ASU No. 2016-13 “Financial Instruments – Credit Losses (Topic 326), Measurement of Credit Losses on Financial Statements” requires a financial asset (or a group of financial assets) measured at amortized cost basis to be presented at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset(s) to present the net carrying value at the amount expected to be collected on the financial asset. Credit losses relating to available-for-sale debt securities should be recorded through an allowance for credit losses. For the Company, the requirements of the new standard will be effective for the fiscal year ending March 31, 2022 and interim periods therein, with early adoption permitted from the fiscal year ending March 31, 2020 and interim periods within. The Company is currently assessing the application of the standard to determine if it will have a material impact on the presentation, results of operations, cash flows, and financial position of the Company.

 

  1. REVENUE

 

Upon the adoption of ASC Topic 606, revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. The Company recognizes revenue when it transfers control over a product or service to a customer.

 

Nature of Goods and Services

 

The following is a description of principal activities – separated by reportable segments – from which the Company generates its revenue.

 

Transmission

 

The Transmission segment of the Company principally generates revenue from providing the services/products shown in further detail below. Transmission systems generally include overhead lines, underground cables and substations, connecting generation and interconnectors to the distribution system. The Company owns, maintains, and operates an electricity transmission system spanning upstate New York. The Company’s transmission services are regulated by both the New York Independent System Operator and by the FERC in respect of interstate transmission.

Products and services

Nature, timing of satisfaction of performance obligations, and signifi­cant payment terms

 

Electric Transmission

Electric transmission revenues arise under Transmission Congestion Contract auctions, Transmission Service Agreements and Local / Regional Network Services under tariff/rate agreements. The Company bills its transmission services typically on a monthly basis, in the month after service has been provided. The Company recognizes the revenue as the amounts are billed, as these amounts represent the actual consideration for the services provided to customers.

 

Distribution

 

The Distribution segment of the Company principally generates revenue from providing the services/products shown in further detail below. The distribution revenues are primarily associated with cancellable contracts with the exception of certain long-term contracts with commercial and industrial customers. The Company’s distribution services are regulated by the NYPSC.

 

Products and services

Nature, timing of satisfaction of performance obligations, and signifi­cant payment terms

 

Electric Distribution

The Company owns, maintains, and operates an electricity distribution network in upstate New York. The Company bills its distribution services typically on a monthly basis, in the month after service has been provided. The Company recognizes revenue based on its right to invoice its customers. This corresponds directly with the value to the customer of performance to date. The distribution revenue also includes estimated unbilled amounts, which are recognized over time and determined utilizing approved tariff rates and estimated meter volumes.

Gas Distribution

The Company owns, maintains, and operates a gas distribution network serving areas in New York, primarily consisting of domestic and commercial consumers. The Company bills its distribution services typically on a monthly basis, in the month after service has been provided. The Company recognizes revenue based on its right to invoice its customers. This corresponds directly with the value to the customer of performance to date. The amount of revenue also includes estimated unbilled amounts, which are recognized over time and determined utilizing estimated usage.

 

Other Activities

The Other Activities segment of the Company and the revenues generated from it are shown in further detail below.

Products and services

Nature, timing of satisfaction of performance obligations, and signifi­cant payment terms

 

Alternative Revenue Programs

The Company’s distribution tariffs authorize it to increase or decrease its bills to customers for certain items other than direct compensation for the current provision of utility service. These tariff provisions constitute alternative revenue programs. Specifically, the Company has separate revenue decoupling mechanisms for gas and electric which allow for annual adjustments to the Company’s delivery rates as a result of the reconciliation between allowed revenue and billed revenue.

Other

Other revenues include off-system sales, lease revenue, and various deferral mechanisms (including capital tracker and storm deferral) that are not considered revenue from contracts with customers.

 

 

 

 

 

Disaggregation of Revenue

 

In the following table, revenue is disaggregated by major products and services.

 

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  1. REGULATORY ASSETS AND LIABILITIES

 

The Company records regulatory assets and liabilities that result from the ratemaking process. The following table presents the regulatory assets and regulatory liabilities recorded on the balance sheet:

 

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Carrying charges: The Company records carrying charges on regulatory balances for which cash expenditures have been made and are subject to recovery, or for which cash has been collected and is subject to refund. Carrying charges are not recorded on items for which expenditures have not yet been made.

 

Derivative instruments: The Company evaluates open derivative instruments for regulatory deferral by determining if they are probable of recovery from, or refund to, customers through future rates. Derivative instruments that qualify for recovery are recorded at fair value, with changes in fair value recorded as regulatory assets or regulatory liabilities in the period in which the change occurs.

 

Dunkirk settlement deferral: The Company is allowed to defer up to $57 million to offset the Reliability Support Services (“RSS”) associated with the Dunkirk generating plant and RSS agreements with other generators. This is an on-going deferral mechanism. The timing for disposition of any associated deferred balances will be determined by future NYPSC rulings.

 

Economic development fund: Represents a deferral mechanism for economic development discounts. Under this mechanism, the Company reconciles the economic discounts provided to customers to the amount reflected in rates for future refund to, or recovery from, customers. This is an on-going deferral mechanism. The timing for disposition of any associated deferred balances will be determined by future NYPSC rulings.

 

Energy efficiency: An asset or liability is recognized resulting from the difference between revenue billed to customers through the Company’s energy efficiency charge and the costs of the Company’s energy efficiency programs as approved by the NYPSC.

 

Environmental response costs: The regulatory asset represents deferred costs associated with the Company’s share of the estimated costs to investigate and perform certain remediation activities at sites with which it may be associated. The Company’s rate plans provide for specific rate allowances for these costs at a level of $32.1 million per year, with variances deferred for future recovery from, or return to, customers. The Company believes future costs, beyond the expiration of current rate plans, will continue to be recovered through rates. The regulatory liability represents the excess of amounts received in rates over the Company’s actual site investigation and remediation costs.

 

Gas costs adjustment: The Company is subject to rate adjustment mechanisms for commodity costs, whereby an asset or liability is recognized resulting from differences between actual revenues and the underlying cost being recovered or differences between actual revenues and targeted amounts as approved by the NYPSC. These amounts will be refunded to, or recovered from, customers over the next year.

 

Long-term debt true-up: The Company has a mechanism whereby it reconciles the actual interest expense and other debt costs related to its variable rate debt with the amount reflected in rates ($22 million for electric and $5.5 million for gas). The Company defers any over or under recoveries for future refund to, or recovery from, customers. This is an on-going deferral mechanism. The timing for disposition of any associated deferred balances will be determined by future NYPSC rulings.

 

Postretirement benefits: The regulatory asset represents the Company’s deferral related to the underfunded status of its pension and PBOP plans. The regulatory liability primarily represents the excess of amounts received in rates over actual costs of the Company’s pension and PBOP plans to be refunded in future periods.

 

Rate adjustment mechanisms: In addition to commodity costs, the Company is subject to a number of additional rate adjustment mechanisms whereby an asset or liability is recognized resulting from differences between actual revenues and the underlying cost being recovered or differences between actual revenues and targeted amounts as approved by the NYPSC.

 

Regulatory tax asset/liability, net: Represents over-recovered federal and state deferred taxes of the Company primarily as a result of regulatory flow through accounting treatment and state income tax rate changes and excess federal deferred taxes as a result of the recently enacted Tax Cuts and Jobs Act (“Tax Act”).

 

Storm costs: The Joint Proposal (NMPC rate proceeding Case 12-E-0201) established an annual allowance for major storm recovery of $29 million in each of the three fiscal years ended March 31, 2016. The NYPSC allowed for the continuation of this allowance in Case 15-M-0744 for the two fiscal years ended March 31, 2018. The Company deferred the difference between the base rate allowance and actual major storm incremental costs for future refund to, or recovery from, customers. Under the new NMPC rate case (Case 17-E-0238), the annual allowance for major storm recovery will be $23 million for the three fiscal years ending March 31, 2021 and a per storm deferral threshold of $0.4 million was established. At December 31, 2017, the regulatory liability represents the cumulative storm reserve allowance/funding for major storm incremental costs and the regulatory asset represents the cumulative incremental costs incurred for qualified storm events. At December 31, 2018, these amounts have been reported net.

 

 

 

 

 

 

 

  1. RATE MATTERS

 

Electric and Gas Filing

 

On April 28, 2017, the Company filed a proposal to reset electric and natural gas delivery prices beginning in April 2018. On January 19, 2018, the Company reached a settlement agreement with the NYPSC Staff and other parties to the case and filed a Joint Proposal for a three-year rate plan. The proposal reflects the new federal tax law changes and provides a cumulative revenue requirement increase of $240.8 million and $60.8 million for the electric and gas business, respectively, based on a 9.0% return on equity and 48% common equity ratio. On March 15, 2018, the NYPSC issued a final order approving the Joint Proposal and the new rates took effect on April 1, 2018.

 

As of March 31, 2018, resulting from the Joint Proposal, a new electric rate plan settlement credit of $44.9 million and a new gas rate plan settlement credit of $28.4 million were established. These credits are included in other regulatory liabilities in the preceding table within Note 4, “Regulatory Assets and Liabilities.” The Company applied $38.4 million of existing regulatory liabilities towards the creation of these credits.

 

Tax Act

 

On March 15, 2018, the FERC initiated multiple proceedings intended to adjust FERC-jurisdictional rates to reflect the corporate tax changes as a result of the passage of the Tax Act signed into law on December 22, 2017. Proceedings initiated relevant to the Company are the Notice of Inquiry (“NOI”) seeking comments on the effects of the Tax Act on all FERC-jurisdiction rates and a Notice of Proposed Rulemaking (“NOPR”) issued as a result of the NOI. In response to the FERC NOI, the Company had made recommendations designed to mitigate the cash flow impacts of the expected refunds including providing flexibility regarding the methods used to refund accumulated deferred income tax (“ADIT”) to customers and providing flexibility regarding the time period of the flow back. In the NOPR, the FERC proposes to give flexibility we proposed. Comments on the NOPR were due on January 22, 2019, and the FERC will issue a final rule sometime thereafter, hopefully in the first half of fiscal year 2020. The amortization of the excess deferred taxes is expected to result in a net margin reduction of $12 million per year.

 

In response to the Tax Act signed into law on December 22, 2017, the NYPSC issued an Order Instituting Proceeding under Case 17-M-0815 - Proceeding on Motion of the Commission on Changes in Law that May Affect Rates. This proceeding was instituted to solicit comments on the Tax Act’s implications and places the utilities on notice of the NYPSC’s intent to protect ratepayers’ interest and to ensure that any cost reductions from the changes in federal income taxes are deferred for future ratepayer benefit. On March 29, 2018, the NYPSC Staff released its proposal to address accounting and ratemaking related to the Tax Act. Comments on NYPSC Staff’s proposal were filed June 27, 2018.

 

On August 9, 2018, the NYPSC issued an order in its generic proceeding considering the impacts of federal tax reform. NYPSC Staff had advocated that all New York utilities implement a sur-credit by October 1st that would reflect the immediate effects of the Tax Act and also return any deferred benefits to customers. In response, the Company filed a proposal to (i) delay any sur-credit to January 1st to offset scheduled rate increases and (ii) retain any deferred benefits, including accumulated deferred federal income taxes (“ADFIT”), for future rate moderation.

 

The NYPSC’s order effectively approved all aspects of the Company’s proposal. The NYPSC agreed that the Company should be allowed to defer both the pass back of calendar year 2018 tax savings (to the extent not already returned in the new rate plan) and the amortization of excess ADFIT balances and use the benefits as a rate moderator when base rates are next revised in 2020/2021. Specifically, the NYPSC directed that no sur-credit is required as the current rate plan already reflects the reduction of the tax rate to 21% and the termination of bonus depreciation. The NYPSC approved the Company’s proposal to defer the tax benefit realized for the three-month period (January-March) prior to new rates, of $18.0 million for electric and $4.6 million for gas, to offset future rate increases or investments. Protected balances of $620 million of electric excess ADFIT and $129 million of gas excess ADIT and unprotected electric excess ADFIT of $76 million and unprotected gas excess ADFIT of $14 million will be deferred for future disposition in rate proceedings.

 

Operations Staffing Audit

 

In January 2014, the NYPSC initiated an operational audit to review internal staffing levels and use of contractors for the core utility functions of the investor owned utilities operating in New York, including the Company. On June 26, 2014, the NYPSC selected a third party to conduct the audit. On February 21, 2017, the third party submitted its final report, which contained recommendations for all of National Grid’s New York utilities designed to improve the staffing and workforce management processes. The report contained 27 recommendations for National Grid. The Company filed its implementation plan on March 23, 2017. On December 15, 2017, the NYPSC issued an Order approving the Company’s implementation plan without modification, with updates to be made every four months to the NYPSC on the status of implementation. The Company submitted its most recent update on December 17, 2018.

 

New York Management Audit

 

In 2018, the NYPSC initiated a comprehensive management and operations audit of National Grid’s three New York electric and gas utilities. New York law requires periodic management audits of all utilities at least once every five years. National Grid last underwent a New York management audit in 2014/2015, when the NYPSC audited our New York gas business. The audit will be process oriented and forward looking and presents opportunities to obtain feedback on how to improve service to customers and meet regulatory expectations. Areas of focus will include the traditional audit areas of corporate governance, budgeting and finance, customer, work management, and long-term planning, as well as organization design, information systems, gas safety, and grid modernization.

 

  1. UTILITY PLANT AND NONUTILITY PROPERTY

 

The following table summarizes utility plant and nonutility property at cost along with accumulated depreciation and amortization:

 

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  1. DERIVATIVE INSTRUMENTS

 

The Company utilizes derivative instruments to manage commodity price risk associated with its natural gas and electricity purchases. The Company’s commodity risk management strategy is to reduce fluctuations in firm gas and electricity sales prices to its customers.

 

The Company’s financial exposures are monitored and managed as an integral part of the Company’s overall financial risk management policy. The Company engages in risk management activities only in commodities and financial markets where it has an exposure, and only in terms and volumes consistent with its core business.

 

 

Volumes

 

Volumes of outstanding commodity derivative instruments measured in dekatherms (“dths”) and megawatt hours (“mwhs”) are as follows:

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Amounts Recognized on the Balance Sheet

 

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The changes in fair value of the Company’s rate recoverable contracts are offset by changes in regulatory assets and liabilities. As a result, the changes in fair value of those contracts had no impact in the accompanying statements of income. All of the Company’s derivative instruments are subject to rate recovery as of December 31, 2018 and 2017.

 

Credit and Collateral

 

The Company is exposed to credit risk related to transactions entered into for commodity price risk management. Credit risk represents the risk of loss due to counterparty non-performance. Credit risk is managed by assessing each counterparty’s credit profile and negotiating appropriate levels of collateral and credit support.

 

The credit policy for commodity transactions is managed and monitored by the Finance Committee to National Grid plc’s Board of Directors (“Finance Committee”), which is responsible for approving risk management policies and objectives for risk assessment, control and valuation, and the monitoring and reporting of risk exposures. NGUSA’s Energy Procurement Risk Management Committee (“EPRMC”) is responsible for approving transaction strategies, annual supply plans, and counterparty credit approval, as well as all valuation and control procedures. The EPRMC is chaired by the Vice President of U.S. Treasury and reports to both the NGUSA Board of Directors and the Finance Committee.

 

The EPRMC monitors counterparty credit exposure and appropriate measures are taken to bring such exposures below the limits, including, without limitation, netting agreements, and limitations on the type and tenor of trades. The Company enters into enabling agreements that allow for payment netting with its counterparties, which reduce its exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. In instances where a counterparty’s credit quality has declined, or credit exposure exceeds certain levels, the Company may limit its credit exposure by restricting new transactions with the counterparty, requiring additional collateral or credit support, and negotiating the early termination of certain agreements. Similarly, the Company may be required to post collateral to its counterparties.

 

The Company’s credit exposure for all commodity derivative instruments, normal purchase normal sale contracts, and applicable payables and receivables, net of collateral, and instruments that are subject to master netting agreements, was an asset of $20.9 million and a liability of $12.5 million as of December 31, 2018 and 2017, respectively.

 

The aggregate fair value of the Company’s commodity derivative instruments with credit-risk-related contingent features that were in a liability position at December 31, 2018 and 2017 was $1.7 million and $24.7 million, respectively. The Company had zero and $8.8 million collateral posted for these instruments at December 31, 2018 and 2017, respectively. At December 31, 2018, if the Company’s credit rating were to be downgraded by one or two levels, it would not be required to post any additional collateral to its counterparties and if the Company’s credit rating were to be downgraded by three levels, it would be required to post additional collateral to its counterparties of $2.0 million. At December 31, 2017, if the Company’s credit rating had been downgraded by one, two, or three levels, it would have been required to post additional collateral to its counterparties of zero, $1.3 million, or $20.2 million, respectively.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Offsetting Information for Derivative Instruments Subject to Master Netting Arrangements

 

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  1. FAIR VALUE MEASUREMENTS

 

The following tables present assets and liabilities measured and recorded at fair value on the balance sheet on a recurring basis and their level within the fair value hierarchy as of December 31, 2018 and 2017:

 

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Derivative instruments: The Company’s Level 2 fair value derivative instruments primarily consist of over-the-counter (“OTC”) electric and gas swap contracts with pricing inputs obtained from the New York Mercantile Exchange and the Intercontinental Exchange (“ICE”), except in cases where the ICE publishes seasonal averages or where there were no transactions within the last seven days. The Company may utilize discounting based on quoted interest rate curves, including consideration of non-performance risk, and may include a liquidity reserve calculated based on bid/ask spread for the Company’s Level 2 derivative instruments. Substantially all of these price curves are observable in the marketplace throughout at least 95% of the remaining contractual quantity, or they could be constructed from market observable curves with correlation coefficients of 95% or higher.

 

The Company’s Level 3 fair value derivative instruments consist of gas option and purchase, and electric option and capacity transactions, which are valued based on internally-developed models. Industry-standard valuation techniques, such as the Black-Scholes pricing model, Monte Carlo simulation, and Financial Engineering Associates libraries are used for valuing such instruments. A derivative is designated Level 3 when it is valued based on a forward curve that is internally developed, extrapolated, or derived from market observable curves with correlation coefficients less than 95%, where optionality is present, or if non-economic assumptions are made.

 

Available-for-sale securities: Available-for-sale securities are included in other special funds on the balance sheet and primarily include equity and debt investments based on quoted market prices (Level 1) and municipal and corporate bonds based on quoted prices of similar traded assets in open markets (Level 2).

 

Changes in Level 3 Derivative Instruments

 

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A transfer into Level 3 represents existing assets or liabilities that were previously categorized at a higher level for which the inputs became unobservable during the year. A transfer out of Level 3 represents assets and liabilities that were previously classified as Level 3 for which the inputs became observable based on the criteria discussed previously for classification in Level 2. These transfers, which are recognized at the end of each period, result from changes in the observability of forward curves from the beginning to the end of each reporting period. There were no transfers between Level 1 and Level 2, and no transfers into or out of Level 3, during the years ended December 31, 2018 or 2017.

 

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivative instruments valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. The Company considers non-performance risk and liquidity risk in the valuation of derivative instruments categorized in Level 2 and Level 3.

 


Quantitative Information About Level 3 Fair Value Measurements

 

The following tables provide information about the Company’s Level 3 valuations:

 

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The significant unobservable inputs listed above would have a direct impact on the fair values of the Level 3 instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of the Company’s gas option derivative instruments and electric option and swap derivative instruments are implied volatility and gas forward curves. A relative change in commodity price at various locations underlying the open positions can result in significantly different fair value estimates.

 

Other Fair Value Measurements

 

The Company’s balance sheet reflects long-term debt at amortized cost. The fair value of the Company’s long-term debt was based on quoted market prices when available or estimated using quoted market prices for similar debt. The fair value of this debt at December 31, 2018 and 2017 were $3.3 billion and $2.9 billion, respectively.

 

All other financial instruments on the balance sheet such as accounts receivable, accounts payable, and notes receivable from and payable to associated companies are stated at cost, which approximates fair value.

 


  1. EMPLOYEE BENEFITS

 

The Company participates in two non-contributory defined benefit pension plans (the “Pension Plans”) and two PBOP plans (the “PBOP Plans,” together with the Pension Plans, the “Plans”). The Company calculates benefits under these plans based on age, years of service and pay using March 31 as a measurement date. In addition, the Company also participates in defined contribution plans for eligible employees. The plans are sponsored by National Grid USA Service Company.

 

Plan assets are maintained in commingled trusts. In respect of cost determination, plan assets are allocated to the Company based on the Company’s proportionate share of the Plan’s projected benefit obligation. The Plan’s costs are first directly charged to the Company based on the Company’s employees that participate in the Plan. Costs associated with affiliated service companies’ employees are then allocated as part of the labor burden for work performed on the Company’s behalf. The Company applies deferral accounting for pension and PBOP expenses associated with its regulated gas and electric operations. Any differences between actual pension costs and amounts used to establish rates are deferred and collected from, or refunded to, customers in subsequent periods. Pension and PBOP expense are included within operation expenses in the accompanying statements of income. Portions of the net periodic benefit costs disclosed below have been capitalized as a component of property, plant and equipment.

 

Pension Plans

 

The Pension Plans are composed of both a qualified and a non-qualified plan. The qualified pension plan provides substantially all union employees, as well as all non-union employees hired before January 1, 2011, with a retirement benefit. The qualified pension plan is a cash balance pension plan design in which pay-based credits are applied based on service time and interest credits are applied at rates set forth in the plan. For non-union employees, effective January 1, 2011, pay-based credits are based on a combination of service time and age. The non-qualified pension plans provide additional defined pension benefits to certain eligible executives. The funding policy is determined largely by the Company’s rate agreements with the NYPSC. However, the contribution to the qualified pension plan for any year will not be less than the minimum amount required under Internal Revenue Service (“IRS”) regulations. During the years ended December 31, 2018 and 2017, the Company made contributions of approximately $10.3 million and $28.3 million, respectively, to the qualified pension plans. The Company expects to contribute approximately $4.5 million to the Pension Plans during the year ending December 31, 2019.

 

PBOP Plans

 

The Company’s PBOP Plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must contribute to the cost of their coverage. The PBOP Plans are funded based on rate agreements with the NYPSC. During the years ended December 31, 2018 and 2017, the Company made contributions of approximately $16.1 million and $44.5 million, respectively, to the PBOP Plans. The Company does not expect to contribute to the PBOP Plans during the year ending December 31, 2019.

 

Defined Contribution Plan

 

NGUSA has a defined contribution pension plan that covers substantially all employees. For the years ended December 31, 2018 and 2017, the Company recognized an expense in the accompanying statements of income of $10.3 million and $9.0 million, respectively, for matching contributions.

 

Net Periodic Benefit Costs

 

The Company’s total pension cost for the years ended December 31, 2018 and 2017 are $46.9 million and $34.4 million, respectively. The Company recognized an estimated settlement loss of $8.0 million as part of total pension costs during the current fiscal year due to plan payouts that exceeded the threshold as prescribed in ASC 715.

 

The Company’s total PBOP cost for the years ended December 31, 2018 and 2017 are $15.5 million and $39.2 million, respectively.

 

Amounts Recognized in AOCI and Regulatory Assets

 

The following tables summarize other pre-tax changes in plan assets and benefit obligations recognized primarily in regulatory assets and accumulated other comprehensive income for the years ended December 31, 2018 and 2017:

 

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Amounts Recognized in AOCI and Regulatory Assets – not yet recognized as components of net actuarial loss

 

The following tables summarize the Company's amounts in regulatory assets and other comprehensive income on the accompanying balance sheet that have not been recognized as components of net actuarial loss at December 31, 2018 and 2017:

 

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The NYPSC’s statement of policy requires that prior service costs and gains and losses be amortized over a ten-year period calculated on a vintage year basis. The amount of net actuarial loss and prior service cost to be amortized from regulatory assets during the year ending December 31, 2019 for the Pension Plans is $42.5 million and $2 million, respectively, and net actuarial loss and prior service benefit to be amortized from regulatory assets during the year ending December 31, 2019 for the PBOP Plans is $7.1 million and $0.04 million, respectively.

 

 

 

 

 

Reconciliation of Funded Status to Amount Recognized

 

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Expected Benefit Payments

 

Based on current assumptions, the Company expects to make the following benefit payments subsequent to December 31, 2018:

 

 

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Assumptions Used for Employee Benefits Accounting

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The Company selects its discount rate assumption based upon rates of return on highly rated corporate bond yields in the marketplace as of each measurement date. Specifically, the Company uses the Hewitt AA Above Median Curve along with the expected future cash flows from the Company retirement plans to determine the weighted average discount rate assumption.

 

The expected rate of return for various passive asset classes is based both on analysis of historical rates of return and forward-looking analysis of risk premiums and yields. Current market conditions, such as inflation and interest rates, are evaluated in connection with the setting of the long-term assumptions. A small premium is added for active management of both equity and fixed income securities. The rates of return for each asset class are then weighted in accordance with the actual asset allocation, resulting in a long-term return on asset rate for each plan.

 

Assumed Health Cost Trend Rate

 

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Plan Assets

 

The National Grid Retirement Plans Committee is the fiduciary who manages the benefit plan investments to minimize the long-term cost of operating the Plans, with a reasonable level of risk. Risk tolerance is determined as a result of a periodic asset/liability study which analyzes the Plans’ liabilities and funded status and results in the determination of the allocation of assets across equity fixed income securities and other investments. Equity investments are broadly diversified across U.S. and non-U.S. stocks, as well as across growth, value, and small and large capitalization stocks. Likewise, the fixed income portfolio is broadly diversified across market segments. Approximately ten percent of the total investment portfolio is approved for investments in private equity, real estate, and infrastructure with the objective of enhancing long-term returns while improving portfolio diversification. For the PBOP Plans, since the earnings on a portion of the assets are taxable, those investments are managed to maximize after tax returns consistent with the broad asset class parameters established by the asset allocation study. Investment performance is reviewed by the National Grid Retirement Plans Committee on a quarterly basis.

 

The Pension Plan is a trusted non-contributory defined benefit plan covering all eligible represented employees of the Company and eligible non-represented employees of the participating National Grid companies. The PBOP Plans are both a contributory and non-contributory, trusteed, employee life insurance and medical benefit plan sponsored by the Service Company. Life insurance and medical benefits are provided for eligible retirees, dependents, and surviving spouses of the Company.

 

The target asset allocations for the benefit plans as of December 31, 2018 and 2017 are as follows:

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Fair Value Measurements

 

The following tables provide the fair value measurements amounts for the pension and PBOP assets:

 

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The methods used to fair value pension and PBOP assets are described below:

 

Cash and cash equivalents: Cash and cash equivalents that can be priced daily are classified as Level 1. Active reserve funds, reserve deposits, commercial paper, repurchase agreements, and commingled cash equivalents are classified as Level 2. Cash and cash equivalents invested in commingled money market investment funds which have net asset value (“NAV”) pricing per fund share are excluded from the fair value hierarchy.

 

Accounts receivable and accounts payable: Accounts receivable and accounts payable are classified as Level 1. Such amounts are short-term and settle within a few days of the measurement date.

 

Equity and preferred securities: Common stocks, preferred stocks, and real estate investment trusts are valued using the official close of the primary market on which the individual securities are traded. Equity securities are primarily comprised of securities issued by public companies in domestic and foreign markets plus investments in commingled funds, which are valued on a daily basis. The Company can exchange shares of the publicly traded securities and the fair values are primarily sourced from the closing prices on stock exchanges where there is active trading, in which case they are classified as Level 1 investments. If there is less active trading, then the publicly traded securities would typically be priced using observable data, such as bid and ask prices, and these measurements are classified as Level 2 investments. Mutual funds with publicly quoted prices and active trading are classified as Level 1 investments. For investments in commingled funds that are not publicly traded and have ongoing subscription and redemption activity, the fair value of the investment is the NAV per fund share, derived from the underlying securities’ quoted prices in active markets, and they are excluded from the fair value hierarchy. Investments in commingled funds with redemption restrictions and that use NAV are excluded from the fair value hierarchy.

 

Global tactical asset allocation: Assets held in global tactical asset allocation funds are managed by investment managers who use both top-down and bottom-up valuation methodologies to value asset classes, countries, industrial sectors, and individual securities in order to allocate and invest assets opportunistically. Mutual funds with publicly quoted prices and active trading are classified as Level 1 investments. For commingled funds that are not publicly traded and have ongoing subscription and redemption activity, the fair value of the investment is the NAV per fund share, and is excluded from the fair value hierarchy. Investments with redemption restrictions and that use NAV are excluded from the fair value hierarchy.

 

Fixed income securities: Fixed income securities (which include corporate debt securities, municipal fixed income securities, U.S. Government and Government agency securities including government mortgage backed securities, index linked government bonds, and state and local bonds) convertible securities, and investments in securities lending collateral (which include repurchase agreements, asset backed securities, floating rate notes and time deposits) are valued with an institutional bid valuation. A bid valuation is an estimated price at which a dealer would pay for a security (typically in an institutional round lot). Oftentimes, these evaluations are based on proprietary models which pricing vendors establish for these purposes. In some cases there may be manual sources when primary vendors do not supply prices. Fixed income investments are primarily comprised of fixed income securities and fixed income commingled funds. The prices for direct investments in fixed income securities are generated on a daily basis. Prices generated from less active trading with wider bid ask prices are classified as Level 2 investments. Mutual funds with publicly quoted prices and active trading are classified as Level 1 investments. For commingled funds that are not publicly traded and have ongoing subscription and redemption activity, the fair value of the investment is the NAV per fund share, and is excluded from the fair value hierarchy. Investments in commingled funds with redemption restrictions and that use NAV are excluded from the fair value hierarchy.

 

Private equity and real estate: Commingled equity funds, commingled special equity funds, limited partnerships, real estate, venture capital, and other investments are valued using evaluations (NAV per fund share) based on proprietary models, or based on the NAV. Investments in private equity and real estate funds are primarily invested in privately held real estate investment properties, trusts, and partnerships as well as equity and debt issued by public or private companies. The Company’s interest in the fund or partnership is estimated based on the NAV. The Company’s interest in these funds cannot be readily redeemed due to the inherent lack of liquidity and the primarily long-term nature of the underlying assets. Distribution is made through the liquidation of the underlying assets. The Company views these investments as part of a long-term investment strategy. These investments are valued by each investment manager based on the underlying assets. The funds utilize valuation techniques consistent with the market, income, and cost approaches to measure the fair value of certain real estate investments. The majority of the underlying assets are valued using significant unobservable inputs and often require significant management judgment or estimation based on the best available information. Market data includes observations of the trading multiples of public companies considered comparable to the private companies being valued. Investments in limited partnerships with redemption restrictions and that use NAV are excluded from the fair value hierarchy.

 

While management believes its valuation methodologies are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the NAV as a practical expedient could result in a different fair value measurement at the reporting date.

 

Other Benefits

 

At December 31, 2018 and 2017, the Company had accrued workers compensation, auto, and general insurance claims which have been incurred but not yet reported (“IBNR”) of $12.5 million and $13.2 million, respectively. IBNR reserves have been established for claims and/or events that have transpired, but have not yet been reported to the Company for payment.

 


  1. ACCUMULATED OTHER COMPREHENSIVE INCOME

 

The following table represents the changes in the Company’s AOCI for the years ended December 31, 2018 and 2017:

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(1) Amounts are reported as net other income and deductions in the accompanying statements of income.

 


  1. CAPITALIZATION

 

Long-term Debt

 

Long-term debt at December 31, 2018 and 2017 is as follows:

 

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The aggregate maturities of long-term debt for the years subsequent to December 31, 2018 are as follows:

 

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The Company’s debt agreements and banking facilities contain covenants, including those relating to the periodic and timely provision of financial information by the issuing entity and financial covenants such as restrictions on the level of indebtedness. Failure to comply with these covenants, or to obtain waivers of those requirements, could in some cases trigger a right, at the lender’s discretion, to require repayment of some of the Company’s debt and may restrict the Company’s ability to draw upon its facilities or access the capital markets. During the years ended December 31, 2018 and 2017, the Company was in compliance with all such covenants.

 

Debt Authorizations

 

Since January 12, 2015, the Company had regulatory approval from the FERC to issue up to $1 billion of short-term debt, internally or externally. The authorization was renewed with an effective date of January 11, 2019 for a period of two years that expires on January 10, 2021. The Company had no external short-term debt as of December 31, 2018 and 2017. Refer to Note 15, “Related Party Transactions” under “Notes Receivable from and Notes Payable to Associated Companies (“Intercompany Money Pool”)” for short-term debt outstanding to associated companies.

 

Since May 19, 2016, the NYPSC authorized the Company to issue up to $2.1 billion of incremental long-term debt in one or more transactions through March 31, 2020. The Company can issue up to $429.5 million of the total authorization for optional refunding of existing debt. On November 29, 2018, the Company issued $500 million of unsecured senior long-term debt at 4.28% with a maturity date of December 15, 2028.

 

State Authority Financing Bonds

 

The assets of the Company were subject to liens and other charges and were provided as collateral over borrowings of $429.5 million of State Authority Financing Bonds at December 31, 2017. These bonds were issued to secure a like amount of tax-exempt revenue bonds issued by the New York State Energy Research and Development Authority (“NYSERDA”). In September 2018, the Company converted six of the eight series of the State Authority Financing Bonds from a variable rate into a fixed rate. In October 2018, the remaining two series were converted from a variable rate into a fixed rate as well. The fixed rates on the bonds range from 3.23% to 3.48%. During the conversions, the Company was discharged of liens and charges associated with these bonds, and $5.3 million of the $50 million 1986 Series A bond with the maturity date of December 1, 2026 was redeemed. These conversions were accounted for as extinguishments in accordance with ASC 470, “Debt.” Prior to conversion, the bonds bore interest at short-term adjustable interest rates (with an option to convert to other rates, including a fixed interest rate) ranging from 0.69% to 5.53% and 0.66% to 4.13% for the years ended December 31, 2018 and 2017, respectively.

 

Advances from Associated Companies

 

Since January 2015, the Company had FERC and board authorization to borrow up to $500 million from NGUSA from time to time for working capital needs. The advance is non-interest bearing. At December 31, 2018 and 2017, the Company had no outstanding advance from associated companies.

 

In June 2009, the Company received board authorization to borrow up to $450 million from NMHI from time to time for working capital needs. At December 31, 2018 and 2017, the Company had no outstanding advance from associated companies.

 

Dividend Restrictions

 

The Company’s debt and credit arrangements contain various financial and other covenants as described below. The Company was in compliance with all such covenants during the years ended December 31, 2018 and 2017.

 

The Company is limited by the various rate plans, NYPSC orders, and FERC orders with respect to the amount of dividends the Company can pay. If the Company’s total debt exceeds 55% of its total capital excluding goodwill but does not exceed 57%, then the Company will be permitted to pay dividends up to an amount equal to but no greater than 50% of its net income for the previous twelve months until its average total debt for the most recent six month period is less than or equal to 55%. If the Company’s total capital exceeds 57% then the Company may not pay dividends until the average total debt for the most recent six months ending is less than or equal to 55%. As long as the bond ratings on the least secure forms of debt issued by the Company and National Grid plc remain investment grade and do not fall to the lowest investment grade rating (with one or more negative watch downgrade notices issued with respect to such debt), the Company is allowed to pay dividends.

 

The Company’s filed rate plan includes a ratemaking capital structure of approximately 52% debt and 48% equity through the combination of long-term debt issuance and dividend payments. In September 2017, the Company paid dividends on common stock of $550 million to NMHI to align the capital structure more closely to its filed rate plan.

 

Cumulative Preferred Stock

 

The Company has certain issues of non-participating cumulative preferred stock outstanding which can be redeemed at the option of the Company. There are no mandatory redemption provisions on the Company’s cumulative preferred stock. A summary of cumulative preferred stock is as follows:

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In connection with the acquisition of KeySpan by NGUSA, the Company became subject to a requirement to issue a class of preferred stock, having one share (the “Golden Share”), subordinate to any existing preferred stock. The holder of the Golden Share would have voting rights that limit the Company’s right to commence any voluntary bankruptcy, liquidation, receivership, or similar proceeding without the consent of the holder of the Golden Share. The NYPSC subsequently authorized the issuance of the Golden Share to a trustee, GSS Holdings, Inc. (“GSS”), who will hold the Golden Share subject to a Services and Indemnity Agreement requiring GSS to vote the Golden Share in the best interests of NYS. On July 8, 2011, the Company issued the Golden Share with a par value of $1.

 

The Company did not redeem any preferred stock during the years ended December 31, 2018 or 2017. The annual dividend requirement for cumulative preferred stock was $1.1 million for each of the years ended December 31, 2018 and 2017.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  1. INCOME TAXES

 

Components of Income Tax Expense

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  1. Investment tax credits (“ITC”) are being deferred and amortized over the depreciable life of the property giving rise to the credits.

 

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Statutory Rate Reconciliation

 

The Company’s effective tax rates for the years ended December 31, 2018 and 2017 are 23.8% and 33.7%, respectively. The following table presents a reconciliation of income tax expense at the federal statutory tax rate of 21% and 31.6%, respectively, to the actual tax expense:

 

[image]

 

The Company is included in the NGNA and subsidiaries consolidated federal income tax return and New York unitary state income tax return. The Company has joint and several liability for any potential assessments against the consolidated group.

 

Tax Reform

 

On December 22, 2017, the Tax Act was signed into law. The Tax Act includes significant changes to various federal tax provisions applicable to the Company, including provisions specific to regulated public utilities. The most significant changes include the reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018 and the limitation of the net operating loss deduction for net operating losses generated in tax years starting after December 31, 2017 to 80% of taxable income with an indefinite carryforward period. The Tax Act provisions related to regulated public utilities eliminate bonus depreciation for certain property acquired or placed in service after September 27, 2017 and extend the normalization requirements for ratemaking treatment of excess deferred taxes.

 

On August 3, 2018, the IRS released proposed regulations associated with the expanded depreciation rules enacted as part of the Tax Act. The proposed regulations would enable utilities to claim additional bonus depreciation on property acquired and placed in service between September 28, 2017 and March 31, 2018. The company adopted the guidance in the proposed regulations and revised the impact of the income tax effect of the Tax Act to reflect the additional six months of bonus depreciation.

 

On December 22, 2017, the Securities Exchange Commission issued Staff Accounting Bulletin ("SAB") 118, which provides guidance on accounting for the effects of the Tax Act. The FASB staff subsequently issued guidance stating that private companies may apply SAB 118 to the financial statements. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date to complete the accounting under ASC 740. To the extent that a company's accounting for certain income tax effects of the Tax Act is incomplete, a company can determine a reasonable estimate for those effects and record a provisional estimate in the financial statements. If a company cannot determine a provisional amount, the company should continue to apply existing accounting guidance for income taxes based on provisions of the tax laws that were in effect immediately prior to the enactment of the Tax Act.

 

On November 15, 2018, FERC issued a Notice of Proposed Rulemaking (“NOPR”) in which it is proposing to require all public utility transmission providers with transmission rates under an Open Access Transmission Tariff (“OATT”), a transmission owner tariff, or a rate schedule to revise those rates to account for changes caused by the Tax Act. Specifically, for transmission formula rates, the Commission is proposing to require that public utilities deduct excess Accumulated Deferred Income Taxes (ADIT) from their rate bases and adjust their income tax allowances by amortized excess ADIT. The Commission is also proposing to require all public utilities with transmission formula rates to incorporate a new permanent worksheet into their transmission formula rates that will annually track ADIT information. Additionally, the Commission is proposing to require all public utilities with transmission stated rates to determine the amount of excess and deferred income tax caused by the Tax Act’s reduction to the federal corporate income tax rate and return or recover this amount to or from customers. The company plans to implement the NOPR requirements once it is finalized.

 

During the period ending December 31,2018, the Company adjusted its remeasurement of federal deferred tax assets and liabilities to the enacted tax rate of 21% and recognized the impact of the Tax Act. The Company recognized a net decrease in its deferred tax liability in the amount of $700 million with $2 million recorded to deferred income tax expense and $702 million recorded as a regulatory deferred tax liability for the refund of excess deferred income taxes to the ratepayers. The resulting measurement of the impact of the Tax Act was a decrease in the deferred tax assets and liabilities in accounts 190, 282, and 283 of $700 million and a tax regulatory liability in account 254 of $950 million. The protected excess ADIT is $607.2 million and unprotected excess ADIT is $92.8 million. The company is not currently amortizing the amounts into rates and an amortization period has not been agreed between the company and the regulator. Once agreed, the excess ADIT will be amortized to account 411 and the unfunded ADIT will be amortized to account 410.

 

Deferred Tax Components

[image]

 

 

(1) The Company established a valuation allowance for deferred tax assets related to expiring charitable contribution carryforwards in the amounts of $1.3 million and $1.2 million as of December 31, 2018 and December 31, 2017, respectively.

 

Unrecognized Tax Benefits

 

The Company adopted the provisions of FASB guidance which clarifies the accounting for uncertain tax positions as modified by FERC Docket AI07-2-000. FASB guidance provides that the financial effects of a tax position shall initially be recognized when it is more likely than not, based on the technical merits, that the position will be sustained upon examination, assuming the position will be audited, and the taxing authority has full knowledge of all relevant information. FERC docket AI07-2-000 issues supplementary guidance requiring entities to continue to recognize deferred income taxes for Commission accounting and reporting purposes based on the difference between positions taken in tax returns filed or expected to be filed and amounts reported in the financial statements. As of December 31, 2018 and December 31, 2017, the Company did not have any unrecognized tax benefits on a FERC basis.

 

As of December 31, 2018, and 2017, the Company has accrued for interest related to unrecognized tax benefits of $36.0 million and $25.7 million, respectively. During years ended December 31, 2018 and 2017 the Company recorded interest expense of $10.3 million and $8.0 million, respectively. The Company recognizes interest related to unrecognized tax benefits in other interest, including affiliate interest and related penalties, if applicable, in other deductions, net, in the accompanying statements of income. No tax penalties were recognized during the years ended December 31, 2018 and 2017.

 

It is reasonably possible that other events will occur during the next twelve months that would cause the total amount of unrecognized tax benefits to increase or decrease. However, the Company does not believe any such increases or decreases would be material to its results of operations, financial position, or cash flows.

 

During the period, the Company reached a settlement with the IRS for the tax years ended March 31, 2008 and March 31, 2009. The outcome of the settlement did not have a material impact to its results of operations, financial position, or cash flows. The IRS continues its examination of the next cycle which includes income tax returns for the years ended March 31, 2010 through March 31, 2012. The examination is not expected to conclude in the next fiscal year. The income tax returns for the years ended March 31, 2013 through March 31, 2018 remain subject to examination by the IRS.

 

During the period, the state of New York concluded its examination of Niagara Mohawk Holdings, Inc. & Combined Affiliates’ income tax returns for the years ended March 31, 2009 through March 31, 2012. The examination resulted in a capital tax refund of $3.3 million. The income tax returns for the years ended March 31, 2014 through March 31, 2018 remain subject to examination by the state of New York.

 

 

The following table indicates the earliest tax year subject to examination:

 

[image]

 

  1. ENVIRONMENTAL MATTERS

 

The normal ongoing operations and historic activities of the Company are subject to various federal, state, and local environmental laws and regulations. Under federal and state Superfund laws, potential liability for the historic contamination of property may be imposed on responsible parties jointly and severally, without regard to fault, even if the activities were lawful when they occurred.

 

The United States Environmental Protection Agency ("EPA"), and the New York State Department of Environmental Conservation ("DEC"), as well as private entities, have alleged that the Company is a potentially responsible party under state or federal law for the remediation of numerous sites. The Company’s most significant liabilities relate to former Manufactured Gas Plant (“MGP”) facilities formerly owned or operated by the Company. The Company is currently investigating and remediating, as necessary, those MGP sites and certain other properties under agreements with the EPA and the DEC. Expenditures incurred for the years ended December 31, 2018 and 2017 were $8.6 million and $11.8 million, respectively.

 

The Company estimated the remaining costs of environmental remediation activities were $369.8 million and $359.6 million at December 31, 2018 and 2017, respectively. The Company had a current portion of environmental remediation costs of $30.1 million included in other miscellaneous current and accrued liabilities on the balance sheet at December 31, 2018. These costs are expected to be incurred over approximately 41 years. However, remediation costs for each site may be materially higher than estimated, depending on changing technologies and regulatory standards, selected end use for each site, and actual environmental conditions encountered. The Company has recovered amounts from certain insurers and potentially responsible parties, and, where appropriate, the Company may seek additional recovery from other insurers and from other potentially responsible parties, but it is uncertain whether, and to what extent, such efforts will be successful.

 

By rate orders issued and effective April 1, 2018, the NYPSC has provided an annual rate allowance of $32.1 million ($27.3 million in electric base rates and $4.8 million in gas base rates). Any annual spend above the $32.1 million rate allowance is deferred for future recovery. Previous rate orders have provided for similar recovery mechanisms (with different rate allowances and thresholds). Accordingly, as of December 31, 2018 and 2017, the Company has recorded environmental regulatory assets of $369.8 million and $359.6 million, respectively, and environmental regulatory liabilities of $54.3 million and $82.3 million, respectively.

 

The Company believes that its ongoing operations, and its approach to addressing conditions at historic sites, are in substantial compliance with all applicable environmental laws. Where the Company has regulatory recovery, it believes that the obligations imposed on it because of the environmental laws will not have a material impact on its results of operations or financial position.

 

  1. COMMITMENTS AND CONTINGENCIES

 

Operating Lease Obligations

 

The Company has various operating leases relating to office space. Total rental expense for operating leases included in operation expenses in the accompanying statements of income was $4.4 million and $4.3 million for the years ended December 31, 2018 and 2017, respectively.

 

The future minimum lease payments for the years subsequent to December 31, 2018 are as follows:

 

[image]

 

Purchase Commitments

 

The Company has several long-term contracts for the purchase of electric power. Substantially all of these contracts require power to be delivered before the Company is obligated to make payment. Additionally, the Company has entered into various contracts for gas delivery, storage, and supply services. Certain of these contracts require payment of annual demand charges, which are recoverable from customers. The Company is liable for these payments regardless of the level of service required from third-parties.

 

 

 

The Company’s commitments under these long-term contracts for the years subsequent to December 31, 2018 are summarized in the table below:

 

[image]

The Company purchases additional energy to meet load requirements from independent power producers, other utilities, energy merchants or the New York Independent System Operator at market prices.

 

Legal Matters

 

The Company is subject to various legal proceedings arising out of the ordinary course of its business. The Company does not consider any of such proceedings to be material, individually or in the aggregate, to its business or likely to result in a material adverse effect on its results of operations, financial position, or cash flows.

 

Nuclear Contingencies

 

As of December 31, 2018 and 2017, the Company had a liability of $173.0 million and $169.8 million, respectively, recorded in other deferred credits on the balance sheet, for the disposal of nuclear fuel irradiated prior to 1983. The Nuclear Waste Policy Act of 1982 provides three payment options for liquidating such liability and the Company has elected to delay payment, with interest, until the year in which Constellation Energy Group Inc., which purchased the Company’s nuclear assets, initially plans to ship irradiated fuel to an approved Department of Energy (“DOE”) disposal facility.

 

The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository. A Blue Ribbon Commission (“BRC”) on America’s Nuclear Future, appointed by the U.S. Energy Secretary, released a report on January 26, 2012, detailing comprehensive recommendations for creating a safe, long-term solution for managing and disposing of the nation’s spent nuclear fuel and high-level radioactive waste.

 

In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste” in response to the BRC recommendations. This strategy included a consolidated interim storage facility that was planned to be operational in 2025. However, due to continued delays on the part of the DOE, and the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term spent nuclear fuel storage, the Company cannot predict the date at which the DOE will begin accepting spent nuclear fuel.

 

  1. RELATED PARTY TRANSACTIONS

 

Accounts Receivable from and Accounts Payable to Associated Companies

 

NGUSA and its affiliates provide various services to the Company, including executive and administrative, customer services, financial (including accounting, auditing, risk management, tax, and treasury/finance), human resources, information technology, legal, and strategic planning, that are charged between the companies and charged to each company.

 

The Company records short-term receivables from, and payables to, certain of its associated companies in the ordinary course of business. The amounts receivable from, and payable to, its associated companies do not bear interest and are settled through the intercompany money pool. A summary of outstanding accounts receivable from associated companies and accounts payable to associated companies is as follows:

 

[image]

 

Notes Receivable from and Notes Payable to Associated Companies (“Intercompany Money Pool”)

 

The settlement of the Company’s various transactions with NGUSA and certain associated companies generally occurs via the intercompany money pool in which it participates. The Company is a participant in the Regulated Money Pool and can both borrow and invest funds. Borrowings from the Regulated Money Pool bear interest in accordance with the terms of the Regulated Money Pool Agreement. As the Company fully participates in the Regulated Money Pool rather than settling intercompany charges with cash, all changes in the intercompany money pool balance and accounts receivable from associated companies and accounts payable to associated companies balances are reflected as investing or financing activities in the accompanying statements of cash flows. In addition, for the purpose of presentation in the statements of cash flows, it is assumed all amounts settled through the intercompany money pool are constructive cash receipts and payments, and therefore are presented as such.

 

The Regulated Money Pool is funded by operating funds from participants. NGUSA has the ability to borrow up to $3 billion from National Grid plc for working capital needs including funding of the Regulated Money Pool, if necessary. The Company had short-term intercompany money pool investments of $600.5 million and $182.9 million at December 31, 2018 and 2017, respectively. The average interest rates for the intercompany money pool were 2.2% and 1.4% for the years ended December 31, 2018 and 2017, respectively.

 

Service Company Charges

 

The affiliated service companies of NGUSA provide certain services to the Company at their cost. The service company costs are generally allocated to associated companies through a tiered approach. First and foremost, costs are directly charged to the benefited company whenever practicable. Secondly, in cases where direct charging cannot be readily determined, costs are allocated using cost/causation principles linked to the relationship of that type of service, such as number of employees, number of customers/meters, capital expenditures, value of property owned, and total transmission and distribution expenditures. Lastly, all other costs are allocated based on a general allocator determined using a 3-point formula based on net margin, net utility plant, and operations and maintenance expense.

 

Charges from the service companies of NGUSA, including but not limited to non-power goods and services, to the Company for the years ended December 31, 2018 and 2017 were $390.2 million and $384.6 million, respectively.


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
  1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
  2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
  3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
  4. Report data on a year-to-date basis.
Line No.
Item
(a)
Unrealized Gains and Losses on Available-For-Sale Securities
(b)
Minimum Pension Liability Adjustment (net amount)
(c)
Foreign Currency Hedges
(d)
Other Adjustments
(e)
Other Cash Flow Hedges Interest Rate Swaps
(f)
Other Cash Flow Hedges [Specify]
(g)
Totals for each category of items recorded in Account 219
(h)
Net Income (Carried Forward from Page 116, Line 78)
(i)
Total Comprehensive Income
(j)
1
Balance of Account 219 at Beginning of Preceding Year
2,018,403
691,699
1,326,704
2
Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income
654,357
62,708
591,649
3
Preceding Quarter/Year to Date Changes in Fair Value
1,620,547
85,531
1,706,078
4
Total (lines 2 and 3)
966,190
148,239
1,114,429
255,973,372
257,087,801
5
Balance of Account 219 at End of Preceding Quarter/Year
2,984,593
543,460
2,441,133
6
Balance of Account 219 at Beginning of Current Year
2,984,593
543,460
2,441,133
7
Current Quarter/Year to Date Reclassifications from Account 219 to Net Income
772,796
75,104
697,692
8
Current Quarter/Year to Date Changes in Fair Value
1,639,521
69,627
1,709,148
9
Total (lines 7 and 8)
2,412,317
5,477
2,406,840
198,308,115
195,901,275
10
Balance of Account 219 at End of Current Quarter/Year
572,276
537,983
34,293


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION

Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.

Line No.
Classification
(a)
Total Company For the Current Year/Quarter Ended
(b)
Electric
(c)
Gas
(d)
Other (Specify)
(e)
Other (Specify)
(f)
Other (Specify)
(g)
Common
(h)
1
UtilityPlantAbstract
UTILITY PLANT
2
UtilityPlantInServiceAbstract
In Service
3
UtilityPlantInServiceClassified
Plant in Service (Classified)
12,010,474,229
9,319,338,435
2,428,883,314
262,252,480
4
UtilityPlantInServicePropertyUnderCapitalLeases
Property Under Capital Leases
5
UtilityPlantInServicePlantPurchasedOrSold
Plant Purchased or Sold
6
UtilityPlantInServiceCompletedConstructionNotClassified
Completed Construction not Classified
554,122,253
487,271,941
53,655,392
13,194,920
7
UtilityPlantInServiceExperimentalPlantUnclassified
Experimental Plant Unclassified
8
UtilityPlantInServiceClassifiedAndUnclassified
Total (3 thru 7)
12,564,596,482
9,806,610,376
2,482,538,706
275,447,400
9
UtilityPlantLeasedToOthers
Leased to Others
3,425,127
3,425,127
10
UtilityPlantHeldForFutureUse
Held for Future Use
11
ConstructionWorkInProgress
Construction Work in Progress
438,319,836
375,115,349
56,908,567
6,295,920
12
UtilityPlantAcquisitionAdjustment
Acquisition Adjustments
1,289,132,075
1,061,730,253
227,401,822
13
UtilityPlantAndConstructionWorkInProgress
Total Utility Plant (8 thru 12)
14,295,473,520
11,246,881,105
2,766,849,095
281,743,320
14
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Accumulated Provisions for Depreciation, Amortization, & Depletion
3,964,093,617
2,980,582,307
889,411,623
94,099,687
15
UtilityPlantNet
Net Utility Plant (13 less 14)
10,331,379,903
8,266,298,798
1,877,437,472
187,643,633
16
DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract
DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17
AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract
In Service:
18
DepreciationUtilityPlantInService
Depreciation
3,958,516,026
2,975,387,283
889,029,056
94,099,687
19
AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService
Amortization and Depletion of Producing Natural Gas Land and Land Rights
20
AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService
Amortization of Underground Storage Land and Land Rights
21
AmortizationOfOtherUtilityPlantUtilityPlantInService
Amortization of Other Utility Plant
4,462,069
4,079,502
382,567
22
DepreciationAmortizationAndDepletionUtilityPlantInService
Total in Service (18 thru 21)
3,962,978,095
2,979,466,785
889,411,623
94,099,687
23
DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract
Leased to Others
24
DepreciationUtilityPlantLeasedToOthers
Depreciation
1,115,522
1,115,522
25
AmortizationAndDepletionUtilityPlantLeasedToOthers
Amortization and Depletion
26
DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers
Total Leased to Others (24 & 25)
1,115,522
1,115,522
27
DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract
Held for Future Use
28
DepreciationUtilityPlantHeldForFutureUse
Depreciation
29
AmortizationUtilityPlantHeldForFutureUse
Amortization
30
DepreciationAndAmortizationUtilityPlantHeldForFutureUse
Total Held for Future Use (28 & 29)
31
AbandonmentOfLeases
Abandonment of Leases (Natural Gas)
32
AmortizationOfPlantAcquisitionAdjustment
Amortization of Plant Acquisition Adjustment
33
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Total Accum Prov (equals 14) (22,26,30,31,32)
3,964,093,617
2,980,582,307
889,411,623
94,099,687


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
  1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent.
  2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Line No.
Description of item
(a)
Balance Beginning of Year
(b)
Changes during Year Additions
(c)
Changes during Year Amortization
(d)
Changes during Year Other Reductions (Explain in a footnote)
(e)
Balance End of Year
(f)
1
Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)
2
Fabrication
3
Nuclear Materials
4
Allowance for Funds Used during Construction
5
(Other Overhead Construction Costs, provide details in footnote)
6
SUBTOTAL (Total 2 thru 5)
7
Nuclear Fuel Materials and Assemblies
8
In Stock (120.2)
9
In Reactor (120.3)
10
SUBTOTAL (Total 8 & 9)
11
Spent Nuclear Fuel (120.4)
12
Nuclear Fuel Under Capital Leases (120.6)
13
(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)
14
TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)
15
Estimated Net Salvage Value of Nuclear Materials in Line 9
16
Estimated Net Salvage Value of Nuclear Materials in Line 11
17
Est Net Salvage Value of Nuclear Materials in Chemical Processing
18
Nuclear Materials held for Sale (157)
19
Uranium
20
Plutonium
21
Other (Provide details in footnote)
22
TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
  1. Report below the original cost of electric plant in service according to the prescribed accounts.
  2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
  3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
  4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments.
  5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
  6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year.
  7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications.
  8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages.
  9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line No.
Account
(a)
Balance Beginning of Year
(b)
Additions
(c)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at End of Year
(g)
1
1. INTANGIBLE PLANT
2
(301) Organization
3
(302) Franchise and Consents
6,357,778
6,357,778
4
(303) Miscellaneous Intangible Plant
1,029,954
239,349
1,269,303
5
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)
7,387,732
239,349
7,627,081
6
2. PRODUCTION PLANT
7
A. Steam Production Plant
8
(310) Land and Land Rights
9
(311) Structures and Improvements
10
(312) Boiler Plant Equipment
11
(313) Engines and Engine-Driven Generators
12
(314) Turbogenerator Units
13
(315) Accessory Electric Equipment
14
(316) Misc. Power Plant Equipment
15
(317) Asset Retirement Costs for Steam Production
16
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
17
B. Nuclear Production Plant
18
(320) Land and Land Rights
19
(321) Structures and Improvements
20
(322) Reactor Plant Equipment
21
(323) Turbogenerator Units
22
(324) Accessory Electric Equipment
23
(325) Misc. Power Plant Equipment
24
(326) Asset Retirement Costs for Nuclear Production
25
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26
C. Hydraulic Production Plant
27
(330) Land and Land Rights
28
(331) Structures and Improvements
29
(332) Reservoirs, Dams, and Waterways
30
(333) Water Wheels, Turbines, and Generators
31
(334) Accessory Electric Equipment
32
(335) Misc. Power Plant Equipment
33
(336) Roads, Railroads, and Bridges
34
(337) Asset Retirement Costs for Hydraulic Production
35
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36
D. Other Production Plant
37
(340) Land and Land Rights
246,109
207
1,607,861
1,853,763
38
(341) Structures and Improvements
39
(342) Fuel Holders, Products, and Accessories
40
(343) Prime Movers
41
(344) Generators
42
(345) Accessory Electric Equipment
43
(346) Misc. Power Plant Equipment
44
(347) Asset Retirement Costs for Other Production
44.1
(348) Energy Storage Equipment - Production
45
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)
246,109
207
1,607,861
1,853,763
46
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)
246,109
207
1,607,861
1,853,763
47
3. Transmission Plant
48
(350) Land and Land Rights
103,742,379
4,305,914
11,997
108,036,296
48.1
(351) Energy Storage Equipment - Transmission
49
(352) Structures and Improvements
48,619,758
248,638
175,338
16,378
48,709,436
50
(353) Station Equipment
1,148,682,879
128,240,740
5,630,812
310,183
1,270,982,624
51
(354) Towers and Fixtures
120,686,567
811,920
636,329
460,405
121,322,563
52
(355) Poles and Fixtures
781,652,057
55,018,177
14,380,049
110,141
850,940,142
53
(356) Overhead Conductors and Devices
550,678,689
28,470,778
907,511
65,534
578,176,422
54
(357) Underground Conduit
39,880,702
2,385,930
42,266,632
55
(358) Underground Conductors and Devices
137,248,504
11,289,705
1,274,534
147,263,675
56
(359) Roads and Trails
4,545,322
5,167,071
9,712,393
57
(359.1) Asset Retirement Costs for Transmission Plant
546,264
546,264
58
TOTAL Transmission Plant (Enter Total of lines 49 thru 59)
2,936,283,121
235,938,873
5,743,528
9,075
3,177,956,447
59
4. Distribution Plant
60
(360) Land and Land Rights
48,409,664
6,608,342
1,722
55,019,728
61
(361) Structures and Improvements
48,652,647
1,191,258
256,823
49,587,082
62
(362) Station Equipment
762,519,339
51,638,940
1,428,000
54,289
812,675,990
63
(363) Energy Storage Equipment – Distribution
64
(364) Poles, Towers, and Fixtures
1,151,114,304
45,373,473
4,359,147
305,748
1,191,822,882
65
(365) Overhead Conductors and Devices
1,288,425,398
42,967,224
3,103,845
1,646,605
357,105
1,326,285,067
66
(366) Underground Conduit
207,523,756
9,498,328
1,926,996
8,484
215,086,604
67
(367) Underground Conductors and Devices
662,615,586
28,369,489
3,086,115
106,156
688,005,116
68
(368) Line Transformers
965,539,780
50,989,485
5,348,443
6,950
1,011,187,772
69
(369) Services
499,733,944
12,544,219
3,644,119
235,045
508,869,089
70
(370) Meters
151,639,683
22,332,902
2,043,433
171,929,152
71
(371) Installations on Customer Premises
7,594,742
412,109
162,101
7,844,750
72
(372) Leased Property on Customer Premises
73
(373) Street Lighting and Signal Systems
273,609,318
10,896,472
7,456,493
7,235
277,056,532
74
(374) Asset Retirement Costs for Distribution Plant
1,690,172
3,676
1,693,848
75
TOTAL Distribution Plant (Enter Total of lines 62 thru 76)
6,069,068,333
282,822,241
32,813,793
1,659,740
353,429
6,317,063,612
76
5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77
(380) Land and Land Rights
78
(381) Structures and Improvements
79
(382) Computer Hardware
80
(383) Computer Software
81
(384) Communication Equipment
82
(385) Miscellaneous Regional Transmission and Market Operation Plant
83
(386) Asset Retirement Costs for Regional Transmission and Market Oper
84
TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85
6. General Plant
86
(389) Land and Land Rights
2,341,028
2,341,028
87
(390) Structures and Improvements
105,238,361
4,783,795
398,595
45,541
109,578,020
88
(391) Office Furniture and Equipment
4,954,886
3,669,803
626,129
45,541
8,044,101
89
(392) Transportation Equipment
8,063,206
8,063,206
90
(393) Stores Equipment
64,869
4,518
60,351
91
(394) Tools, Shop and Garage Equipment
45,691,464
3,507,577
1,302,658
47,896,383
92
(395) Laboratory Equipment
12,832,440
321,886
521,859
12,632,467
93
(396) Power Operated Equipment
279,275
279,275
94
(397) Communication Equipment
65,609,663
5,005,620
383,550
48,043
70,279,776
95
(398) Miscellaneous Equipment
41,707,357
540,179
42,247,536
96
SUBTOTAL (Enter Total of lines 86 thru 95)
286,782,549
17,828,860
3,237,309
48,043
301,422,143
97
(399) Other Tangible Property
98
(399.1) Asset Retirement Costs for General Plant
733,058
45,728
687,330
99
TOTAL General Plant (Enter Total of lines 96, 97, and 98)
287,515,607
17,828,860
3,283,037
48,043
302,109,473
100
TOTAL (Accounts 101 and 106)
9,300,254,793
537,075,432
30,353,509
12,911
353,429
9,806,610,376
101
(102) Electric Plant Purchased (See Instr. 8)
102
(Less) (102) Electric Plant Sold (See Instr. 8)
103
(103) Experimental Plant Unclassified
104
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)
9,300,254,793
537,075,432
30,353,509
12,911
353,429
9,806,610,376


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line No.
LesseeName
Name of Lessee
(a)
IndicationOfAssociatedCompany
* (Designation of Associated Company)
(b)
LeaseDescription
Description of Property Leased
(c)
CommissionAuthorization
Commission Authorization
(d)
ExpirationDateOfLease
Expiration Date of Lease
(e)
ElectricPlantLeasedToOthers
Balance at End of Year
(f)
1
Mill Street Hydro
Land and Water Rights
(a)
02/19/1919
(i)
12/14/2026
104,999
2
Watertown, NY
3
Authorized by NYPSC
4
Case 10150
5
Hydro Development Group, Inc
Hydroelectric Plant and Land
(b)
12/16/1993
(j)
12/31/2023
390,790
6
Rights
7
Theresa, NY
8
Authorized by NYPSC
9
Case 28629
10
Hydro Development Group, Inc
Hydroelectric Plant and Land
(c)
12/16/1993
(k)
12/31/2023
415,014
11
Rights, Watertown, NY
12
Authorized by NYPSC
13
Case 28689
14
Union Falls Hydropower
Hydroelectric Plant and Land
(d)
09/15/1986
(l)
06/30/2024
410,947
15
Rights, Town of Black Brook, NY
16
Authorized by NYPSC
17
Case 28689
18
Middle Falls Limited Partnership
Hydroelectric Plant and Land
(e)
08/19/1988
(m)
04/25/2029
514,603
19
Rights, Town of Easton and
20
Greenwich
21
Authorized by NYPSC
22
Case 88-E-087
23
South Glens Falls Limited
Water and Land Rights
(f)
12/17/1991
(n)
09/20/2034
710,562
24
Village of South Glens Falls
25
Case 91-E-1119
26
Northern Electric Power
Land and Water Rights, Former
(g)
12/17/1991
(o)
11/20/2035
280,334
27
Company, L.P.
Hudson Falls Hydro Station
28
Authorized by NYPSC
29
Case 91-E-1119
30
Northern Electric Power
Land and Water Rights, Former
(h)
12/17/1991
(p)
11/20/2035
597,878
31
Company, L.P.
Moreau Hydro Station
32
Town of Moreau
33
Authorized by NYPSC
34
Case 91-E-1119
47
TOTAL
3,425,127


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: CommissionAuthorization
Original value: 02/19/1919
(b) Concept: CommissionAuthorization
Original value: 12/16/1993
(c) Concept: CommissionAuthorization
Original value: 12/16/1993
(d) Concept: CommissionAuthorization
Original value: 09/15/1986
(e) Concept: CommissionAuthorization
Original value: 08/19/1988
(f) Concept: CommissionAuthorization
Original value: 12/17/1991
(g) Concept: CommissionAuthorization
Original value: 12/17/1991
(h) Concept: CommissionAuthorization
Original value: 12/17/1991
(i) Concept: ExpirationDateOfLease
Original value: 12/14/2026
(j) Concept: ExpirationDateOfLease
Original value: 12/31/2023
(k) Concept: ExpirationDateOfLease
Original value: 12/31/2023
(l) Concept: ExpirationDateOfLease
Original value: 06/30/2024
(m) Concept: ExpirationDateOfLease
Original value: 04/25/2029
(n) Concept: ExpirationDateOfLease
Original value: 9/20/2034
(o) Concept: ExpirationDateOfLease
Original value: 11/20/2035
(p) Concept: ExpirationDateOfLease
Original value: 11/20/2035

Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
  1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held for future use.
  2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.
ElectricPlantHeldForFutureUseDescription
Description and Location of Property
(a)
ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Date Originally Included in This Account
(b)
ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Date Expected to be used in Utility Service
(c)
ElectricPlantHeldForFutureUse
Balance at End of Year
(d)
1 Land and Rights:
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Other Property:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
  1. Report below descriptions and balances at end of year of projects in process of construction (107).
  2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts).
  3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.
ConstructionWorkInProgressProjectDescription
Description of Project
(a)
ConstructionWorkInProgress
Construction work in progress - Electric (Account 107)
(b)
1
Electric
2
DISTRIBUTION:
3
Ohio St - Buffalo River Tunnel/Bore
12,510,848
4
Collamer Crossing_D_Sub_Work
8,384,694
5
Sodeman Rd Station - new station -
7,720,118
6
I&M - NC D-Line OH Work From Insp.
6,923,142
7
I&M - NE D-Line OH Work From Insp.
6,889,626
8
I&M - NW D-Line OH Work From Insp.
6,000,291
9
Buffalo Station 59 Rebuild - Sub
5,533,801
10
New Two Mile Creek Dist Sub
5,371,855
11
Lehigh Add 2nd Transformer
4,550,597
12
East NY-Genl Equip Budgetary Reserv
2,914,629
13
Pin#2805.32 Route 5s Utica
2,859,135
14
NC ARP Breakers & Reclosers
2,692,151
15
Van Dyke Station - New 115/13.2kV s
2,516,796
16
Cable Replacement - Ntwk Secondary
2,262,273
17
MV-Poland 62258 Route 8 Reconducto
2,163,994
18
Buffalo Street Light Cable Replacem
2,094,966
19
Demand Reduction REV Demonstration
1,807,170
20
Spectrum Broadband Expansion
1,735,191
21
NYW Mobile Sub #10 115-5kV/12MVA
1,688,452
22
New Maple Ave Substation
1,638,250
23
PS&I Activity Dist Gen NY.
1,633,549
24
West Hamlin #82 - New TB2 - Install
1,509,624
25
New 115-13.2kV Mobile Sub #11W
1,508,561
26
Altamont TB1 Replacement
1,435,555
27
Kenmore Station 22 Battery Storage
1,424,953
28
Buffalo Station 122 Rebuild - Sub
1,319,974
29
Cable Replacement - Ntwk Sec NYE
1,284,171
30
East NY-Dist-New Bus-Resid Blanket.
1,168,543
31
Cent NY-Dist-New Bus-Resid Blanket
1,159,363
32
*Menands 10151 / 52 Relocations
1,140,833
33
West NY-General-Genl Equip Blanket
1,138,657
34
Stoner 52 - Mohawk Dr Conversion
1,132,622
35
West NY-Dist-New Bus-Resid Blanket.
1,117,193
36
Spare 115kV-13.8kV Transformer NYW
1,111,800
37
Cent NY-Dist-Damage/Failure Blankt
1,023,879
38
Two Mile Creek F101151& F68451 Tie
960,499
39
Recloser Communications - Central
953,154
40
REV - FEEDER MONITORS
942,274
41
Sodeman Rd - Feeder Getaways
939,883
42
INVP 4473-US Con-UNY Voice Upg
924,228
43
*NR-Higley 92451-NYS Hwy 56-FdrTie
914,651
44
NE ARP Breakers & Reclosers
899,539
45
BAT18_Roof
867,586
46
East NY-Dist-Reliability Blanket.
841,516
47
RTU M9000 Distribution
818,274
48
Lysander 29754_Swgr 6 to 52a
802,282
49
Buffalo Sta 56- upgrade 4 Xfmrs
797,650
50
Hopkins 253 - Replace Metalclad Gea
781,270
51
West NY-Dist-Asset Replace Blanket.
778,180
52
New Cicero Substation DSub
776,489
53
Cent NY-Dist-Reliability Blanket.
765,614
54
New Two Mile Creek D-Line
760,712
55
Temple Relay repl for Ash St line
745,771
56
West NY-Dist-New Bus-Comm Blanket.
741,298
57
Delameter TB1 Replacement
732,951
58
Cent NY-General-Genl Equip Blanket
716,291
59
Minor projects
49,104,257
60
Transmission
61
Gardenville-Rebuild Line Relocation
13,447,371
62
Rebuild Huntley Station Asset Separ
13,296,534
63
NY Inspection Repairs - Capital
9,404,133
64
Schaghticoke Switching Station
8,590,228
65
Clay-Teall#10,Clay-Dewitt#3 Recond
7,951,811
66
Lasher Road Substation
7,910,263
67
Ohio Street new 115 - 34.5kV sub
6,849,980
68
Oswego - 115kV & 34.5kV - Rebuild
6,657,163
69
Gard-Dun 141-142 N Phase Rebuild
6,124,773
70
Rotterdam - Curry #11 recond
5,325,256
71
Purchase Spare Transformers
5,137,960
72
Central Breaker Upgrades - Ash
4,702,151
73
Albany-Greenbush 1&2 Reconductoring
3,809,749
74
Rotterdam-Reconfig Bus& add breaker
3,648,314
75
Ticonderoga- Inst Cap Bank, Rpl OCB
3,428,331
76
Gardenville Rebuild
3,405,237
77
Alabama-Telegraph 115 T1040 ACR.
3,207,150
78
Ballston-Mechanicville 6-34.5kv
3,119,878
79
W. Ashville substation TxT
2,936,802
80
Trans Station Failure Budget Blankt
2,516,258
81
Conductor Clearance - NY Program
2,286,264
82
I&M - NW Sub-T Line Work From Insp.
2,207,075
83
Battle Hill - replace 3 OCBs
2,150,817
84
W. Portland -Sherman 867-34.5kV
2,086,835
85
CAP OH 5210 NYT1000
2,031,155
86
Land-Clay-Teall#10,Clay-Dewitt #3
1,897,813
87
Packard Relays line 191 to 195
1,757,209
88
Scriba Relay Replacement
1,639,203
89
Batavia Second 115 kV Cap Bank
1,569,067
90
Rosa Rd add 115kV Cap Bank
1,550,019
91
I&M - NE Sub-T Line Work From Insp.
1,440,763
92
Relocate S. Dow-Poland 865-34.5kV
1,358,423
93
Mortimer #3 Auto TRF Replace
1,355,410
94
I&M - NC Sub-T Line Work From Insp.
1,299,810
95
Telegraph Road TRF #2 Asset Replace
1,208,279
96
Volney station Relay Replacement
1,160,502
97
Independence - Physical Security
1,148,226
98
Golah Cap Bank Installation
1,120,244
99
Huntley-Lockport 36 37 ACR
1,103,260
100
Frontier 181 ACR/Recond
1,071,019
101
Lafayette - Physical Security
1,051,891
102
TransLine D/F Budget Blanket
1,024,901
103
Ash St. 115-12kV TRF1 Asset replace
1,006,762
104
Seneca Reactor 71E asset replace
995,468
105
Machias - Replace TB#2
928,495
106
Ticonderoga 2-3 T5810-T5830 ACR
888,039
107
Schaghticoke Tap Sw St - Line taps
884,838
108
Edic: Protection Migration
719,819
109
Royal (New Harper) TxT Substation
715,772
110
Schuyler - replace OCBs
710,101
111
RTUs M9000 protocol upgrades Trans
694,182
112
Schaghticoke Control House
689,344
113
345kV Laminated Cross-arm-Program
670,513
114
GE-Geres Lock 8 T2240 Reconductor
645,843
115
Breaker T Repl Program 4-69kV NYW
640,824
116
Collamer Crossing_115kV_Line_TAP
635,434
117
Woodard - Replace three OCBs
627,498
118
Amsterdam-Rotterdam3/4 Relocation
627,050
119
Rotterdam Breaker Replacement
607,163
120
W. ASHVILLE SUB CONTROL HOUSE
600,315
121
Elm St Relief_Add 4th Xfer
598,161
122
NYISO Comm Protocols Support
574,794
123
WD - Install ScadaMates on the 301
573,478
124
Rotterdam - Add Reactors LN19/20
561,557
125
Dunkirk Rebuild
556,594
126
Callanan Tap - Rebuild exist 34.5ln
538,563
127
Feura Bush Relay Replacement
520,496
128
Oswego: 115kV Control House
517,213
129
BatteryRplStrategyCo36TxT
504,599
130
Lasher Rd Transmission Line
444,610
131
Minor Projects
27,518,672
43
375,115,349


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
  1. Explain in a footnote any important adjustments during year.
  2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
  3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications.
  4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Line No.
Item
(a)
Total (c + d + e)
(b)
Electric Plant in Service
(c)
Electric Plant Held for Future Use
(d)
Electric Plant Leased To Others
(e)
Section A. Balances and Changes During Year
1
AccumulatedProvisionForDepreciationOfElectricUtilityPlant
Balance Beginning of Year
2,816,981,648
2,815,898,669
1,082,979
2
Depreciation Provisions for Year, Charged to
3
DepreciationExpenseExcludingAdjustments
(403) Depreciation Expense
222,614,321
222,614,321
4
DepreciationExpenseForAssetRetirementCosts
(403.1) Depreciation Expense for Asset Retirement Costs
5
ExpensesOfElectricPlantLeasedToOthers
(413) Exp. of Elec. Plt. Leas. to Others
32,543
32,543
6
TransportationExpensesClearing
Transportation Expenses-Clearing
7
OtherClearingAccounts
Other Clearing Accounts
8
OtherAccounts
Other Accounts (Specify, details in footnote):
9.1
6,992,236
6,992,236
10
DepreciationProvision
TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)
229,639,100
229,606,557
32,543
11
Net Charges for Plant Retired:
12
BookCostOfRetiredPlant
Book Cost of Plant Retired
30,297,506
30,297,506
13
CostOfRemovalOfPlant
Cost of Removal
55,033,936
55,033,936
14
SalvageValueOfRetiredPlant
Salvage (Credit)
10,847,663
10,847,663
15
NetChargesForRetiredPlant
TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)
74,483,779
74,483,779
16
OtherAdjustmentsToAccumulatedDepreciation
Other Debit or Cr. Items (Describe, details in footnote):
17.1
9,015,480
9,015,480
17.2
Transfer
4,649,644
4,649,644
18
BookCostOfAssetRetirementCosts
Book Cost or Asset Retirement Costs Retired
19
AccumulatedProvisionForDepreciationOfElectricUtilityPlant
Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)
2,976,502,805
2,975,387,283
1,115,522
Section B. Balances at End of Year According to Functional Classification
20
AccumulatedDepreciationSteamProduction
Steam Production
62,411
62,411
21
AccumulatedDepreciationNuclearProduction
Nuclear Production
22
AccumulatedDepreciationHydraulicProductionConventional
Hydraulic Production-Conventional
1,115,180
1,115,180
23
AccumulatedDepreciationHydraulicProductionPumpedStorage
Hydraulic Production-Pumped Storage
342
342
24
AccumulatedDepreciationOtherProduction
Other Production
109,108
109,108
25
AccumulatedDepreciationTransmission
Transmission
652,081,061
652,081,061
26
AccumulatedDepreciationDistribution
Distribution
2,131,907,250
2,131,907,250
27
AccumulatedDepreciationRegionalTransmissionAndMarketOperation
Regional Transmission and Market Operation
28
AccumulatedDepreciationGeneral
General
191,227,453
191,227,453
29
AccumulatedProvisionForDepreciationOfElectricUtilityPlant
TOTAL (Enter Total of lines 20 thru 28)
2,976,502,805
2,975,387,283
1,115,522


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
  1. Report below investments in Account 123.1, Investments in Subsidiary Companies.
  2. Provide a subheading for each company and list thereunder the information called for below. Sub-TOTAL by company and give a TOTAL in columns (e), (f), (g) and (h). (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal.
  3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1.
  4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge.
  5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number.
  6. Report column (f) interest and dividend revenues from investments, including such revenues from securities disposed of during the year.
  7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if different from cost) and the selling price thereof, not including interest adjustment includible in column (f).
  8. Report on Line 42, column (a) the TOTAL cost of Account 123.1.
Line No.
DescriptionOfInvestmentsInSubsidiaryCompanies
Description of Investment
(a)
DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Date Acquired
(b)
DateOfMaturityInvestmentsInSubsidiaryCompanies
Date of Maturity
(c)
InvestmentInSubsidiaryCompanies
Amount of Investment at Beginning of Year
(d)
EquityInEarningsOfSubsidiaryCompanies
Equity in Subsidiary Earnings of Year
(e)
InterestAndDividendRevenueFromInvestments
Revenues for Year
(f)
InvestmentInSubsidiaryCompanies
Amount of Investment at End of Year
(g)
InvestmentGainLossOnDisplosal
Gain or Loss from Investment Disposed of
(h)
1
NM Properties, Inc.
2
Common Stock, 3075 shares, $1 par value
3,075
3,075
3
Paid in Capital
3,308,818
3,308,818
4
Unappropriated Undistributed Subsidiary
2,533,287
10,759
34,040
2,578,086
42
Total Cost of Account 123.1 $
Total
778,606
10,759
34,040
733,807


FOOTNOTE DATA

(a) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 1993-1997

Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
MATERIALS AND SUPPLIES
  1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
  2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.
Line No.
Account
(a)
Balance Beginning of Year
(b)
Balance End of Year
(c)
Department or Departments which Use Material
(d)
1
Fuel Stock (Account 151)
2
Fuel Stock Expenses Undistributed (Account 152)
3
Residuals and Extracted Products (Account 153)
4
Plant Materials and Operating Supplies (Account 154)
5
Assigned to - Construction (Estimated)
34,132,374
32,655,176
Electric / Gas
6
Assigned to - Operations and Maintenance
7
Production Plant (Estimated)
8
Transmission Plant (Estimated)
4,705,318
4,501,679
Electric
9
Distribution Plant (Estimated)
8,215,485
7,859,931
Electric/Gas
10
Regional Transmission and Market Operation Plant (Estimated)
11
Assigned to - Other (provide details in footnote)
12
TOTAL Account 154 (Enter Total of lines 5 thru 11)
47,053,177
45,016,786
13
Merchandise (Account 155)
14
Other Materials and Supplies (Account 156)
15
Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16
Stores Expense Undistributed (Account 163)
17
18
19
20
TOTAL Materials and Supplies
47,053,177
45,016,786


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
Allowances (Accounts 158.1 and 158.2)
  1. Report below the particulars (details) called for concerning allowances.
  2. Report all acquisitions of allowances at cost.
  3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts.
  4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k).
  5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
  6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances.
  7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts).
  8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies.
  9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
  10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
Current Year Year One Year Two Year Three Future Years Totals
Line No.
SO2 Allowances Inventory (Account 158.1)
(a)
No.
(b)
Amt.
(c)
No.
(d)
Amt.
(e)
No.
(f)
Amt.
(g)
No.
(h)
Amt.
(i)
No.
(j)
Amt.
(k)
No.
(l)
Amt.
(m)
1
Balance-Beginning of Year
2
3
Acquired During Year:
4
Issued (Less Withheld Allow)
5
Returned by EPA
6
7
8
Purchases/Transfers:
9
10
11
12
13
14
15
Total
16
17
Relinquished During Year:
18
Charges to Account 509
19
Other:
20
Allowances Used
20.1
20.2
21
Cost of Sales/Transfers:
22
23
24
25
26
27
28
Total
29
Balance-End of Year
30
31
Sales:
32
Net Sales Proceeds(Assoc. Co.)
33
Net Sales Proceeds (Other)
34
Gains
35
Losses
Allowances Withheld (Acct 158.2)
36
Balance-Beginning of Year
37
Add: Withheld by EPA
38
Deduct: Returned by EPA
39
Cost of Sales
40
Balance-End of Year
41
42
Sales
43
Net Sales Proceeds (Assoc. Co.)
44
Net Sales Proceeds (Other)
45
Gains
46
Losses


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: AllowanceInventory

The balance in the allowance account (158.1 and 158.2) is related to renewable enegery credit, not for SO2 or NOx. Hence, this page is not applicable.


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
Allowances (Accounts 158.1 and 158.2)
  1. Report below the particulars (details) called for concerning allowances.
  2. Report all acquisitions of allowances at cost.
  3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts.
  4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k).
  5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
  6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances.
  7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts).
  8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies.
  9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
  10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
Current Year Year One Year Two Year Three Future Years Totals
Line No.
NOx Allowances Inventory (Account 158.1)
(a)
No.
(b)
Amt.
(c)
No.
(d)
Amt.
(e)
No.
(f)
Amt.
(g)
No.
(h)
Amt.
(i)
No.
(j)
Amt.
(k)
No.
(l)
Amt.
(m)
1
Balance-Beginning of Year
2
3
Acquired During Year:
4
Issued (Less Withheld Allow)
5
Returned by EPA
6
7
8
Purchases/Transfers:
9
10
11
12
13
14
15
Total
16
17
Relinquished During Year:
18
Charges to Account 509
19
Other:
20
Allowances Used
20.1
20.2
21
Cost of Sales/Transfers:
22
23
24
25
26
27
28
Total
29
Balance-End of Year
30
31
Sales:
32
Net Sales Proceeds(Assoc. Co.)
33
Net Sales Proceeds (Other)
34
Gains
35
Losses
Allowances Withheld (Acct 158.2)
36
Balance-Beginning of Year
37
Add: Withheld by EPA
38
Deduct: Returned by EPA
39
Cost of Sales
40
Balance-End of Year
41
42
Sales
43
Net Sales Proceeds (Assoc. Co.)
44
Net Sales Proceeds (Other)
45
Gains
46
Losses


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: AllowanceInventory

The balance in the allowance account (158.1 and 158.2) is related to renewable enegery credit, not for SO2 or NOx. Hence, this page is not applicable.


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
WRITTEN OFF DURING YEAR
Line No.
DescriptionOfExtraordinaryPropertyLoss
Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).]
(a)
ExtraordinaryPropertyLossesNotYetRecognized
Total Amount of Loss
(b)
ExtraordinaryPropertyLossesRecognized
Losses Recognized During Year
(c)
ExtraordinaryPropertyLossesWrittenOffAccountCharged
Account Charged
(d)
ExtraordinaryPropertyLossesWrittenOff
Amount
(e)
ExtraordinaryPropertyLosses
Balance at End of Year
(f)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
20 TOTAL


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
WRITTEN OFF DURING YEAR
Line No.
DescriptionOfUnrecoveredPlantAndRegulatoryStudyCosts
Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of COmmission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)]
(a)
UnrecoveredPlantAndRegulatoryStudyCostsNotYetRecognized
Total Amount of Charges
(b)
UnrecoveredPlantAndRegulatoryStudyCostsRecognized
Costs Recognized During Year
(c)
UnrecoveredPlantAndRegulatoryStudyCostsWrittenOffAccountCharged
Account Charged
(d)
UnrecoveredPlantAndRegulatoryStudyCostsWrittenOff
Amount
(e)
UnrecoveredPlantAndRegulatoryStudyCosts
Balance at End of Year
(f)
21
Electric Transmission Development
22
(Authorized in case 17-E-0238
23
effective April 2018);
24
Amortization: April 2018 to
25
March 2021
4,615,000
1,153,750
3,461,250
49
TOTAL
4,615,000
1,153,750
3,461,250


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
Transmission Service and Generation Interconnection Study Costs
  1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies.
  2. List each study separately.
  3. In column (a) provide the name of the study.
  4. In column (b) report the cost incurred to perform the study at the end of period.
  5. In column (c) report the account charged with the cost of the study.
  6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
  7. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.
DescriptionOfStudyPerformed
Description
(a)
StudyCostsIncurred
Costs Incurred During Period
(b)
StudyCostsAccountCharged
Account Charged
(c)
StudyCostsReimbursements
Reimbursements Received During the Period
(d)
StudyCostsAccountReimbursed
Account Credited With Reimbursement
(e)
1
Transmission Studies
2
(a)
ALPS HVDC SRISA Q448
1,240
19,581
3
(b)
NA Trans Q550 SRIS Dysinger II
3,134
4
(c)
NA Trans Q549 SRIS Nia-Dissin
2,099
5
(d)
NA Q548 SRISA Dysinger-Stolle
7,238
6
(e)
NextEra Energy NY Q537 SWA
5,128
7
(f)
NextEra Energy NY Q538 SRIS
5,788
8
(g)
NextEra Energy NY Q539 SRIS
5,932
9
(h)
NextEra Energy NY Q539 SWA
214
10
(i)
NA Trans Q556 SIS & SWA
12,884
12,884
11
(j)
NA Trans Segment B Q559 SIS & SWA
338
338
12
(k)
NA Trans Segment B Q559 SIS & SWA
8,397
12,677
13
(l)
NA Trans Segment A Q558 SIS & SWA
73
14
(m)
NA Trans Segment A Q558 SIS & SWA
3,802
15
(n)
NA Trans Segment A Q557 SIS & SWA
2,409
16
(o)
NA Trans Segment A Q555 SIS & SWA
2,375
17
(p)
HP Hood LLC Q601 FESA & SWA
5,365
13,215
18
(q)
NA Trans Q414 Segment B SWA
5,608
19
Q543- National Grid- Segment B -
601
20
Q543- National Grid- Segment B -
9,984
21
(r)
Q542-National Grid Seg A Edic SWA
6,985
22
Cedar Rapids Transmission Upgrade
27,910
75,426
23
New Scotland Power Express Q631
5,325
24
(s)
Q540-Edic PV SWA/SRIS Study Agmt
729
3,987
25
(t)
EDIC Rampo Q541 SWA/SRIS
657
3,652
26
(u)
Q595 North Park Energy FESA & SWA
9,876
14,709
27
(v)
Q638 FESA & SWA Empire State Holds
14,210
9,646
28
(w)
Q613 Sugar Maple FESA/SWA OneEnery
11,305
12,160
29
(x)
Q632_Alps-Berkshire SISA & SWA
2,008
1,083
30
(y)
Q595 North Park Energy SRIS
2,836
31
(z)
ITC Q684 FSA-SWA
41,484
33,029
32
(aa)
BEC Energy Storage Project FESQ707
1,123
33
(ab)
BEC Energy Storage Project FESQ708
2,021
2,021
34
(ac)
KCE NY6 Project Q759 FESA
725
35
(ad)
HP Hood LLC Q601 FSA
285
20
Total
21
Generation Studies
22
(ae)
Arkwright Q421---SWA
9,454
23
(af)
Erie Power Facilitiy Study SWA Q40
16
176,757
24
(ag)
Dunkirk Unit 2 Q523 SRISA
1,127
992
25
(ah)
Dunkirk Unit 3 & Unit 4 SRISA
255
992
26
(ai)
Roaring Brook Q546 FESA
1,007
2,608
27
(aj)
Great Valley Solar Q534 FESA
4
28
(ak)
Galloo Island Wind Farm Q468 SRISA
259
1,008
29
(al)
Double Lock Solar Q563 FESA
726
6,335
30
(am)
Atlantic Wind, LLC Q560 FESA
39,098
31
(an)
Tayandenega Solar, Q565 FESA
776
7,888
32
(ao)
Casadaga Wind Q387 FSA-SWA
131,711
149,120
33
(ap)
Hidden Meadow Q562 FESA
339
34
(aq)
Caledonia I Q585 FESA (AVON)
14,017
24,403
35
(ar)
Q514 Empire Wind SRIS & SWA
8,252
36
(as)
North Ridge Wind Q526 SIS
9,665
37
(at)
North Ridge Wind Q526 SWA
623
38
(au)
Q574 - Mad River Wind - FESA
298
9,574
39
(av)
Q523 Dunkirk Unit 2 FSA
14,534
35,570
40
(aw)
Q524 Dunkirk Unit 3-4 FSA
11,717
24,057
41
(ax)
Q511 Ogdensburg Generation FSA/SWA
9,914
51,172
42
(ay)
Q571 Heritage Wind FESA Study
895
15,562
43
(az)
Q596 Alle Catt II Wind - SRIS
6,695
13,179
44
(ba)
Q494 Alabama Wind SWA for FSA
59,062
83,413
45
(bb)
Q468 Galloo Wind SWA for FSA
48,839
72,242
46
(bc)
Q512 Northbrook Lyons SWA for FSA
23,016
21,974
47
(bd)
Franklin Solar FESA Agreement Q624
1,217
1,217
48
(be)
Ball Hill Wind SWA for FSA Q505
80,274
99,604
49
(bf)
Sun East -Hills Solar FESA Q581
8,834
12,202
50
(bg)
Watkins Rd Solar Q568 SWA
2,928
51
(bh)
Q534 Great Valley Solar SRISA
7,222
52
(bi)
Allegany Wind SRIS SWA
23,442
53
(bj)
Flint Mine Solar Q637 FESA & SWA
22,200
22,806
54
(bk)
Johnson Solar FESA Eng. Study Q600
3,328
7,971
55
(bl)
Albany County Solar Q598 - SRIS
4,792
8,252
56
Albany County Solar-Hecate Q570
4,043
7,772
57
(bm)
High River Solar Q618 SRIS
14,479
58
(bn)
East Point Solar Q619 SRIS
1,764
2,185
59
(bo)
Sunny Knoll Solar Q582 SRIS
6,065
60
(bp)
Woodruff Solar SRIS Q#610
3,146
61
(bq)
Tayandenega Solar - SRIS Q#565
10,298
62
(br)
Double Lock Solar - SRIS Q#563
10,061
63
(bs)
Rock District Solar - SRIS Q#564
6,285
64
(bt)
Tribes Hill Solar - SRIS Q#567
5,575
7,298
65
North Country (Boonville) Solar
6,350
13,780
66
(bu)
Sky High Solar Project Q545 SRIS
1,837
3,543
67
(bv)
Mohawk Solar Project Q616 SRIS
6,834
68
(bw)
Franklin Solar FESA Agreement Q624
1,217
1,217
69
(bx)
Johnson Solar FESA Eng. Study Q600
3,328
7,971
70
(by)
Franklin Solar SRIS Q624
5,007
71
(bz)
Heritage Wind SRIS Q571
8,504
8,504
72
(ca)
Roaring Brook Wind Q546 SISA/SWA
9,542
9,542
73
(cb)
Admiral Wind FESA/SWA Q655
16,310
15,545
74
(cc)
Mistral Wind FESA/SWA Q657
12,607
11,863
75
Liberty Dr. Solar Project Q660
4,487
76
(cd)
Arkwright Wind Farm FSA Q421
25,131
77
(ce)
Grissom Solar SWA-FES Q682
8,928
8,230
78
(cf)
West Point LLC HVDC FES Q615
7,512
79
(cg)
Atlantic Wind Q560 Deer River SRIS
3,233
80
(ch)
Q574 Mad River Wind SRIS/SWA
556
81
(ci)
Alder Creek Sola Q709 FESA
5,366
82
(cj)
Johnson Solar Q600 SIS
2,440
83
(ck)
York Solar Q725 FES
7,092
84
(cl)
Niagara Falls Solar Q726 FES
1,087
1,087
85
(cm)
Chaumont Solar Project LFIP Q705
1,104
1,104
86
(cn)
Horseshoe Solar FESA Q710
13,221
87
North Country (Boonville) Solar
4,648
88
(co)
Lyonsdale Solar Q723 FES
3,872
89
(cp)
Machias Solar LLC Q732 FES
1,690
90
(cq)
Arcade Solar LLC Q733 FES
412
91
(cr)
Sun East -Hills Solar SRIS Q581
2,943
92
(cs)
Cortland Energy Center Q718 FESA
3,263
93
(ct)
East Light Energy Center Q719 FESA
6,294
94
(cu)
Excelsior Energy Center Q721 FESA
167
95
(cv)
Hecate Cody Road Wind Q739 SRIS
2,194
96
(cw)
ELP Ticonderoga Solar Q734 FESA
4,651
97
(cx)
ELP Stillwater Solar Q735 FESA
5,314
98
(cy)
Q638 Empire State SRIS/SWA
2,717
99
(cz)
Coldwater Solar Project Q662 FESA
8,414
100
(da)
Skyline Solar Q670 FES
3,158
3,158
101
(db)
Clay Solar Q669 FES
3,760
3,172
102
(dc)
Martin Solar Q666 FES
4,726
103
(dd)
Bakerstand Solar Q667 SIS
4,420
104
(de)
Bear Ridge Solar Q704 SRIS/SWA
10,312
105
(df)
Quiet Meadows Solar Q729 FESA
2,298
1,578
106
(dg)
Invenergy #3 Wind Q531 FSA
69,487
55,666
107
(dh)
Q596 Alle Catt II Wind - FSA
39,215
22,456
108
(di)
Easton Solar 1 Project Q730 FES
3,898
109
(dj)
Easton Solar II Project Q731 FES
3,897
110
(dk)
Grissom Solar II Q748 FESA
1,263
111
(dl)
Goldenrod Solar Q752 FES
1,021
112
(dm)
Blue Star Solar Q753 FES
695
694
113
(dn)
Granada Solar Q757 Monarda FES
1,089
114
(do)
Sky High Solar FSA Q545
15,722
21,646
115
(dp)
Nextera Empire State Q545A FSA
19,591
10,042
116
(dq)
Admiral Wind SRIS Q655
162
117
(dr)
Mistral Wind SRIS Q657
364
118
(ds)
Q534 Great Valley Solar FSA
994
119
(dt)
Tracy Energy Solar Q774 FES
360
120
(du)
Skyline Solar Q670 SRIS
48
121
(dv)
Martin Solar Q666 SRIS
7,093
122
(dw)
Clay Solar Q669 SIS
1,039
123
(dx)
Q772 Hollyhock Solar Proj. FES
19,878
124
(dy)
Q773 Charboneau Solar Proj. SIS
1,353
125
(dz)
Cicero Solar Project Q763 FESA
1,976
126
(ea)
Mistral Wind 2 Project Q771 FES
286
127
(eb)
Q613 Sugar Maple SRIS/SWA OneEnery
4,102
128
(ec)
Q722 Gardner Capital FESA/SWA
256
129
(ed)
East Point Solar Q619 FSA
447
130
(ee)
Q570 Albany County Solar FSA
1,044
131
(ef)
Q598 Albany County Solar FSA
1,044
132
(eg)
Grissom Solar Q682 SIS
72
39
Total
40 Grand Total


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionOfStudyPerformed

HVDC - High Voltage Direct Current

SRISA - System Reliability Impact Study Agreement

(b) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(c) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(d) Concept: DescriptionOfStudyPerformed

SRISA - System Reliability Impact Study Agreement

(e) Concept: DescriptionOfStudyPerformed

SWA - Study Work Agreement

(f) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(g) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(h) Concept: DescriptionOfStudyPerformed

SWA - Study Work Agreement

(i) Concept: DescriptionOfStudyPerformed

SIS & SWA - System Impact Study and Study Work Agreement

(j) Concept: DescriptionOfStudyPerformed

SIS & SWA - System Impact Study and Study Work Agreement

(k) Concept: DescriptionOfStudyPerformed

SIS & SWA - System Impact Study and Study Work Agreement

(l) Concept: DescriptionOfStudyPerformed

SIS & SWA - System Impact Study and Study Work Agreement

(m) Concept: DescriptionOfStudyPerformed

SIS & SWA - System Impact Study and Study Work Agreement

(n) Concept: DescriptionOfStudyPerformed

SIS & SWA - System Impact Study and Study Work Agreement

(o) Concept: DescriptionOfStudyPerformed

SIS & SWA - System Impact Study and Study Work Agreement

(p) Concept: DescriptionOfStudyPerformed

FESA & SWA - Feasibility Study Agreement and Study Work Agreement

(q) Concept: DescriptionOfStudyPerformed

SWA - Study Work Agreement

(r) Concept: DescriptionOfStudyPerformed

SWA - Study Work Agreement

(s) Concept: DescriptionOfStudyPerformed

SWA - Study Work Agreement, SRIS - System Reliability Impact Study

(t) Concept: DescriptionOfStudyPerformed

SWA - Study Work Agreement, SRIS - System Reliability Impact Study

(u) Concept: DescriptionOfStudyPerformed

FESA & SWA - Feasibility Study Agreement and Study Work Agreement

(v) Concept: DescriptionOfStudyPerformed

FESA & SWA - Feasibility Study Agreement and Study Work Agreement

(w) Concept: DescriptionOfStudyPerformed

FESA & SWA - Feasibility Study Agreement and Study Work Agreement

(x) Concept: DescriptionOfStudyPerformed

SISA & SWA - System Impact Study Agreement and Study Work Agreement

(y) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(z) Concept: DescriptionOfStudyPerformed

FSA - Facilities Study Agreement, SWA - Study Work Agreement

(aa) Concept: DescriptionOfStudyPerformed

BEC - Bethlehem Energy Center, FES - Feasibility Study

(ab) Concept: DescriptionOfStudyPerformed

BEC - Bethlehem Energy Center, FES - Feasibility Study

(ac) Concept: DescriptionOfStudyPerformed

Key Capture Energy, Feasibility Study Agreement

(ad) Concept: DescriptionOfStudyPerformed

FSA - Facilities Study Agreement

(ae) Concept: DescriptionOfStudyPerformed

SWA - Study Work Agreement

(af) Concept: DescriptionOfStudyPerformed

SWA - Study Work Agreement

(ag) Concept: DescriptionOfStudyPerformed

SRISA - System Reliability Impact Study Agreement

(ah) Concept: DescriptionOfStudyPerformed

SRISA - System Reliability Impact Study Agreement

(ai) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(aj) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(ak) Concept: DescriptionOfStudyPerformed

SRISA - System Reliability Impact Study agreement

(al) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(am) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(an) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(ao) Concept: DescriptionOfStudyPerformed

FSA/SWA - Facility Study Agreement/Study Work Agreement

(ap) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(aq) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(ar) Concept: DescriptionOfStudyPerformed

SRIS & SWA - System Reliability Impact Study and Study Work Agreement

(as) Concept: DescriptionOfStudyPerformed

SIS - System Impact Study

(at) Concept: DescriptionOfStudyPerformed

SWA - Study Work Agreement

(au) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(av) Concept: DescriptionOfStudyPerformed

FSA - Facility Study Agreement

(aw) Concept: DescriptionOfStudyPerformed

FSA - Facility Study Agreement

(ax) Concept: DescriptionOfStudyPerformed

FSA/SWA - Facility Study Agreement/Study Work Agreement

(ay) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(az) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(ba) Concept: DescriptionOfStudyPerformed

FSA/SWA - Facility Study Agreement/Study Work Agreement

(bb) Concept: DescriptionOfStudyPerformed

FSA/SWA - Facility Study Agreement/Study Work Agreement

(bc) Concept: DescriptionOfStudyPerformed

FSA/SWA - Facility Study Agreement/Study Work Agreement

(bd) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(be) Concept: DescriptionOfStudyPerformed

FSA/SWA - Facility Study Agreement/Study Work Agreement

(bf) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(bg) Concept: DescriptionOfStudyPerformed

SWA - Study Work Agreement

(bh) Concept: DescriptionOfStudyPerformed

SRISA - System Reliability Impact Study Agreement

(bi) Concept: DescriptionOfStudyPerformed

SRIS SWA - System Reliability Impact Study Study Work Agreement

(bj) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

SWA - Study Work Agreement

(bk) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(bl) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(bm) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(bn) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(bo) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(bp) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(bq) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(br) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(bs) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(bt) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(bu) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(bv) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(bw) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(bx) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(by) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(bz) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(ca) Concept: DescriptionOfStudyPerformed

SISA/SWA - System Impact Study Agreement/Study Work Agreement

(cb) Concept: DescriptionOfStudyPerformed

FESA/SWA - Feasibility Study Agreement/Study Work Agreement

(cc) Concept: DescriptionOfStudyPerformed

FESA/SWA - Feasibility Study Agreement/Study Work Agreement

(cd) Concept: DescriptionOfStudyPerformed

FSA - Facility Study Agreement

(ce) Concept: DescriptionOfStudyPerformed

SWA-FES - Study Work Agreement Feasability Study

(cf) Concept: DescriptionOfStudyPerformed

HVDC - High Voltage Direct Current, FES - Feasibility Study

(cg) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(ch) Concept: DescriptionOfStudyPerformed

SRIS/SWA - System Reliability Impact Study/Study Work Agreement

(ci) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(cj) Concept: DescriptionOfStudyPerformed

SIS - System Impact Study

(ck) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(cl) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(cm) Concept: DescriptionOfStudyPerformed

LFIP - Large Facility Interconnection Procedures

(cn) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(co) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(cp) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(cq) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(cr) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(cs) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(ct) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(cu) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(cv) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(cw) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(cx) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(cy) Concept: DescriptionOfStudyPerformed

SRIS/SWA - System Reliability Impact Study/Study Work Agreement

(cz) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(da) Concept: DescriptionOfStudyPerformed

FES - Feasibility Study

(db) Concept: DescriptionOfStudyPerformed

FES - Feasibility Study

(dc) Concept: DescriptionOfStudyPerformed

FES - Feasibility Study

(dd) Concept: DescriptionOfStudyPerformed

SIS - System Impact Study

(de) Concept: DescriptionOfStudyPerformed

SRIS/SWA - System Reliability Impact Study/Study Work Agreement

(df) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(dg) Concept: DescriptionOfStudyPerformed

FSA - Facility Study Agreement

(dh) Concept: DescriptionOfStudyPerformed

FSA - Facility Study Agreement

(di) Concept: DescriptionOfStudyPerformed

FES - Feasibility Study

(dj) Concept: DescriptionOfStudyPerformed

FES - Feasibility Study

(dk) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(dl) Concept: DescriptionOfStudyPerformed

FES - Feasibility Study

(dm) Concept: DescriptionOfStudyPerformed

FES - Feasibility Study

(dn) Concept: DescriptionOfStudyPerformed

FES - Feasibility Study

(do) Concept: DescriptionOfStudyPerformed

FSA - Facility Study Agreement

(dp) Concept: DescriptionOfStudyPerformed

FSA - Facility Study Agreement

(dq) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(dr) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(ds) Concept: DescriptionOfStudyPerformed

FSA - Facility Study Agreement

(dt) Concept: DescriptionOfStudyPerformed

FES - Feasibility Study

(du) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(dv) Concept: DescriptionOfStudyPerformed

SRIS - System Reliability Impact Study

(dw) Concept: DescriptionOfStudyPerformed

SIS - System Impact Study

(dx) Concept: DescriptionOfStudyPerformed

FES - Feasibility Study

(dy) Concept: DescriptionOfStudyPerformed

SIS - System Impact Study

(dz) Concept: DescriptionOfStudyPerformed

FESA - Feasibility Study Agreement

(ea) Concept: DescriptionOfStudyPerformed

FES - Feasibility Study

(eb) Concept: DescriptionOfStudyPerformed

SRIS/SWA - System Reliability Impact Study/Study Work Agreement

(ec) Concept: DescriptionOfStudyPerformed

FESA/SWA - Feasibility Study Agreement/Study Work Agreement

(ed) Concept: DescriptionOfStudyPerformed

FSA - Facility Study Agreement

(ee) Concept: DescriptionOfStudyPerformed

FSA - Facility Study Agreement

(ef) Concept: DescriptionOfStudyPerformed

FSA - Facility Study Agreement

(eg) Concept: DescriptionOfStudyPerformed

SIS - System Impact Study


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
OTHER REGULATORY ASSETS (Account 182.3)
  1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
  2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes.
  3. For Regulatory Assets being amortized, show period of amortization.
CREDITS
Line No.
DescriptionAndPurposeOfOtherRegulatoryAssets
Description and Purpose of Other Regulatory Assets
(a)
OtherRegulatoryAssets
Balance at Beginning of Current Quarter/Year
(b)
IncreaseDecreaseInOtherRegulatoryAssets
Debits
(c)
OtherRegulatoryAssetsWrittenOffAccountCharged
Written off During Quarter/Year Account Charged
(d)
OtherRegulatoryAssetsWrittenOffRecovered
Written off During the Period Amount
(e)
OtherRegulatoryAssets
Balance at end of Current Quarter/Year
(f)
1
(a)
NY Energy Highway Transmission Dev. Costs
2
(b)
Regulatory Tax Asset
194,316,993
23,935,237
218,252,230
3
(c)
Deferred Environmental Restoration Costs
359,631,707
18,850,657
8,636,881
369,845,483
4
(d)
Storm Restoration Costs Deferred
114,401,845
56,159,416
164,340,818
6,220,443
5
(e)
Revenue Decoupling Mechanism - Electric
15,949,710
11,574,445
27,524,155
6
(f)
Asset Retirement Obligation Regulatory Asset
13,952,984
804,827
1,085,024
13,672,787
7
(g)
Gas Adjustment Clause
34,851,812
222,391,245
230,955,459
26,287,598
8
(h)
Gas Futures - Gas Supply
2,952,652
3,858,290
5,695,391
1,115,551
9
(i)
Electric Swaps - Electric Supply
26,359,388
114,889,725
141,249,113
10
(j)
Transportation Adjustment Clause Imbalance Surchare
94,209
94,209
11
(k)
Medicare Act Tax Benefit Deferral
3,230,756
2,430,579
800,177
12
(l)
Commodity Timing Impact
18,300,067
38,219,194
55,482,509
1,036,752
13
(m)
Clean Energy Standard
1,709,582
42,354,565
42,455,762
1,608,385
14
(n)
Interim Gass EE Def
3,994,862
121,370
3,873,492
15
(o)
Pension Benefits
133,002,964
23,769,015
94,972,196
61,799,783
16
(p)
Postretirement benefits other than pension
38,854,338
51,807,646
90,661,984
17
(q)
Deferral Summary Case 10-E-0050
3,149,393
2,244,877
904,516
18
(r)
Merchant Function Charge - Electric
214,805
10,820
225,625
19
(s)
Revenue Decoupling Mechanism - Gas
2,467,511
75,547
2,543,058
20
(t)
Excess AFUDC - Electric Plant in Service
92,806
1,438
18,679
75,565
21
(u)
Revenue Sharing Mechanism
1,258,194
397,956
860,238
22
(v)
Merchant Function Charge - Gas
308,818
200,498
509,316
23
(w)
Pension Expense Deferred
11,326,665
4,808,603
9,729,776
6,405,492
24
(x)
OPEB Expense Deferred
2,202,859
3,754,431
5,957,290
25
(y)
Electric Plant in Service Excess AFUDC
399,976
1,639
21,310
380,305
26
(z)
Incentive Return on Retirement Funding
34,491
25,577
8,914
27
(aa)
Gas Millenium Fund
132,957
132,957
28
(ab)
NYPA Residential Hydropower Benefit Reconciliation
1,626,236
1,626,236
29
(ac)
Legacy Transition Charge
1,992,909
7,458,161
8,940,448
510,622
30
(ad)
Electricity Supply Reconciliation Mechanism
3,788,073
83,401,630
78,444,222
8,745,481
31
(ae)
State Regulatory Tax Asset
1,583,353
1,583,353
32
(af)
Reforming the Energy Vision Proj - Incr Cap
64,531
215,249
83,844
195,936
33
(ag)
Reforming the Energy Vision Demo Proj - Incr O&M
4,880,044
2,428,327
2,347,900
4,960,471
34
(ah)
Deferred Community Carrying Charges Elec
48,097,948
38,327,948
86,425,896
35
(ai)
Deferred Community Carrying Charges Gas
1,160,078
143,229
1,303,307
36
(aj)
Enhanced SBC Program Deferral - Elec
12,755,322
22,602
12,732,720
37
(ak)
Vegetation Management Deferral
16,159,190
11,519,519
4,639,671
38
(al)
Dunkirk Settlement Deferral
57,000,000
40,634,482
16,365,518
39
(am)
Demand Response Programs Deferral
1,658,957
10,927
1,648,030
40
(an)
LED Facility Revenue/Charge Deferral
68,109
39,747
78
107,778
41
(ao)
LED Dist Lost Delivery Revenue Deferral
47,520
30,299
54
77,765
42
(ap)
LED Cost of Removal Deferral
3,264
176,168
3,264
176,168
43
(aq)
Rate Case Expense 12-E-0201- Electric
744,516
114,058
395,233
463,341
44
(ar)
Rate Case Expense 12-G-0202- Gas
609,149
93,320
317,850
384,619
45
(as)
Property Tax Expense Deferral- Elec
5,856,080
5,502,907
8,996,395
2,362,592
46
(at)
Merchant Function Charge (MFC) - Imbalance - Gas
21,548
2,850
18,698
47
(au)
System Performance Adjustment
680,822
1,254,206
816,653
1,118,375
48
(av)
Clean Energy Fund Deferral-Gas
4,096,966
28,746
4,125,712
49
(aw)
Clean Energy Fund Defberral-Elec
24,672,020
173,107
24,845,127
50
(ax)
Oil to Gas Conversion Deferral
1,305,122
137,181
1,425,497
16,806
51
(ay)
Management Audit - Electric
112,493
50,494
61,999
52
(az)
Management Audit - Gas
23,941
9,600
14,341
53
(ba)
Low Income EAP - Gas
2,779,278
88,851
2,690,427
54
(bb)
Low Income EAP - Electric
2,627,198
837,719
1,789,479
55
(bc)
ETIP Revenue Deferral - Gas
678,526
678,526
44
TOTAL
1,150,654,773
784,622,285
1,380,528,005
554,749,053


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

This account represents an allowance of nonrecurring costs associated with the Electric Transmission Energy Highway project that was transferred to account 182.2 - Unrecovered plant and regulatory study costs for a project that is not going into construction. In Rate Case 17-E-0238, the PSC allowed recovery of $4.615 million (Appendix 5, Schedule 1) with a 3-year amortization recovery period (April 2018 - March 2021). The balance will be amortized in the amount of $1.538 million each Rate Year from account 182.2.

(b) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The objectives of accounting for income taxes are to recognize (a) the amount of taxes payable or refundable for the current year, and (b) deferred tax liabilities and assets for the future tax consequences of events that have been recognized in the Company's financial statements or tax returns.

(c) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Section 10.1.6 of the Joint Proposal of 17-E-0238 and 17-E-0239 provides for the recoveries of Site Investigation and Remediation expenses. The Company will reconcile the expense to the annual rate allowance of $27.321 million for electric and $4.821 million for gas. Any under- or over-expenditures are deferred for future refund to, or recovery from customers.

(d) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Section 10.1.15 of the Joint Proposal of 17-E-0238, the Company is authorized a base rate allowance of $23 million each rate year. The Company will defer the difference between the base rate allowance and actual major storm incremental costs. Balance in account represents Storm Restoration Costs that are allowed to be deferred and have been deferred by the Company with permission from the PSC for future recoveries based on various rate years. These costs are allowed to be collected from customers. The expense deferred in account 1823006 should be analyzed in conjunction with account 2540314 which holds the respective allowances for storm deferrals which match up with the expenses deferred in 1823006.

(e) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The Company's Electric Tariff has a mechanism (PSC No. 220, Rule 57 effective April 2018 per Section 3.5 of rate case 17-E-0238) that permits the Company to defer the difference between revenue per customer targets and actual revenues.

(f) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The Company recovers cost of removal through its depreciation rates, as such the Company defers recognition of the effects of the asset retirement obligation.

(g) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

This account represents the monthly the Gas Adjustment Clause (GAC) deferral. The GAC deferral entry takes into account the difference between (1) the actual gas cost recoveries from customers and (2) the actual gas costs incurred by the Company for gas purchased from suppliers. The deferral is filed annually for the period of September to August and submitted to the PSC by October 15th. After the filing is made, the balance is transferred to an imbalance regulatory deferral account and is recovered or refunded to customers in the next calendar period.

(h) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

As commodity costs, including realized gains and losses on commodity derivatives, are refunded to or recovered from customers through the Company's gas recovery mechanism, a regulatory asset or liability is recorded as an offset to the unrealized gain or loss on a derivative asset in accordance with ASC 980 under US GAAP.

(i) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

As commodity costs, including realized gains and losses on commodity derivatives, are refunded to or recovered from customers through the Company's electric cost recovery mechanism, a regulatory asset or liability is recorded as an offset to the unrealized gain or loss on a derivative asset in accordance with ASC 980 under US GAAP.

(j) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

This account represents the Refund/Surcharge for prior years’ TAC (Transportation Adjustment Clause) imbalances (i.e. over/under collection). Dependent on the position/year of the imbalance amount, debits and/or credits can represent amortization of the imbalances and accrued interest on the declining balances. The account is filed annually for the period of September – August. Amortization of refund/surcharge occur from January to December and relate to prior GAC (Gas Adjustment Clause) Gas year September - August.

(k) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

This account represents asset related to Medicare Act Tax Benefit deferral to be recovered from customers. NMPC rate cases 12-E-0201 & 12-G-0202 includes the pro-rata allocation of deferral credits for this account. Effective April 2018, rate case 17-G-0239 required an additional pro rata allocation credit to create the Gas Rate Plan Deferral Credit. This mechanism is discontinued under case 17-G-0239.

(l) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Purpose of this account is to reconcile commodity expense in a given month with commodity revenue in the same month, with the difference being collected from or returned to customers.

(m) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

On August 1, 2016, the PSC issued an order (Case 15-E-0302) to implement a Large-Scale Renewable Program and Clean Energy Standards (CES). Under this program, the Company is required to purchase the percentage of Renewable Energy Credits to support new renewable generation sources and Zero Emission Credits to support Zero-Emission-nuclear power from NYSERDA and recover costs from ratepayers through commodity charges on customer bills.

(n) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

To establish recoverable incremental expenditure for interim gas programs and associated carrying charges for disposition in a future rate case pursuant to Case 07-M-0548 issued and effective March 4, 2015. Deferred with carrying charges using the Other Customer Capital Rate.

(o) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Account represents actuarial gain/loss on prior service cost that will be amortized into expense over a set period of time.

(p) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Account represents actuarial gain/loss on prior service cost that will be amortized into expense over a set period of time.

(q) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The purpose of this account is to amortize the deferral summary balance per rate case 10-E-0050. In line with rate case 12-E-0201, amortization of the balance has taken place, and the remaining balance of $3.1 million in the account will remain until the next rate case. Pursuant to the new electric rate case 17-E-0238, the Company was authorized to create an Electric Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for our customers. In April 2018, $2.245 million was transferred from the Deferral Summary case 10-E balance to the Electric Rate Plan Deferral Credit. This mechanism is discontinued under Case 17-E-0238.

(r) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The Merchant Function Charge (MFC) is applied to the customer’s bill when the customer receives electricity supply from the Company. This charge includes costs associated with commodity related credit and collections, commodity related uncollectible expense, electric supply procurement costs and working capital for electric supply. This charge is applied to the Electricity Supply portion of a customer’s bill. This charge will not be billed if the customer chooses and alternate supplier. Based on rate case 17-E-0238 the Company is allowed to defer the difference between the revenue for the MFC and the revenue requirement.

(s) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The Company's Gas Tariff has a mechanism (PSC No. 219, Rule 32 effective April 2018 per Section 4.6, of rate case 17-G-0239) that permits the Company to defer the difference between revenue per customer targets and actual revenues.

(t) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Allowance for Funds Used During Construction given to Niagara Mohawk, which are being amortized April 2004-May 2023.

(u) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

This account records (1) the current year's Net Revenue Sharing (NRS) deferral and (2) the amortization of prior year NRS imbalances (i.e. net over or under collections). In accordance with rate case 17-G-0239 and the PSC 219 tariff (Rule 26), the Company sets delivery revenue targets for SC 6 and combined SC9/ SC14 service classes each rate year and reconciles actual fiscal year revenues to these targets. The company shares with participating service classes of customers 90% of the difference vs targets in SC 6 revenues and 100% of the difference in the combined SC9/14 revenues vs targets. Additionally, the annual filing with the PSC occurs during June of each year, with new rates effective August 1st.

(v) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The Company's Gas Tariff has a mechanism (PSC No. 219, Rule 33 effective April 2018 per case 17-G-0239) that permits the Company to recover from customers costs associated with energy supply procurement, credit and collections and uncollectible as well as working capital on purchased gas and gas storage.

(w) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Section 10.1.1 of the Joint Proposal in Cases 17-E-0238 & 17-E-0239 require the Company to defer the difference between actual Pension and OPEB costs and the annual revenue requirements for Pension and OPEB costs.

(x) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Section 10.1.1 of the Joint Proposal in Cases 17-E-0238 & 17-E-0239 require the Company to defer the difference between actual Pension and OPEB costs and the annual revenue requirements for Pension and OPEB costs.

(y) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Allowance for Funds Used During Construction given to the Company, which are being amortized April 2004-April 2038.

(z) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

This deferral mechanism discontinued April 2013. The balance of this account represents partially amortized amount per Section 4.4.1 and Appendix 6, Schedule 13 of the Joint Proposal per Case 12-G-0202. In April 2018, rate case 17-G-0239 transferred a pro-rata allocation of this account, a portion was used to create the Gas Rate Plan Deferral Credit. Remaining balance will be considered in future rate cases.

(aa) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

This account records deferral of recoveries from customers through surcharge as allowed under: Case 99-G-1369 and continued under Case 17-G-0239 Joint Proposal page 76. These recoveries are meant to compensate the company for specific R&D expenditures related to Millennium projects. The account is reconciled and filed annually for the period of (Jan-Dec) and submitted to the PSC at January 1. In April 2018, Millennium R&D's share of the one-time Gas Rate Plan Deferral Credit was applied to the deferral balance which increased deferred liability by $0.341 million.

(ab) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The Company's Electric Tariff has a mechanism (PSC No. 220, Rule 46.2.6 effective April 2018 per Case 17-E-0238 section 10.1.25) that permits the Company to reconcile the benefits associated with the net market value of NYPA Rural & Domestic power, the benefit of the monthly Residential Consumer Discount Program payment and the Residential Agricultural Discount Program to the amounts credited to customers.

(ac) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The Company's Electric Tariff has a mechanism (PSC No. 220, Rule 46.2 effective April 2018 per case 17-E-0238 section10.1.25) that permits the Company to recover from customers costs associated with Legacy power agreements and reconcile the revenues and costs.

(ad) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The Company's Electric Tariff has a mechanism (PSC No. 220, Rule 46.3 effective April 2018 per case 17-E-0238 section 10.1.25) that permits the Company to recover from customers costs associated with purchased power agreements and reconcile the revenues and costs.

(ae) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The objectives of accounting for income taxes are to recognize (a) the amount of taxes payable or refundable for the current year, and (b) deferred tax liabilities and assets for the future tax consequences of events that have been recognized in the Company's financial statements or tax returns.

(af) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

In Case 14-M-0101 ("Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision; issued/effective 02/26/2015), the State of New York PSC directed the Company to engage third parties and develop concepts for demonstration projects related to Reforming the Energy Vision (REV).

Additionally, per the order, utilities are permitted to defer the revenue requirement impacts of the incremental cost of demonstration projects, until their next rate plan. This account covers the deferral of incremental revenue requirement amounts for in-service CAPEX associated with the Company’s REV Demonstration Projects. At the inception of the deferral, the REV Demonstration Projects are as follows: (1) Fruit Belt Community Solar Project (Buffalo, NY), (2) Potsdam Resiliency Project (Potsdam, NY), (3) Distributed System Platform Project (Buffalo, NY) and (4) Demand Reduction Project (Clifton Park, NY). (5) Smart City Project (Schenectady, NY). Per Rate Case 17-E-0238, the Company will defer costs associated with additional REV demonstration projects.

(ag) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

In Case 14-M-0101 (Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision; issued/effective 02/26/2015), the State of New York PSC directed the Company to engage third parties and develop concepts for demonstration projects related to Reforming the Energy Vision (REV).

Additionally, per the order, utilities are permitted to defer the revenue requirement impacts of the incremental cost of demonstration projects, until their next rate plan. This account captures the deferral of incremental revenue requirement amounts for incremental O&M associated with the Company’s REV Demonstration Projects. At the inception of the deferral, the REV Demonstration Projects are as follows: (1) Fruit Belt Community Solar Project (Buffalo, NY), (2) Potsdam Resiliency Project (Potsdam, NY), (3) Distributed System Platform Project (Buffalo, NY) and (4) Demand Reduction Project (Clifton Park, NY). Per Rate Case 17-E-0238, the Company will defer costs associated with additional REV demonstration projects.

(ah) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Section 10.1 of Joint Proposal in Docket 17-E-0238 requires the company to defer interest on regulatory assets.

(ai) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Section 10.1 of Joint Proposal in Rate Case17-E-0238 requires the company to defer interest on regulatory assets.

(aj) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Per Case 17-E-0238, System Benefit Charge costs will continue to be reconciled pursuant to Public Service Commission 220 Rule 41. Energy Efficiency Portfolio Standard deferral was re-classed to a separate GL account per Public Service Commission request in July 2018.

(ak) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

This account holds the deferral for later recovery of the cost that the Company has incurred to comply with new federal regulations application to vegetation management practices on the electric transmission system. The incremental work performed to comply with the regulation is the basis for deferral of the incremental expenditures incurred for FY 2015 in agreement with Appendix 7, Section 1.2.2. of the Joint Proposal approved by NY PSC in Case 12-E-0201. Effective April 2018, PSC Case 17-E-0238 transferred a pro-rata allocation, $11.5 million was used to create the Electric Rate Plan Deferral Credit. This mechanism is discontinued under case 17-E-0238.

(al) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

This account carries the deferred charges for RSS (Reliability Support Service) paid to Dunkirk totaling $57 million as per RSS agreement rate case 12-E-0136 (Petition of Dunkirk Power LLC and NRG energy Inc for Waiver of generator Retirement) and rate case 12-E-0201. Pursuant to the new electric rate case 17-E-0238, the Company was authorized to create an Electric Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for our customers. In April 2018, a pro rata allocation was transferred from the Dunkirk Settlement deferral balance to the Electric Rate Plan Deferral Credit. This mechanism is discontinued under case 17-E-0238.

(am) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Per rate case 14-E-0423 National Grid will continue its electric Demand Response Programs. Each Rate Year, the Company will fully reconcile its Demand Response Program costs to the amount reflected in rates. Amounts below or above value collected in rates will be deferred. Demand Response programs are as follow: Distribution Load Relief, Commercial System Relief, Direct Load Control. Interest will be provided by Electric Pricing for NIMO accounting to record at the end of each year.

(an) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The Company filed tariff amendments to incorporate Light Emitting Diode (LED) street lighting fixture options, P.S.C. No 214 - Electricity. Municipalities have expressed interest to NMPC in replacing the non-LED fixtures with LED fixtures. The company requested a deferral for future recovery equal to the return of and return on (1) LED facility costs not included in the proposed rate, (2) incremental cost of removal incurred by the Company, and (3) any lost delivery kilowatt-hour (kWh) sales revenue. (case 15-E-0645)

(ao) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The Company filed tariff amendments to incorporate Light Emitting Diode (LED) street lighting fixture options, P.S.C. No 214 - Electricity. Municipalities have expressed interest to NMPC in replacing the non-LED fixtures with LED fixtures. The company requested a deferral for future recovery equal to the return of and return on (1) LED facility costs not included in the proposed rate, (2) incremental cost of removal incurred by the Company, and (3) any lost delivery kilowatt-hour (kWh) sales revenue. (case 15-E-0645)

(ap) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The Company filed tariff amendments to incorporate Light Emitting Diode (LED) street lighting fixture options, P.S.C. No 214 - Electricity. Municipalities have expressed interest to NMPC in replacing the non-LED fixtures with LED fixtures. The company requested a deferral for future recovery equal to the return of and return on (1) LED facility costs not included in the proposed rate, (2) incremental cost of removal incurred by the Company, and (3) any lost delivery kilowatt-hour (kWh) sales revenue. (case 15-E-0645)

(aq) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The balance in this account represents the incremental rate case expenses incurred associated with Case 17-E-0238 (Electric). The rate case expenses for Case 17-E-0238 are deferred as a regulatory asset. In the Company's current rate cases 17-E-0238 & 17-G-0239, the balance in the account will be amortized over three Rate Years (April 2018 - March 2021) under the rate plan in accordance to Appendix 1, Schedule 1.

(ar) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The balance in this account represents the incremental rate case expenses incurred associated with Case 17-G-0239 (Gas). The rate case expenses for Case 17-G-0239 are deferred as a regulatory asset. In the Company's current rate cases 17-E-0238 & 17-G-0239, the balance in the account will be amortized over three Rate Years (April 2018 - March 2021) under the rate plan in accordance to Appendix 1, Schedule 2.

(as) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Section 10.1.7 of the Joint Proposal in Case 17-E-0238 requires the Company to defer 80% of the difference between actual property taxes (excluding the effects of property tax refunds) and the rate allowance ($183.024 million in Rate Year One, $189.211 million in Rate Year Two, and $195.164 million in Rate Year Three).

(at) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

This account contains the MFC (Merchant Function Charge) Gas Imbalance surcharges/refunds and associated carrying charges. The MFC is included on the customers’ bills and annual recoveries are compared to annual amounts allowed per the PSC. Any imbalance is filed with the PSC annually and collected/refunded from customers from April through March.

(au) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

This account represents the Refund/Surcharge for prior years’ SPA (System Performance Adjustment) imbalances (i.e. over/under collection). This account is filed annually for the period of September - August and is submitted to the PSC by October 15th.

(av) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Per Tariff Leaf 122.1 of PSC No. 219, Rule 31.1A (CEF Surcharge Rate). Beginning on March 1, 2016, the CEF Surcharge Rate collects funds associated with NYSERDA administered activities. The balance in this accoutn represents the differece between NYSERDA CEF Bill as you go payments and CEF recoveries.

(aw) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Per Tariff Leaf 221 of PSC No. 220, Rule 41.3 (CEF Surcharge Rate). Beginning on March 1, 2016, the CEF Surcharge Rate will collect funds associated with NYSERDA administered clean energy activities. The balance in this account represents the difference between NYSERDA CEF Bill as you go payments and CEF recoveries.

(ax) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Per rate case 17-G-0239 (Section 10.1.22, Section 13.8.2 & Appendix 6, Schedule 13), the Company continue its oil to gas conversion deferral. NMPC will defer the difference between conversion cost and annual rate allowance of $0.764 million, the cost of which will not exceed $1 million annually.

(ay) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The balance in this account represents the NY PSC management audit costs incurred. The management audit expenses will be deferred as a regulatory asset. As approved in the Company's Rate Case 17-E-0238 & 17-G-0239, Appendix 5, Schedule 1, the balance in the account will be amortized over five Rate Years (April 2018 - March 2023) for $67,200 each Rate Year.

(az) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

The balance in this account represents the NY PSC management audit costs incurred. The management audit expenses will be deferred as a regulatory asset. As approved in the Company's Rate Case 17-E-0238 & 17-G-0239, Appendix 6, Schedule 1, the balance in the account will be amortized over five Rate Years (April 2018 - March 2023) for $12,800 each Rate Year.

(ba) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Beginning January 1, 2018, Niagara Mohawk implemented the Low Income Energy Affordability Program (“LIEAP”), which was approved by case 14-M-0565. Electric and gas customers who received a Home Energy Assistance Program (HEAP) benefit within the last the previous 14 months were eligible to participate in a Low Income Discount Program. The monthly Tier Level discount is based upon the customer’s HEAP benefit. Per rate case 17-G-0239, each Rate Year beginning April 1, 2018, the Company will fully reconcile Energy Affordability Program Costs to the amount reflected in rates and defer the difference for future recovery from customers or future use in a low-income program.

(bb) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Beginning January 1, 2018, Niagara Mohawk implemented the Low Income Energy Affordability Program (“LIEAP”), which was approved by case 14-M-0565. Electric and gas customers who received a Home Energy Assistance Program (HEAP) benefit within the last the previous 14 months were eligible to participate in a Low Income Discount Program. The monthly Tier Level discount is based upon the customer’s HEAP benefit. Per rate case 17-E-0238, each Rate Year beginning April 1, 2018, the Company will fully reconcile Energy Affordability Program Costs to the amount reflected in rates and defer the difference for future recovery from customers or future use in a low-income program.

(bc) Concept: DescriptionAndPurposeOfOtherRegulatoryAssets

Regulatory Accounts 1823995/2540995 were created to track the Efficiency Transition Implementation Plan ("ETIP") Gas Revenue Deferral Mechanism or over/under recovered revenues plus corresponding carrying charges calculated using pre-tax Weighted Average Cost of Capita rate(pre-tax WACC") as stated on PSC No219 GAS LEAF: 122.1 Revision 9.


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
MISCELLANEOUS DEFFERED DEBITS (Account 186)
  1. Report below the particulars (details) called for concerning miscellaneous deferred debits.
  2. For any deferred debit being amortized, show period of amortization in column (a)
  3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes.
CREDITS
Line No.
Description of Miscellaneous Deferred Debits
(a)
Balance at Beginning of Year
(b)
Debits
(c)
Credits Account Charged
(d)
Credits Amount
(e)
Balance at End of Year
(f)
1
(a)
Oswego
5,802,754
362,545
1,542,407
4,622,892
2
Cash Over and Short
402,306
14,449,448
15,700,165
848,411
3
Suspense Consolidations
62,458
69,402,527,938
69,401,368,533
1,221,863
4
HSBC-Vcard
359,902
20,484,681
20,451,474
326,695
5
WNS-Bank Fees
1,168
1,168
6
Pension Costs
333,782,921
512,622,019
477,814,474
368,590,466
47
Miscellaneous Work in Progress
48
Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49
TOTAL
339,690,537
373,261,283


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionOfMiscellaneousDeferredDebits

NMPC has had a Purchase Power Agreement (PPA) with Oswego Dam (Oswego) to purchase power at a fixed rate since 1993. A tracking provision in the contract obligates Oswego to pay the Company the difference between the fixed contract rate and the cost the Company would have incurred in producing the power itself. This difference has been building in the Company’s favor (i.e. the fixed contract rate was less expensive than the cost the Company would incur in producing the power itself) since 1993, and is inclusive of interest. A Regulatory Liability for US GAAP was recorded in the amount of $11 million. This amount represents the running balance of the difference between the two costs since the beginning of the contract through Sept 2014. On a monthly basis, using a discounting schedule provided by Oswego, the deferred debit and the regulatory liability will be wound down based on the difference between the fixed contract rate and the internal production rate (which is now in Oswego’s favor) through the end of the contract in 2022. An additional discount on the Company's purchased power by Oswego will also be accounted for in the wind down calculation.


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
  1. Report the information called for below concerning the respondent’s accounting for deferred income taxes.
  2. At Other (Specify), include deferrals relating to other income and deductions.
Line No.
DescriptionOfAccumulatedDeferredIncomeTax
Description and Location
(a)
AccumulatedDeferredIncomeTaxes
Balance at Beginning of Year
(b)
AccumulatedDeferredIncomeTaxes
Balance at End of Year
(c)
1
Electric
2
Reserve - Environmental
84,063,911
86,451,381
3
Regulatory Liabilities - Other
217,147,426
182,657,550
4
Regulatory Tax Liabilities
187,816,226
224,383,909
5
Allowance for uncolletible accounts
28,608,186
28,639,271
6
Future Federal Benefit of State Taxes
16,183,550
18,876,150
7
7
Other
69,752,013
59,607,741
8 TOTAL Electric (Enter Total of lines 2 thru 7)
603,571,312
600,616,002
9
Other (Specify)
10
Reserve - Environmental
14,834,808
15,256,126
11
Regulatory Liabilities - Other
43,857,899
45,638,195
12
Regulatory Tax Liabilities
44,583,655
43,719,949
13
Allowance for uncolletible accounts
12,260,651
12,273,973
14
Future Federal Benefit of State Taxes
4,825,530
5,123,780
15
15
Other
17,385,598
13,683,576
16 TOTAL Gas (Enter Total of lines 10 thru 15)
137,748,141
135,695,599
17 Other (Specify)
18 TOTAL (Acct 190) (Total of lines 8, 16 and 17)
741,319,453
736,311,601
Notes


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
CAPITAL STOCKS (Account 201 and 204)
  1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
  2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
  3. Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued.
  4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative.
  5. State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year.
  6. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purpose of pledge.
Line No.
Class and Series of Stock and Name of Stock Series
(a)
Number of Shares Authorized by Charter
(b)
Par or Stated Value per Share
(c)
Call Price at End of Year
(d)
Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Shares
(e)
Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) Amount
(f)
Held by Respondent As Reacquired Stock (Acct 217) Shares
(g)
Held by Respondent As Reacquired Stock (Acct 217) Cost
(h)
Held by Respondent In Sinking and Other Funds Shares
(i)
Held by Respondent In Sinking and Other Funds Amount
(j)
1
Common Stock (Account 201)
2
3
4
5
Total
187,364,863
6
Preferred Stock (Account 204)
7
8
9
10
Total
28,984,701
1
Capital Stock (Accounts 201 and 204) - Data Conversion
2
Common-Account 201
3
Common
250,000,000
1
187,364,863
187,364,863
4
TOTAL-COMMON
250,000,000
187,364,863
187,364,863
5
Preferred-Account 204
6
Cumulative Preferred
31,000,000
7
3.40% Series
100
103.5
57,524
5,752,400
8
3.60% Series
100
104.85
137,152
13,715,200
9
3.90% Series
100
106
95,171
9,517,100
10
Preferred Stock - Golden Share
1
1
1
1
1
11
TOTAL-PREFERRED
31,000,001
289,848
28,984,701
12
Total


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

2019-04-17
Year/Period of Report

End of:
2018
/
Q4
Other Paid-in Capital
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting such change.
  1. Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation.
  2. Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave rise to amounts reported under this caption including identification with the class and series of stock to which related.
  3. Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210) - Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
  4. Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line No.
Item
(a)
Amount
(b)
1
DonationsReceivedFromStockholdersAbstract
Donations Received from Stockholders (Account 208)
2
DonationsReceivedFromStockholders
Beginning Balance Amount
3
IncreasesDecreasesFromSalesOfDonationsReceivedFromStockholders
Increases (Decreases) from Sales of Donations Received from Stockholders
4
DonationsReceivedFromStockholders
Ending Balance Amount
5
ReductionInParOrStatedValueOfCapitalStockAbstract
Reduction in Par or Stated Value of Capital Stock (Account 209)
6
ReductionInParOrStatedValueOfCapitalStock
Beginning Balance Amount
7
IncreasesDecreasesDueToReductionsInParOrStatedValueOfCapitalStock
Increases (Decreases) Due to Reductions in Par or Stated Value of Capital Stock
8
ReductionInParOrStatedValueOfCapitalStock
Ending Balance Amount
9
GainOrResaleOrCancellationOfReacquiredCapitalStockAbstract
Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)
10
GainOnResaleOrCancellationOfReacquiredCapitalStock
Beginning Balance Amount
11
IncreasesDecreasesFromGainOrResaleOrCancellationOfReacquiredCapitalStock
Increases (Decreases) from Gain or Resale or Cancellation of Reacquired Capital Stock
12
GainOnResaleOrCancellationOfReacquiredCapitalStock
Ending Balance Amount
13
MiscellaneousPaidInCapitalAbstract
Miscellaneous Paid-In Capital (Account 211)
14
MiscellaneousPaidInCapital
Beginning Balance Amount
15
IncreasesDecreasesDueToMiscellaneousPaidInCapital
Increases (Decreases) Due to Miscellaneous Paid-In Capital
16
MiscellaneousPaidInCapital
Ending Balance Amount
17
OtherPaidInCapitalAbstract
Histrocal Data - Other Paid in Capital
18
OtherPaidInCapitalDetail
Beginning Balance Amount
19.1
IncreasesDecreasesInOtherPaidInCapital
Donations Received from Stockholders (Account 208)
19.2
IncreasesDecreasesInOtherPaidInCapital
SUBTOTAL
19.3
IncreasesDecreasesInOtherPaidInCapital
Reduction in Par or Stated Value of Common Stock (Account 209)
19.4
IncreasesDecreasesInOtherPaidInCapital
SUBTOTAL
19.5
IncreasesDecreasesInOtherPaidInCapital
Gain on Resale or Cancellation of Reacquired Capital Stock (Acct 210)
19.6
IncreasesDecreasesInOtherPaidInCapital
Balance @ 12/31/2007.
10,865,988
19.7
IncreasesDecreasesInOtherPaidInCapital
SUBTOTAL
10,865,988
19.8
IncreasesDecreasesInOtherPaidInCapital
Miscellaneous Paid In Capital (Account 211):
19.9
IncreasesDecreasesInOtherPaidInCapital
Amount set up on 01/05/50, as adjusted 12/58, regarding certain
19.10
IncreasesDecreasesInOtherPaidInCapital
investments contributed by Niagara Hudson Power Corporation, former
19.11
IncreasesDecreasesInOtherPaidInCapital
parent holding company in accordance with its "Dissolution Plan" which
19.12
IncreasesDecreasesInOtherPaidInCapital
was approved by the Securities and Exchange Commission under date
19.13
IncreasesDecreasesInOtherPaidInCapital
of 08/25/49 and by the District Court of the United States for the
19.14
IncreasesDecreasesInOtherPaidInCapital
Northern District of New York State under date of 11/4/49.
2,137,110
19.15
IncreasesDecreasesInOtherPaidInCapital
Amount of cash received upon liquidation of Niagara Hudson
19.16
IncreasesDecreasesInOtherPaidInCapital
Power Corporation in excess of estimated liabilities.
500,000
19.17
IncreasesDecreasesInOtherPaidInCapital
Contributions in aid of construction transferred from Account 217, per
19.18
IncreasesDecreasesInOtherPaidInCapital
order of the Public Service Commission of the State of New York,
19.19
IncreasesDecreasesInOtherPaidInCapital
dated 03/08/52 in case 13343.
28,773
19.20
IncreasesDecreasesInOtherPaidInCapital
Capital surplus of the Oswego Canal Company, merged as of 03/31/52,
19.21
IncreasesDecreasesInOtherPaidInCapital
$276,296 less write down of electric plant of $67,212.
209,084
19.22
IncreasesDecreasesInOtherPaidInCapital
Excess of book value over the purchase price of the capital stock of
19.23
IncreasesDecreasesInOtherPaidInCapital
the Woodville Electric Light and Power Company, Inc.
5,164
19.24
IncreasesDecreasesInOtherPaidInCapital
Refund of deposits for script certificates of Niagara Hudson Power
19.25
IncreasesDecreasesInOtherPaidInCapital
Corporation which expired on 01/05/58.
124,121
19.26
IncreasesDecreasesInOtherPaidInCapital
Proceeds from the sale of 5,173 shares of common stock held for
19.27
IncreasesDecreasesInOtherPaidInCapital
distribution to holders of unexchanged certificates of Niagara
19.28
IncreasesDecreasesInOtherPaidInCapital
Hudson Power Corporation common stock. Sold pursuant to order of
19.29
IncreasesDecreasesInOtherPaidInCapital
the United States District Court for the Northern District of New
19.30
IncreasesDecreasesInOtherPaidInCapital
York, dated 01/23/61.
204,267
19.31
IncreasesDecreasesInOtherPaidInCapital
To record subsidiaries on the "Equity" basis:
19.32
IncreasesDecreasesInOtherPaidInCapital
Excess book value over the cost of investments at the date of
19.33
IncreasesDecreasesInOtherPaidInCapital
acquisition of Canadian Niagara Power Co., Ltd. ($3,457,284) and
19.34
IncreasesDecreasesInOtherPaidInCapital
St. Lawrence Power Co. ($903,145) as previously recorded on the
19.35
IncreasesDecreasesInOtherPaidInCapital
Company's books. Ownership of these companies was transferred to
19.36
IncreasesDecreasesInOtherPaidInCapital
Opinac Energy Corporation (formerly Opinac Investments Limited)
19.37
IncreasesDecreasesInOtherPaidInCapital
during 1982.
4,360,429
19.38
IncreasesDecreasesInOtherPaidInCapital
Excess of the cost of investment carried on the Company's books over
19.39
IncreasesDecreasesInOtherPaidInCapital
the book value at date of acquisition of Beebee Island Corporation.
62,872
19.40
IncreasesDecreasesInOtherPaidInCapital
Excess of the book value at the date of acquisition over the cost of
19.41
IncreasesDecreasesInOtherPaidInCapital
investments carried on the Company's books of Moreau Manufacturing
19.42
IncreasesDecreasesInOtherPaidInCapital
Corp.
477,984
19.43
IncreasesDecreasesInOtherPaidInCapital
Merger Purchase Accounting Adjustments
2,671,376,392
19.44
IncreasesDecreasesInOtherPaidInCapital
Return of Capital Dividend on common stock (7/02)
86,086,034
19.45
IncreasesDecreasesInOtherPaidInCapital
Equity Contribution made by parent company (NM Holdings)
404,127,268
19.46
IncreasesDecreasesInOtherPaidInCapital
Share based compensation
3,751,505
19.47
IncreasesDecreasesInOtherPaidInCapital
Parent tax loss allocation
87,476,659
20
OtherPaidInCapitalDetail
Ending Balance Amount
40
OtherPaidInCapital
Total
3,099,495,838


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
CAPITAL STOCK EXPENSE (Account 214)
  1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
  2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Line No.
NameOfClassAndSeriesOfStock
Class and Series of Stock
(a)
CapitalStockExpense
Balance at End of Year
(b)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
TOTAL


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
LONG-TERM DEBT (Account 221, 222, 223 and 224)
  1. Report by Balance Sheet Account the details concerning long-term debt included in Account 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other Long-Term Debt.
  2. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
  3. For Advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received.
  4. For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued.
  5. In a supplemental statement, give explanatory details for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a)principal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates.
  6. If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name of the pledgee and purpose of the pledge.
  7. If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote.
  8. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (f). Explain in a footnote any difference between the total of column (f) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
  9. Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line No.
ClassAndSeriesOfObligationCouponRateDescription
Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates)
(a)
RelatedAccountNumber
Related Account Number
(b)
Principal Amount of Debt Issued
(c)
LongTermDebtIssuanceExpensePremiumOrDiscount
Total Expense, Premium or Discount
(d)
LongTermDebtIssuanceExpenses
Total Expense
(e)
LongTermDebtPremium
Total Premium
(f)
LongTermDebtDiscount
Total Discount
(g)
NominalDateOfIssue
Nominal Date of Issue
(h)
DateOfMaturity
Date of Maturity
(i)
AmortizationPeriodStartDate
AMORTIZATION PERIOD Date From
(j)
AmortizationPeriodEndDate
AMORTIZATION PERIOD Date To
(k)
Outstanding (Total amount outstanding without reduction for amounts held by respondent)
(l)
Interest for Year Amount
(m)
1
Bonds (Account 221)
2
3
4
5
Subtotal
3,274,165,000
6
Reacquired Bonds (Account 222)
7
8
9
10
Subtotal
11
Advances from Associated Companies (Account 223)
12
13
14
15
Subtotal
16
Other Long Term Debt (Account 224)
17
18
19
20
Subtotal
Long Term Debt (Historical Data)
1
Bonds (Account 221)
2
Unsecured notes:
3
Senior Note @ 4.88%
750,000,000
3,805,177
(a)
08/10/2009
(m)
08/15/2019
(y)
08/10/2009
(ak)
08/15/2019
750,000,000
36,607,500
4
Senior Note @ 2.72%
300,000,000
1,338,576
(b)
11/28/2012
(n)
11/28/2022
(z)
11/28/2012
(al)
11/28/2022
300,000,000
8,163,000
5
Senior Notes @ 3.51%
500,000,000
3,060,582
(c)
09/25/2014
(o)
10/01/2024
(aa)
09/25/2014
(am)
10/01/2024
500,000,000
17,540,000
6
Senior Notes @ 4.28%
500,000,000
2,755,598
(d)
12/04/2018
(p)
12/15/2028
(ab)
12/04/2018
(an)
12/15/2028
500,000,000
1,604,250
7
Senior Notes @ 4.28%
400,000,000
2,060,582
(e)
09/25/2014
(q)
10/01/2034
(ac)
09/25/2014
(ao)
10/01/2034
400,000,000
17,112,000
8
Senior Note @ 4.12%
400,000,000
3,642,569
(f)
11/28/2012
(r)
11/28/2042
(ad)
11/28/2012
(ap)
11/28/2042
400,000,000
16,476,000
9
State Autority Financing - tax exempt:
10
Due 12/01/23 @ 3.23%
69,800,000
934,300
(g)
12/01/1988
(s)
12/01/2023
(ae)
12/01/1988
(aq)
12/01/2023
69,800,000
2,854,528
11
Due 12/01/25 @ 3.29%
75,000,000
12,440,897
(h)
12/01/1985
(t)
12/01/2025
(af)
12/01/1985
(ar)
12/01/2025
75,000,000
3,220,668
12
Due 12/01/26 @ 3.42%
50,000,000
787,811
(i)
12/01/1986
(u)
12/01/2026
(ag)
12/01/1986
(as)
12/01/2026
44,700,000
1,829,318
13
Due 03/01/27 @ 3.45%
25,760,000
2,463,371
(j)
03/01/1987
(v)
03/01/2027
(ah)
03/01/1987
(at)
03/01/2027
25,760,000
1,134,944
14
Due 07/01/27 ($68.2M @ 3.43% & $25M @ 3.48%)
93,200,000
1,609,373
(k)
07/01/1987
(w)
07/01/2027
(ai)
07/01/1987
(au)
07/01/2027
93,200,000
3,475,683
15
Due 07/01/29 @ 3.43%
115,705,000
4,981,759
(l)
07/01/1984
(x)
07/01/2029
(aj)
07/01/1984
(av)
07/01/2029
115,705,000
5,066,777
16
SUBTOTAL ACCOUNT 221
3,279,465,000
39,880,595
3,274,165,000
115,084,668
17
Other Long Term Debt (Account 224)
18
SUBTOTAL ACCOUNT 224
33 TOTAL
3,279,465,000
39,880,595
3,274,165,000
115,084,668


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NominalDateOfIssue
Original value: 08/10/2009
(b) Concept: NominalDateOfIssue
Original value: 11/28/2012
(c) Concept: NominalDateOfIssue
Original value: 09/25/2014
(d) Concept: NominalDateOfIssue
Original value: 12/04/2018
(e) Concept: NominalDateOfIssue
Original value: 09/25/2014
(f) Concept: NominalDateOfIssue
Original value: 11/28/2012
(g) Concept: NominalDateOfIssue
Original value: 12/01/1988
(h) Concept: NominalDateOfIssue
Original value: 12/01/1985
(i) Concept: NominalDateOfIssue
Original value: 12/01/1986
(j) Concept: NominalDateOfIssue
Original value: 03/01/1987
(k) Concept: NominalDateOfIssue
Original value: 07/01/1987
(l) Concept: NominalDateOfIssue
Original value: 07/01/1984
(m) Concept: DateOfMaturity
Original value: 08/15/2019
(n) Concept: DateOfMaturity
Original value: 11/28/2022
(o) Concept: DateOfMaturity
Original value: 10/01/2024
(p) Concept: DateOfMaturity
Original value: 12/15/2028
(q) Concept: DateOfMaturity
Original value: 10/01/2034
(r) Concept: DateOfMaturity
Original value: 11/28/2042
(s) Concept: DateOfMaturity
Original value: 12/01/2023
(t) Concept: DateOfMaturity
Original value: 12/01/2025
(u) Concept: DateOfMaturity
Original value: 12/01/2026
(v) Concept: DateOfMaturity
Original value: 03/01/2027
(w) Concept: DateOfMaturity
Original value: 07/01/2027
(x) Concept: DateOfMaturity
Original value: 07/01/2029
(y) Concept: AmortizationPeriodStartDate
Original value: 08/10/2009
(z) Concept: AmortizationPeriodStartDate
Original value: 11/28/2012
(aa) Concept: AmortizationPeriodStartDate
Original value: 09/25/2014
(ab) Concept: AmortizationPeriodStartDate
Original value: 12/04/2018
(ac) Concept: AmortizationPeriodStartDate
Original value: 09/25/2014
(ad) Concept: AmortizationPeriodStartDate
Original value: 11/28/2012
(ae) Concept: AmortizationPeriodStartDate
Original value: 12/01/1988
(af) Concept: AmortizationPeriodStartDate
Original value: 12/01/1985
(ag) Concept: AmortizationPeriodStartDate
Original value: 12/01/1986
(ah) Concept: AmortizationPeriodStartDate
Original value: 03/01/1987
(ai) Concept: AmortizationPeriodStartDate
Original value: 07/01/1987
(aj) Concept: AmortizationPeriodStartDate
Original value: 07/01/1984
(ak) Concept: AmortizationPeriodEndDate
Original value: 08/15/2019
(al) Concept: AmortizationPeriodEndDate
Original value: 11/28/2022
(am) Concept: AmortizationPeriodEndDate
Original value: 10/01/2024
(an) Concept: AmortizationPeriodEndDate
Original value: 12/15/2028
(ao) Concept: AmortizationPeriodEndDate
Original value: 10/01/2034
(ap) Concept: AmortizationPeriodEndDate
Original value: 11/28/2042
(aq) Concept: AmortizationPeriodEndDate
Original value: 12/01/2023
(ar) Concept: AmortizationPeriodEndDate
Original value: 12/01/2025
(as) Concept: AmortizationPeriodEndDate
Original value: 12/01/2026
(at) Concept: AmortizationPeriodEndDate
Original value: 03/01/2027
(au) Concept: AmortizationPeriodEndDate
Original value: 07/01/2027
(av) Concept: AmortizationPeriodEndDate
Original value: 07/01/2029

Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
  1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
  2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
  3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.
Particulars (Details)
(a)
Amount
(b)
1
Net Income for the Year (Page 117)
198,308,115
2
Reconciling Items for the Year
3
4
Taxable Income Not Reported on Books
5
Federal Income Taxes
47,849,964
6
See Details in Footnote
(a)
115,721,652
9
Deductions Recorded on Books Not Deducted for Return
10
See Details in Footnote
(b)
701,272,542
14
Income Recorded on Books Not Included in Return
15
See Details in Footnote
(c)
71,390,283
19
Deductions on Return Not Charged Against Book Income
20
See Details in Footnote
(d)
649,849,603
27
Federal Tax Net Income
341,912,387
28
Show Computation of Tax:
29
Federal Taxable Income, Page 261
341,912,387
30
Total Tax @ 35%/31.55% (Blended) Before Credits
88,423,424
31
Credits
77,148
32
Prior Year Adjustment
47,938,101
33
Net Allocated Tax
40,408,175


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: TaxableIncomeNotReportedOnBooks

Taxable Income Not Reported on Books

 

 

Employee Stock Purchase Plan Discount

477,780

 

Construction - Aid of Construction

59,833,569

 

Add-back of Income Tax Credits

161,148

 

Share Based Comp_Windfall/Shortfal

18,955

 

Lobbying Expenses & Political Contributions

672,725

 

Meals and Entertainment

625,419

 

Flow-through Depreciation

53,932,056

 

Total Line 6

 

$115,721,652

 

(b) Concept: DeductionsRecordedOnBooksNotDeductedForReturn

Deductions Recorded on Books Not Deducted for Return

 

 

ACCRUED INTEREST - TAX RESERVE

10,372,052

 

ACCRUED OTHER - TCC AUCTION REVENUE

9,745,248

 

ADIT - STATE

 

2,425,308

 

AFUDC DEBT

 

8,955,272

 

AMORTIZATION EXPENSE

1,537,666

 

BAD DEBTS

 

161,480

 

COST OF REMOVAL

 

6,922,839

 

DEFERRED GAS COST

8,564,214

 

DEPRECIATION EXPENSE - BOOK

228,774,069

 

INCENTIVE PLAN

 

1,607,764

 

INJURIES AND DAMAGES

1,212,590

 

INVESTMENTS - PARTNERSHIPS

10,758

 

POLE ATTACHMENT RENTALS

15,348

 

REG ASSET - CARRYING CHARGES

49,245,102

 

REG ASSET - HEDGING

43,929,133

 

REG ASSET - OPEB

 

64,702,569

 

REG ASSET - PENSION

100,073,721

 

REG ASSET - OTHER

94,963,061

 

REG ASSET - ARO

 

280,198

 

REG LIABILITY - OTHER

44,434,572

 

RESERVE - ENVIRONMENTAL

10,213,777

 

RESERVE - FIN 48 STATE

5,373,420

 

RESERVE - GENERAL

1,306,846

 

RESERVE - HEALTHCARE COSTS

2,371,000

 

RESERVE - SALES TAX

871,747

 

UNAMORTIZED DEBT DISCOUNT OR PREMIUM

158,578

 

UNICAP - INVENTORY

2,724,956

 

WORKERS' COMPENSATION

319,254

 

Total Line 10

 

$701,272,542

 

 

 

 

 

 

(c) Concept: IncomeRecordedOnBooksNotIncludedInReturn

Income Recorded on Books Not Included in Return

 

 

Tax Exempt Interest Income

(508,730)

 

Change in Cash Surrender Value

(186,842)

 

Flow-through AFUDC Equity

(13,602,559)

 

Dividend Received Deduction

(85,824)

 

Equity-based Compensation and Dividends

(4,655,805)

 

Flow-through Cost of Removal

(52,021,287)

 

Flow-through Unamortized Debt

(329,236)

 

Total Line 15

 

($71,390,283)

 

 

 

 

 

 

(d) Concept: DeductionsOnReturnNotChargedAgainstBookIncome

Deductions on Return Not Charged Against Book Income

 

 

ACCRUED OTHER

 

(3,236,707)

 

ACCRUED OTHER - REC OBLIGATION

(1,607,987)

 

ACCRUED OTHER - PSA4

(209,596)

 

ASSET RETIREMENT OBLIGATION

(532,399)

 

CASUALTY LOSS

 

(11,754,903)

 

DEFERRED COMPENSATION

(501,550)

 

DEPRECIATION EXPENSE - TAX

(210,447,925)

 

DEPRECIATION EXPENSE - TAX BONUS

(11,961,626)

 

FASB 112

 

 

(1,579,627)

 

GAIN (LOSS) ON SALE OF ASSETS

(4,818,343)

 

HEDGING

 

 

(43,929,133)

 

INSURANCE PROVISION

(1,787,002)

 

OPEB / FASB 106

 

(86,629,649)

 

PENSION COST

 

(36,509,817)

 

REG ASSET - ENVIRONMENTAL

(38,216,811)

 

REG ASSET - PROPERTY TAXES

(10,550,254)

 

REG ASSET - STORM COST

(61,957,574)

 

REG LIABILITY - BONUS DEPRECIATION

(5,292,914)

 

REPAIRS DEDUCTION

(106,665,219)

 

RESERVE - OBSOLETE INVENTORY

(282,178)

 

RESERVE - SEVERANCE

(443,533)

 

UNBILLED REVENUE

 

(8,721,016)

 

VACATION ACCRUAL

 

($1,107,621)

 

SHARE BASED COMP

(900,007)

 

CHARITABLE CONTRIB LIMITATION

(206,212)

 

Total Line 20

 

($649,849,603)

 

 

 

 

 

 


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
  1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
  2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (g) and (h). The balancing of this page is not affected by the inclusion of these taxes.
  3. Include in column (g) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts.
  4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
  5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying the year in column (d).
  6. Enter all adjustments of the accrued and prepaid tax accounts in column (i) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses.
  7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority.
  8. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (o) the amounts charged to Accounts 408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts.
  9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT BEGINNING OF YEAR BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED
Line No.
DescriptionOfTaxesAccruedPrepaidAndCharged
Kind of Tax (See Instruction 5)
(a)
TypeOfTax
Type of Tax
(b)
TaxJurisdiction
State
(c)
TaxYear
Tax Year
(d)
TaxesAccrued
Taxes Accrued (Account 236)
(e)
PrepaidTaxes
Prepaid Taxes (Include in Account 165)
(f)
TaxesCharged
Taxes Charged During Year
(g)
TaxesPaid
Taxes Paid During Year
(h)
TaxAdjustments
Adjustments
(i)
TaxesAccrued
Taxes Accrued (Account 236)
(j)
PrepaidTaxes
Prepaid Taxes (Included in Account 165)
(k)
TaxesAccruedPrepaidAndCharged
Electric (Account 408.1, 409.1)
(l)
IncomeTaxesExtraordinaryItems
Extraordinary Items (Account 409.3)
(m)
AdjustmentsToRetainedEarnings
Adjustment to Ret. Earnings (Account 439)
(n)
TaxesIncurredOther
Other
(o)
1
Federal
2
Federal Income Tax
84,537,476
40,408,175
49,180,110
37,121,590
38,643,951
28,851,151
11,557,024
3
FICA Contribution
1,842,471
30,476,331
31,243,896
54,029
1,020,877
19,941,264
10,535,067
4
Federal Unemployment
2,121
178,842
177,226
3,737
10,960
189,802
5
State
6
State Income Tax
31,634,330
9,549,675
14,792,269
26,391,736
6,902,209
2,647,466
7
Franchise - Gross Earnings
470,250
24,295,171
23,113,066
711,855
18,726,477
5,568,694
8
State Unemployment Insurance
8,207
428,315
420,686
15,836
428,315
9
Sales and Use
2,554,182
38,109,750
39,989,781
2,244,573
2,918,724
26,160
38,083,590
10
Local
11
Real Estate
20,952
223,092,522
223,053,926
88,148
28,600
177,550,920
45,541,602
12
Municipial Gross Income
1,261,250
14,904,389
14,838,378
1,327,261
11,948,261
2,956,128
13
Other
5,357
336,161
330,786
18
315,044
21,117
40
TOTAL
121,385,382
71,122,143


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)

Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i) the average period over which the tax credits are amortized.

Deferred for Year Allocations to Current Year's Income
Line No.
Account Subdivisions
(a)
Balance at Beginning of Year
(b)
Account No.
(c)
Amount
(d)
Account No.
(e)
Amount
(f)
Adjustments
(g)
Balance at End of Year
(h)
Average Period of Allocation to Income
(i)
ADJUSTMENT EXPLANATION
(j)
1
Electric Utility
2
10%
11,422,554
506,804
1,059,468
10,869,890
35 Years
8 TOTAL
11,422,554
506,804
1,059,468
10,869,890
9
Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10
4%
83,746
7,900
75,846
44 Years
11
10%
2,840,695
267,971
2,572,724
44 Years
12
TOTAL
2,924,441
275,871
2,648,570
48 TOTAL


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
OTHER DEFERRED CREDITS (Account 253)
  1. Report below the particulars (details) called for concerning other deferred credits.
  2. For any deferred credit being amortized, show the period of amortization.
  3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
DEBITS
Line No.
Description and Other Deferred Credits
(a)
Balance at Beginning of Year
(b)
Contra Account
(c)
Amount
(d)
Credits
(e)
Balance at End of Year
(f)
1
Energy Service Company Deposits
1,488,438
851,213
623,253
1,260,478
2
Suppl Executive Retirement Plan
1,042,196
594,092
92,542
540,646
3
Nuclear Fuel Disposal Costs
169,812,722
3,174,423
172,987,145
4
Other Post Employment Benefit
28,122,893
18,197,182
16,617,554
26,543,265
5
Long Term Interest Payable
25,661,493
1,558,192
11,930,244
36,033,545
6
Def Cr - Sales Tax Acc
9,360,137
1,469,266
2,341,013
10,231,884
7
(a)
FIN 48 FIT/SIT
116,464,307
13,620,856
28,224,261
131,067,712
8
Storm Reserve
1,080,593
45,397
1,558,630
2,593,826
9
Deferred Revenue
365,580
101,769
79,483
343,294
10
(b)
Mohawk Valley Edge - CIAC
4,819,686
1,986,512
3,478,578
6,311,752
11
All Other
133,484,973
143,746,173
134,309,804
142,921,342
47
TOTAL
224,733,072
182,170,652
202,429,785
244,992,205


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionOfOtherDeferredCredits

Federal Income Tax (FIT)

State Income Tax (SIT)

(b) Concept: DescriptionOfOtherDeferredCredits

Contribution in Aid of Construction (CIAC)


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report


End of:
2018
/
Q4
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
  1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property.
  2. For other (Specify),include deferrals relating to other income and deductions.
  3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account 411.2
(f)
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1
Accelerated Amortization (Account 281)
2
Electric
3
Defense Facilities
4
Pollution Control Facilities
5
Other
5.1
Other
5.2
Other
8
TOTAL Electric (Enter Total of lines 3 thru 7)
9
Gas
10
Defense Facilities
11
Pollution Control Facilities
12
Other
12.1
Other
12.2
Other
15
TOTAL Gas (Enter Total of lines 10 thru 14)
16
Other
16.1
Other
16.2
Other
17
TOTAL (Acct 281) (Total of 8, 15 and 16)
18
Classification of TOTAL
19
Federal Income Tax
20
State Income Tax
21
Local Income Tax


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282)
  1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization.
  2. For other (Specify),include deferrals relating to other income and deductions.
  3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account 411.2
(f)
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1 Account 282
2
Electric
1,305,014,102
40,540,228
182/254
4,531,545
1,350,085,875
3
Gas
324,917,115
8,090,225
182/254
1,005,947
334,013,287
4
Other (Specify)
5
Total (Total of lines 2 thru 4)
1,629,931,217
48,630,453
5,537,492
1,684,099,162
6
7
8
9
TOTAL Account 282 (Total of Lines 5 thru 8)
1,629,931,217
48,630,453
5,537,492
1,684,099,162
10
Classification of TOTAL
11
Federal Income Tax
1,395,417,973
37,285,458
4,663,784
1,437,367,215
12
State Income Tax
234,513,244
11,344,995
873,708
246,731,947
13
Local Income Tax


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283)
  1. Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amounts recorded in Account 283.
  2. For other (Specify),include deferrals relating to other income and deductions.
  3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
  4. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account 411.2
(f)
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1 Account 283
2
Electric
3
Regulatory Assets - Environmen
64,816,009
8,933,179
73,749,188
4
Reg Assets - Pension and OPEB
30,521,557
30,521,557
5
Regulatory Assets - Other
42,296,991
40,006,034
5,195,758
7,486,715
6
Other Deferred Tax Liabilities
859,756
1,809,384
50,098
2,719,238
7
Pension, OPEB and other employ
13,222,651
29,362,715
42,585,366
9 TOTAL Electric (Total of lines 3 thru 8)
151,716,964
30,422,313
5,245,856
126,540,507
10
Gas
11
Regulatory Assets - Environmen
11,438,119
1,576,444
13,014,563
12
Reg Assets - Pension and OPEB
6,251,403
6,251,403
13
Regulatory Assets - Other
18,253,543
10,548,301
1,064,191
8,769,433
14
Other Deferred Tax Liabilities
3,315,505
2,768,814
10,261
556,952
15
Pension, OPEB and other employ
2,779,334
5,921,384
8,700,718
17 TOTAL Gas (Total of lines 11 thru 16)
42,037,904
12,070,690
1,074,452
31,041,666
18 TOTAL Other
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)
193,754,868
42,493,003
6,320,308
157,582,173
20
Classification of TOTAL
21
Federal Income Tax
151,647,463
32,673,573
182/254
4,989,730
123,963,620
22
State Income Tax
42,107,405
9,819,430
182/254
1,330,578
33,618,553
23
Local Income Tax
NOTES


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
OTHER REGULATORY LIABILITIES (Account 254)
  1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
  2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes.
  3. For Regulatory Liabilities being amortized, show period of amortization.
DEBITS
Line No.
Description and Purpose of Other Regulatory Liabilities
(a)
Balance at Beginning of Current Quarter/Year
(b)
Account Credited
(c)
Amount
(d)
Credits
(e)
Balance at End of Current Quarter/Year
(f)
1
(a)
Federal Tax Regulatory Liability
983,467,934
236,751,289
29,275,234
775,991,879
2
(b)
Energy Efficiency - Gas EEPS deferral
33,927
6,146,096
6,112,169
3
(c)
Gas Refund
403,469
403,469
4
(d)
Deferred Gas Cost
29,710,733
29,710,733
5
(e)
Pipeline Refunds
55
55
6
(f)
Gas Adjustment Clause (GAC) Imbalance Refund
3,122,550
3,171,805
9,681,564
9,632,309
7
(g)
Temporary State Assessment 18A
502,843
9,294
636,377
1,129,926
8
(h)
Transportation Adjustment Clause Imbalance Refund
158,199
253,938
95,739
9
(i)
Commodity Timing Impact Deferral
41,558,630
41,558,630
10
(j)
RPS Program Cost Deferred
17,623,450
17,623,450
11
(k)
CES Def Supply
4,414,815
4,414,815
12
(l)
Exc Resv Tax Elec
17,948,000
17,948,000
13
(m)
Exc Resv Tax Gas
4,534,000
4,534,000
14
(n)
Energy Efficiency Surcharge - Gas
3,963,992
1,161,947
5,609,938
8,411,983
15
(o)
Energy Efficiency Surcharge - Electric
15,472,736
7,705,676
23,919,496
31,686,556
16
(p)
On-Bill Repayment EE Fund Oblig
7,257,423
8,001,019
5,755,231
5,011,635
17
(q)
Merchant Function Charge - Electric
228,312
570,921
342,609
18
(r)
Revenue Decoupling Mechanism - Electric
14,309,214
51,748,618
37,439,404
19
(s)
Deferred Rate Case True Up
29,239,860
29,239,860
20
(t)
Capital Tracker (Case 12-G-0202) - Gas
5,201,772
5,201,772
21
(u)
Affordability Program - Electric
3,012,009
32,400
203,046
3,182,655
22
(v)
Generation Stranded Cost Adjustments
3,862,937
1,966,851
4,741,272
6,637,358
23
(w)
Low Income Program - Gas
2,761,953
1,011,879
3,301,255
5,051,329
24
(x)
Int SBC Costs Deferral
635,097
1,692,358
1,057,261
25
(y)
Off System Sales Profit Deferral
543,046
2,432,305
2,956,784
1,067,525
26
(z)
Electric Supply Reconciliation Mechanism (ESRM)
38,439,021
38,439,021
27
(aa)
Excess Storm Reserve
170,138,977
194,638,977
24,500,000
28
(ab)
Capital Tracker (Case 12-E-0201) - Elec
13,269,953
13,336,570
66,617
29
(ac)
State Tax Regulatory Liability
57,486,030
24,342,978
11,379,812
44,522,864
30
(ad)
NUP-FY18-E-15-M-0744
53,311,227
19,638,461
72,949,688
31
(ae)
NUP-FY18-G-15-M-0744
11,897,236
4,588,291
16,485,527
32
(af)
Paige St Settlement
498,419
11,232
487,187
33
(ag)
Debt True Up - Electric
56,696,172
49,816,997
3,049,974
9,929,149
34
(ah)
Consumer Service Advocate
90,479
64,160
26,319
35
(ai)
Deferral Carrying Charges 10-E-0050
82,750,585
92,894,347
33,354,954
23,211,192
36
(aj)
Proceeds from Sale of Emissions Allowance -Albany
1,435,234
1,261,808
173,426
37
(ak)
Clean Air Act - Roseton
135,179
119,052
16,127
38
(al)
Customer Service System Conversion Savings Gas
68,593
51,907
16,686
39
(am)
Net Revenue Sharing Mechanism - Gas
321,733
466,735
145,002
40
(an)
Unbilled Gas Revenue
20,106,709
155,270,052
153,175,983
18,012,640
41
(ao)
Electric Customer Service Penalty
17,328,766
13,755,319
3,573,447
42
(ap)
Gas Contingency Reserve
407,326
306,173
101,153
43
(aq)
Gas Customer Service Penalty
28,954,891
28,345,000
6,085,000
6,694,891
44
(ar)
Loss on Sale of Building
269
269
45
(as)
System Benefit Charge Program Deferred
13,573,321
13,573,321
46
(at)
Diana Dolgeville - IPP Settlement
3,500,128
2,495,100
1,005,028
47
(au)
Merchant Function Charge - Gas
65,585
223,889
158,304
48
(av)
Site Investigation & Remediation Expend Def Gas
11,163,139
7,512,917
3,825,534
7,475,756
49
(aw)
Transmission Revenue Adjustment Clause
110,352,453
147,573,610
57,304,562
20,083,405
50
(ax)
NYS Sales Tax Refund
1,200,000
868,696
331,304
51
(ay)
Economic Development Fund - Electric
90,302,612
67,752,902
3,816,028
26,365,738
52
(az)
Gross Receipts Tax Customer Refund -2000-Gas
15,386
11,284
4,102
53
(ba)
Gas Millenium Fund Deferral
631,775
1,734,735
1,102,960
54
(bb)
Bonus Depreciation Adjustment - Elec (15-M-0744)
9,445,702
6,914,278
2,301,199
4,832,623
55
(bc)
Bonus Depreciation Adjustment - Gas (12-G-0202)
21,897
16,550
5,347
56
(bd)
Internal Reserve Carry Charge
50,829,108
36,235,265
14,593,843
57
(be)
Gas Futures - Gas Supply
527,995
3,390,416
2,862,421
58
(bf)
KeySpan Merger Savings - Gas
62,806
47,392
15,414
59
(bg)
Electric Swaps - Electric Supply
7,446,356
66,390,873
82,651,512
23,706,995
60
(bh)
Voltage Migration Fee Deferral
7,504
7,960
456
61
(bi)
RDM Revenue Decoupling - Gas
11,388,189
12,783,057
1,394,868
62
(bj)
Long Term Debt True-Up - Gas
19,279,477
14,966,563
745,020
5,057,934
63
(bk)
Federal Tax Refund 1991-1995
3,723,054
2,800,696
922,358
64
(bl)
Curtailment
316,134
226,179
89,955
65
(bm)
Oswego Puchase Power Agreement
5,802,754
1,542,406
362,545
4,622,893
66
(bn)
NYPA Hyrdropower Benefit
25,588
1,226,900
1,248,086
46,774
67
(bo)
Pension Expense deferred-Electric
23,949,366
4,916,280
28,865,646
68
(bp)
OPEB Expense deferred-Electric
75,616,335
39,191,602
62,836,975
99,261,708
69
(bq)
Low Income Allowance Discount Program - Electric
9,069,787
7,393,916
9,938,482
11,614,353
70
(br)
Site Investigation and Remediation Exp. Def Elec
71,180,832
45,956,785
21,641,133
46,865,180
71
(bs)
Legacy Transition Charge
16,967,598
16,967,598
72
(bt)
Dunkirk II Settlement Deferral - Excess
1,331,592
70
13,999
1,345,521
73
(bu)
NYPA Replacement Power & Expansion Power
4,927,507
3,513,100
1,414,407
74
(bv)
NMPC - 18 A Assessment Gas
319,628
371
303,978
623,235
75
(bw)
Hydro One Network
1,887,763
1,887,763
76
(bx)
Miscellaneous Penalties
443,402
333,255
110,147
77
(by)
Case 08-G-0609 Joint Proposal Amortization
2,895,907
2,178,569
717,338
78
(bz)
Demand Response Programs
223,803
2,325,230
2,101,427
79
(ca)
Net Utility Plant & Depreciation Rec (Elec)
39,425,999
39,425,999
80
(cb)
Net Utility Plant & Depreciation Rec (Gas)
7,349,364
31,789
7,381,153
81
(cc)
Self-Direct Electric
405,425
139,905
366,205
631,725
82
(cd)
Rate Plan Settlement Credit Elec
4,650,000
44,880,000
40,230,000
83
(ce)
Rate Plan Settlement Credit Gas
28,420,000
28,420,000
84
(cf)
LED Capital Investment Tracker - Elec
21,644
268,741
247,097
85
(cg)
Walk-in Pymt Fee - Elec
147,851
358,328
210,477
86
(ch)
Walk-in Pymt Fee - Gas
54,685
132,368
77,683
87
(ci)
Vegetation Management Cost-Elec
4,739,838
14,423,581
9,683,743
88
(cj)
Platform Service Revenue
6,225
25,295
19,070
89
(ck)
Net Utility Plant - 17-G-0239
447,601
1,263,157
815,556
90
(cl)
Economic Develop Fund - Gas
7,708,330
6,406,748
2,028,722
3,330,304
91
(cm)
Economic Develop Grant Program - Gas
3,237,826
995,440
4,233,266
92
(cn)
Economic Develop Grant Program - Electric
4,714,778
2,044,725
1,812,512
4,482,565
93
(co)
AffordAbility Program - Gas
587,240
11,280
88,040
664,000
94
(cp)
Property Tax Exp Def - Gas
11,258,788
11,391,755
841,501
708,534
95
(cq)
Variable Pay Deferral - Gas
363,279
324,228
39,051
96
(cr)
NYPA Discount Rec Deferral
2,692,035
998,753
343,791
2,037,073
97
(cs)
Transmission Tower Painting
75,841
22,812
50,067
103,096
98
(ct)
Sub-Transmission Tower Painting
1,116,248
846,908
2,249
271,589
99
(cu)
Transmission Footer Inspection Expense
29,831
29,831
100
(cv)
Sub-Transmission Footer Inspection Expense
107,658
81,269
928
27,317
101
(cw)
Federal Income Tax Repair Costs
30,113,000
28,118,719
1,994,281
102
(cx)
Rate Plan Deferral Credit - Elec
86,040,605
200,403,569
114,362,964
103
(cy)
Rate Plan Deferral Credit - Gas
21,009,113
56,123,000
35,113,887
104
(cz)
Bonus Depreciation Adjustment (15-M-0744)
1,527,691
987,729
324,444
864,406
105
(da)
Merchant Function Charge - Imbalance
22,786
94,406
71,620
106
(db)
NMPC Gas Community Carrying Charge Deferral
24,073,431
20,390,153
7,091,657
10,774,935
107
(dc)
System Performance Adjustment
23,544
23,544
108
(dd)
Excess Voltage Test
15,222,837
15,358,482
932,372
796,727
109
(de)
Clean Energy Fund - Gas
8,756,809
12,013,242
8,673,633
5,417,200
110
(df)
Clean Energy Fund - Electric
362,149,628
113,978,390
83,377,859
331,549,097
111
(dg)
Spier Falls Transm
86,751
1,158,053
1,071,302
112
(dh)
Clean Energy Fund Interest - Gas
31,594
139,491
107,897
113
(di)
Clean Energy Fund Interest - Elec
2,101,482
12,882,867
10,781,385
114
(dj)
EEPS Interest - Elec
3,973,512
8,836,009
4,862,497
115
(dk)
SBC Interest Deferral
1,362,406
1,362,406
116
(dl)
RPS Interest Deferral
836,613
836,613
41 TOTAL
2,299,569,151
1,829,250,138
1,502,441,812
1,972,760,825


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

In FAS 109, the objectives of accounting for income taxes are to recognize (a) the amount of taxes payable or refundable for the current year, and (b) deferred tax liabilities and assets for the future tax consequences of events that have been recognized in the Company's financial statements or tax returns.

(b) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per Case 12-G-0202 Appendix 6 Schedule 12, the Company will defer the difference between costs (self-administered and System Benefit Charge) and revenue collections. The Energy Efficiency Portfolio Standard (EEPS) program was re-classed into its own account per Public Service Commission request in June 2018. Previously, it was deferred in combination with the Clean Energy Fund gas deferral.

(c) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Account balance represents the remaining portion of NMPC’s litigation settlement from Sithe/Independence Power Partners, L.P. Of the $1.8 million settlement, $1.397 million was returned to firm sales customers through the October 2012 GAC filing. The Company has petitioned the Public Service Commission that the remaining $0.403 million be retained by the Company and not returned to customers/shareholders. The PSC has yet to respond to the Company’s petition.

(d) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account represents the monthly calculation of the Gas Adjustment Clause (GAC) deferral. The GAC deferral entry takes into account the difference between (1) the actual gas cost recoveries from customers and (2) the actual gas costs incurred by the Company for gas purchased from suppliers. The deferral is filed annually for the period of September to August and submitted to the PSC by October 15th. After the filing is made, the balance is transferred to an imbalance regulatory deferral account and is recovered or refunded to customers in the next calendar period.

(e) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account represents refunds received from various pipelines which the Company uses to transport gas. These refunds can come into the company in the form of checks, wires or credits on the pipeline invoice. All refunds in the account at the end of the GAC year (August) are transferred to the annual GAC/TAC Imbalance filing to the PSC at October 15 and will subsequently be refunded to the customers in the next calendar year.

(f) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account represents the Refund/Surcharge for prior years’ MCG (Monthly Cost of Gas) imbalances (i.e. over/under collection). The refund/surcharge is filed annually for the period of September - August and is submitted to the PSC by October 15th.

(g) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Balance in this account represents 18-A Temporary State Energy & Utility Service Conservation Assessment (TSA). This account was established based on a new Temporary State Energy & Utility Services Conservation Assessment effective April 1, 2009. It imposes a charge of 2% of gross intrastate operating revenues for electric (and gas prior to this period - June 2013) utilities derived in the last preceding calendar year minus the amount of General Assessment for the Department of Public Service costs for fiscal year. Pursuant to Case 09-M-0311, the TSA (18-A) expried December 2017 and effective April 1, 2018 utilities are no longer authorized to defer the difference between the TSA costs and TSA collections from customers. The disposition of the balance will be determind in the future rate case.

(h) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account represents the Refund/Surcharge for prior years’ TAC (Transportation Adjustment Clause) imbalances (i.e. over/under collection). The account is filed annually for the period of September – August and is submitted to the Public Service Commission by October 15th.

(i) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The Company reconciles the commodity cost through the Electricity Supply Reconciliation Mechanism (ESRM) pursuant to PSC 220 Rule 46.3. The mechanism calculates the deferral using the prior month actual cost of purchase power and prior month sales revenue, thus there is one-month lag from the accounting perspective. The purpose of this account is to remove one-month lag by recording commodity timing adjustment.

(j) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account represents standalone Renewable Portfolio Standard (RPS) deferral. As a result of 2018 PSC request to view Clean Energy Fund deferrals separately from other deferrals, it was necessary to re-class principal and interest balances related to Renewable Portfolio Standard to their own accounts. Per previous PSC Case 14-M-0094 (Issued/Effective January 21, 2016), NYSERDA’s clean energy activities was consolidated under the umbrella of the Clean Energy Fund (CEF). Legacy programs (and their associated deferral balances) existing prior to this case, including the Renewable Portfolio Standard, were consolidated into CEF.

(k) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

On August 1, 2016, the Commission issued an order (Case 15-E-0302) to implement a Large-Scale Renewable Program and Clean Energy Standards (CES). Under this program, the company is required to purchase the percentage of Renewable Energy Credits to support new renewable generation sources and Zero Emission Credits to support Zero-Emission-nuclear power from NYSERDA and recover costs from ratepayers through commodity charges on customer bills.

(l) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Stipulated in Attachment 1 to DPS-001 filed with the PSC under Case 17-E-0238, the Company recorded the adjustment to the revenue requirement in response to new federal tax rate effective January 2018. Effective April 2018 the federal tax law change is included in delivery rates under the new rate cases 17-E-0238 & 17-G-0239.

(m) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Stipulated in Attachment 1 to DPS-001 filed with the PSC under Case 17-G-0239, the Company recorded the adjustment to the revenue requirement in response to new federal tax rate effective January 2018. Effective April 2018 the federal tax law change is included in delivery rates under the new rate cases 17-E-0238 & 17-G-0239.

(n) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per rate case 17-G-0239, The Company's energy efficiency costs (ETIP) will be recovered in base rates instead of the Energy Efficiency Tracker Surcharge portion of SBC. Any under-expenditure in a given Rate Year will be carried forward and reconciled at the end of Rate Year Three. See Leaf 221.1 of PSC No. 220 for tariff details. Monthly, the company will compare (1) Self-Administered Costs to (2) Rate Allowance. This deferral is downward only. Monthly, carrying charges are calculated on the deferral balance using the "Other Customer Capital Rate," which is set annually by the PSC.

(o) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per rate case 17-G-0239, The Company's energy efficiency costs (ETIP) will be recovered in base rates instead of the Energy Efficiency Tracker Surcharge portion of SBC. Any under-expenditure in a given Rate Year will be carried forward and reconciled at the end of Rate Year Three. See Leaf 221.1 of PSC No. 220 for tariff details. Monthly, the Company will compare (1) Self-Administered Costs to (2) Rate Allowance. This deferral is downward only. Monthly, carrying charges are calculated on the deferral balance using the "Other Customer Capital Rate," which is set annually by the PSC.

(p) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Account is used by Energy Efficiency as a CoPay loan account to record theoretical borrowing from the relevant EE Fund Balance to fund EE CoPay loans and to track the outstanding loan portfolio balance for the CoPay loans given to customers who participate in the Energy Efficiency CoPay Loan program. This account serves as an indication of the amount "borrowed from the Company-E Demand Side Management Fund Balance" to fund Company-E CoPay loans.

(q) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The Merchant Function Charge (MFC) is applied to the customer’s bill when the customer receives electricity supply from the Company. This charge includes costs associated with commodity related credit and collections, commodity related uncollectible expense, electric supply procurement costs and working capital for electric supply. This charge is applied to the Electricity Supply portion of a customer’s bill. This charge will not be billed if the customer chooses and alternate supplier. Based on rate case 17-E-0238 the Company is allowed to defer the difference between the revenue for the MFC and the revenue requirement.

(r) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

NMPC Electric Tariff has a mechanism (PSC No. 220, Rule 57 effective April 2018 per Section 3.5, rate case 17-E-0238) that permits the Company to defer the difference between target revenues for delivery services and actual billed delivery service revenues.

(s) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The Company conducted an A&G Capitalization study based on a time study completed during FY 2018 Q4 using CY 2017. This study resulted in the transfer of A&G costs charged to FERC accounts 920 and 921 to capital through the A&G overhead process at the individual regulated utility operating companies. An entry was recorded in March 2018 by Service Company to transfer A&G costs determined to be capitalized in FY 2018.

 

In March 2018, Niagara Mohawk’s total costs transferred by business segment was $10.796 million for electric distribution, $3.158 million for transmission and $3.217 million for gas. General Accounting prepared a corresponding entry to defer the A&G costs credited to expense and establish a regulatory liability for future benefit to the customer. Going forward the Company is continuing the transfer and deferral of A&G costs that represent capitalized costs.

(t) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The Company implemented a downward only gas reconciliation mechanism which reconciles total gas average net plant and depreciation expense as per rate case. Each rate year, the Company will reconcile its annual combined actual gas average net utility plant & depreciation expense revenue requirement to the combined target gas average net utility plant and depreciation expense revenue requirement. If targets exceed actual expenses a credit entry would be made to the account. There will be no further activity in this account due to the end of the rate case.

(u) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The Affordability Program provides assistance to a small number of eligible low income residential consumers with arrears owed to the company who enter a payment plan to make current payments and retire arrears. The Affordability Program discontinued new enrollment in its arrear forgiveness program in March 2017. The program discontinued as of 3/31/2018 per Rate Case 17-E-0238 & 17-G-0239. The program will be phased-out gradually, as existing customers participating in the program either complete the program, default, or voluntarily remove themselves from the program. The Company will reduce (debit) the current regulatory liability for the credits provided to grandfather customers.

(v) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Section 10.1.19 of the Joint Proposal in rate case 17-E-0238 requires the Company to defer any reductions or additions to stranded costs associated with the implementation of JP for Nine Mile Point (Case 01-E-0011).

(w) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Beginning January 1, 2018, Niagara Mohawk implemented the Low Income Energy Affordability Program (EAP), which was approved by case 14-M-0565. Per Rate Case 17-G-0239, each Rate Year beginning April 1 2018, the Company will fully reconcile Low Income Energy Affordability Program costs to the rate allowance of $14.905 million. Amount in excess of the rate allowance will be deferred for future recovery from customers. Any under-expenditure will be deferred for future use in a low income program.

(x) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per Case 12-G-0202 Appendix 6 Schedule 12, the Company deferred the difference between costs (self-administered and System Benefit Charge) and revenue collections. This program was re-classed into its own account per Public Service Commission request in June 2018, with Principle to U2540002 and Interest to U2540280. Previously, it was deferred in combination with the Clean Energy Fund gas deferral. Per Case 14-M-0094, interest for Energy Efficiency Portfolio Standard and Clean Energy Fund is to be segregated in the company's books for future benefit to ratepayers. This account represents the Interest component of the Energy Efficiency Portfolio Standard (EEPS) deferral.

(y) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account records net margins from off-system sales, capacity release credits other than those associated with assignments to ESCOs and any net margins derived from the optimization of the Company's portfolio of gas supply, transportation, storage and peaking contracts. These net margins will be shared at 85% to customers and 15% to the Company. This account is filed annually as part of the Gas Adjustment Clause (GAC) with the PSC in October for the preceding September through August time period. Once filed, the balance is transferred to the GAC Imbalance account to be refunded in the next calendar year (PSC 219 Rule 17.7; Case 17-G-0239).

(z) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The accounts process Electricity Supply Reconciliation Mechanism (ESRM) performed per rule 46.3.1, 46.3.2, and 46.3.3 of PSC tariff 220. ESRM reconciles electricity supply revenues for the month to the market cost of electricity purchased. Costs in excess of revenues are collected from customers and revenues in excess of costs are credited to customers. ESRM also includes the cost of benefit of hedging contracts.

(aa) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Balance in account represents the cumulative Excess Storm Deferral. In accordance with the Case 17-E-0238, the Storm Reserve allowance amount for electric incremental major storm costs has been updated to reflect the new allowance amount of $23 million per rate year. The allowance deferred in this account should be analyzed in conjunction with account 1823006, which holds the respective expenses for incremental storm costs which match up with the allowances deferred in this account. Pursuant to the new electric rate case 17-E-0238, a pro-rata allocation of $32.76 million was transferred from the Excess Storm Reserve deferral balance to the Rate Plan Deferral Credit liability account.

(ab) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The Company has implemented a downward only electric reconciliation mechanism which reconciles total electric average net plant and depreciation expenses as per rate case 12-E-0201. Each rate year, the Company will reconcile its annual combined actual electric average net utility plant & depreciation expense revenue requirement to the combined target electric average net utility plant and depreciation expense revenue requirement. There will be no further activity in this account due to the end of the rate case.

(ac) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The objectives of accounting for income taxes are to recognize (a) the amount of taxes payable or refundable for the current year, and (b) deferred tax liabilities and assets for the future tax consequences of events that have been recognized in the Company's financial statements or tax returns.

(ad) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account contains the deferral balance of the Net Utility Plant tracker pertaining to the electric service for fiscal year 2018. As determined by rate case 15-M-0744, NMPC will reconcile its annual actual electirc average net utility plant and depreciation expense revenue requirements to the target amounts. There will be no further activity in this account due to the close out of this balance using existing deferred credits specified in case 15-M-0744.

(ae) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account contains the deferral balance of the Net Utility Plant tracker pertaining to the gas service for fiscal year 2018. As determined by rate case 15-M-0744, NMPC will reconcile its annual actual average gas net utility plant and depreciation expense revenue requirements to the target amounts. There will be no further activity in this account due to the close out of this balance using existing deferred credits specified in case 15-M-0744.

(af) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The Case 15-G-0171 settled a pending penalty proceeding between the Company and PSC DPS Staff concerning a natural gas incident that occurred at 310 Paige Street, Schenectady, New York on August 10, 2014.

The Company committed to creating a $500,000 deferral, at shareholder expense, to be used to develop a remote meter valve technology pilot program. The pilot program would be supplemental to any existing research and development budget focused on remote meter valves.

(ag) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The account holds the deferral for Auction Debt True up deferral recovery mechanism stipulated by Section 10.1.5 of Joint Proposal (rate cases 17-E-0238 and 17-G-0239) for Rate Year One only. The Company’s capital structure includes variable rate pollution control revenue bonds. The Company reconciles the actual interest expense for these bonds with the amount reflected in rates and defers the difference for refund to or recovery from customers.

(ah) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per rate case 10-E-0050, the Company will hire one additional Consumer Advocate effective 2010. In the event that the Company does not hire an additional Consumer Advocate, the allowance will be deferred for future ratepayer use. Per rate case 12-E-0201, this deferral is discontinued and the deferred balance above is partially amortized per Section 3.4.1 and Appendix 5, Schedule 18. Per rate case 17-E-0238 effective April 2018, a pro-rata allocation was used to create the Rate Plan Deferral Credit per Appendix 2 Schedule 3.5 effective 2018.

(ai) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Section 10.1 of Joint Proposal in rate case 17-E-0238 requires the company to defer interest on regulatory assets and liabilities. This account holds interest on these regulatory deferrals using the weighted average cost of capital (net of tax).

(aj) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Schedule 17 of Appendix 5 of the Joint Proposal in rate case 12-E-0201 discontinues this deferral mechanism. In addition, the pre-existing deferred amount is partially amortized per Section 3.4.1 & Appendix 5, Schedule 18. Remaining balance subject to pro-rata deferral, $1.26 million used to create the Electric Rate Plan Deferral Credit per rate case 17-E-0238 Appendix 2 Schedule 3.5 effective April 2018.

(ak) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Schedule 17 of Appendix 5 of the Joint Proposal in rate case 12-E-0201 discontinues this deferral mechanism. In addition, the pre-existing deferred amount is partially amortized per Section 3.4.1 & Appendix 5, Schedule 18. Remaining balance subject to pro-rata deferral, a portion was used to create the Electric Rate Plan Deferral Credit per rate case 17-E-0238 per Appendix 2 Schedule 3.5 effective 2018.

(al) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Schedule 12 of Appendix 6 of the Joint Proposal in rate case 12-G-0202 discontinues this deferral mechanism. In addition, the pre-existing deferred amounts are partially amortized per Section 4.4.1 and Appendix 6, Schedule 13. Remaining balance subject to pro-rata deferral was used to create the Gas Rate Plan Deferral Credit per rate case 17-G-0239 Appendix 3 Schedule 2 and 3 effective April 2018.

(am) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account records (1) the current year's Net Revenue Sharing (NRS) deferral and (2) the amortization of prior year NRS imbalances (i.e. net over or under collections). In accordance with rate case 17-G-0239 and the PSC 219 tariff (Rule 26), the Company sets delivery revenue targets for SC 6 and combined SC9/ SC14 service classes each rate year and reconciles actual fiscal year revenues to these targets. The Company shares with participating service classes of customers 90% of the difference vs targets in SC 6 revenues and 100% of the difference in the combined SC9/14 revenues vs targets. Additionally, the annual filing with the PSC occurs during June of each year, with new rates effective August 1st.

(an) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

In accordance with rate cases 17-E-0238 & 17-G-0239, Section 10.1.24, this account represents the accrued unbilled revenue Deferral (Gas Only), the Company will continue its current deferral practice concerning accrued unbilled revenues pursuant to the PSC’s August 30, 1988 Order in Case 29670. No carrying charges will be calculated for accrued unbilled revenues.

(ao) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Balance reflects penalties relating to operations for the Gas Quality Assurance & Safety Program projects that did not meet the PSC Estimating compliance target standards and Gas Safety & Reliability Performance Metric. The PSC has the right to enforce penalties on the Company based on operation performance. The accumulated liability in this account can be drawn down through pro-rata allocation and other offsets as set forth in PSC orders in which penalties are refunded to customers.

(ap) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account represents Gas Contingency Reserve Per rate case 17-G-0239 (Appendix 6, Schedule 1, Page 1 of 2). This reserve is subject to disposition in future rate case.

(aq) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Balance reflects penalties relating to operations for the Gas Quality Assurance & Safety Program projects that did not meet the PSC Estimating compliance target standards and Gas Safety & Reliability Performance Metric. The PSC has the right to enforce penalties on the Company based on operation performance. The accumulated liability in this account can be drawn down through pro-rata allocation and other offsets as set forth in PSC orders in which penalties are refunded to customers.

(ar) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Schedule 12 of Appendix 6 of the Joint Proposal in rate case 12-G-0202 discontinues this deferral mechanism. In addition, the pre-existing deferred amounts are partially amortized per Section 4.4.1 and Appendix 6, Schedule 13. This mechanism is discontinued under cases 17-E-0238 & 17-G-0239.

(as) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account represents standalone former System Benefit Charge (SBC) deferral. As a result of 2018 PSC request to view Clean Energy Fund deferrals separately from other deferrals, it was necessary to re-class principal and interest balances related to other programs to their own accounts. Per Case 14-M-0094 (Issued/Effective January 21, 2016), NYSERDA’s clean energy activities was consolidated under the umbrella of the Clean Energy Fund (CEF). Legacy programs (and their associated deferral balances) existing prior to this case, including the System Benefit Charge, were consolidated into CEF.

(at) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Schedule 17 of Appendix 5 of the Joint Proposal in Case 12-E-0201 discontinues this deferral mechanism. In addition, the pre-existing deferred amount is partially amortized per Section 3.4.1 & Appendix 5, Schedule 18. The balance subject to pro-rata deferral, $2.5 million was transferred to the Electric Rate Plan Deferral Credit per rate case 17-E-0238 Appendix 2 Schedule 3.5 effective April 2018.

(au) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account balance represents the deferral associated with the Merchant Function Charge (MFC) as per rate case 17-G-0239. The MFC deferral is calculated by comparing the (1) actual recoveries associated with various gas commodity related cost components (Gas Supply Procurement, Return Requirement on Gas Storage Inventory and Commodity Related Credit and Collection Expenses) to (2) forecast.

The MFC account balance is filed annually for the fiscal year period (April - March) and is submitted to the PSC in May. The balance is then transferred to an Imbalance regulatory account (i.e. net under- or over-recovered position vs forecast) and is recovered/refunded from/to customers commencing in June and ending in May.

(av) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Section 10.1.6 of the Joint Proposals of 17-E-0238 and 17-G-0239 provides the recoveries of Site Investigation and Remediation(SIR) expenses. The Company will reconcile the expense to the annual rate allowance of $27.321 million for electric and $4.821 million for gas. Any under- or over-expenditures will be deferred for future refund to, or recovery from customers.

(aw) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account holds the deferral balance for the Transmission Revenue Adjustment Clause (TRAC). The TRAC deferral is the difference between the forecast based on transmission revenue credits in delivery rates and actual transmission revenue realized. The TRAC is defined per rate case 17-E-0238 and PSC Tariff 220, Rule 43 effective April 2018.

(ax) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per Joint Proposal 12-M-0447, a sales tax refund from the New York State Department of Taxation and Finance in the amount of $1.2 million would be allocated for the benefit of ratepayers through a deferral mechanism subject to carrying charges. Pursuant to the new electric and gas rates cases 17-E-0238 & 17-G-0239, this mechanism is discontinued, and the Company was authorized to create a Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for customers. In April 2018, $0.869 million was transferred from the NYS Sales Tax Refund deferral balance to the Rate Plan Deferral Credit.

(ay) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The Economic Development Fund Program provides discounted electric delivery rates to qualified customers. National Grid will continue its Economic Development Fund Program. Each Rate Year, the Company will fully reconcile economic development discounts to the amount reflected in rates ($2.193 million in Rate Year One, $2.120 million in Rate Year Two and $1.721 million in Rate Year Three) for refund to or recovery from customers. Refer to Economic Development Fund (10.1.3) rate cases 17-E-0238 and 17-G-0239.

(az) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Schedule 12 of Appendix 6 of the Joint Proposal in Case 12-G-0202 discontinues this deferral mechanism. In addition, the pre-existing deferred amounts are partially amortized per Sections 4.4.1 and Appendix 6, Schedules 13. Remaining balance subject to pro-rata deferral, a portion was used to create the Gas Rate Plan Deferral Credit per rate case 17-G-0239 per Appendix 3 Schedule 2 and 3 effective April 2018.

(ba) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account records deferral of recoveries from customers through surcharge as allowed under: Case 99-G-1369 and continued under Case 17-G-0239 Joint Proposal page 76. These recoveries are meant to compensate the company for specific R&D expenditures related to Millennium projects. The account is reconciled and filed annually for the period of (Jan-Dec) and submitted to the PSC at January 1. In April 2018, Millennium R&D's share of the one-time Gas Rate Plan Deferral Credit was applied to the deferral balance which increased deferred liability by $0.341 million.

(bb) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per rate case 15-M-0744, the Company is allowed to recover 100 percent of the revenue requirement associated with these proposed capital expenditures. It is reasonable for customers to receive the entire tax benefit associated with bonus depreciation from the expenditures. This account holds the deferred tax benefit for the electric business that is owed to customers. Pursuant to Case 17-E-0238, the balance was reduced by pro-rata Electric Rate Plan Deferral Credit in April 2018. There will be no further activity in this account due to the end of the rate case.

(bc) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The purpose of this account is to process the Bonus Depreciation Adjustment. Per rate case 12-G-0202, this deferral is discontinued, and the deferred balance is partially amortized per Section 4.4.1 and Appendix 6, Schedule 13. The remaining balance will be considered in future rate cases. Pursuant to case 17-E-0238, this mechanism is discontinued, and the Company was authorized to create an Gas Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for customers. In April 2018, a portion was transferred from the Bonus Depreciation balance to the Gas Rate Plan Deferral Credit.

(bd) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Regulatory liability relates to Internal Reserve Carrying Charges at the time of the Company acquisition that were initially recorded to the Company's pension liability. Pursuant to Case 17-E-0238, the balance was reduced by pro-rata Rate Plan Deferral Credit in April 2018.

(be) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

As commodity costs, including realized gains and losses on commodity derivatives, are refunded to or recovered from customers through the Company's gas and electric cost recovery mechanisms, a regulatory asset or liability is recorded as an offset to the unrealized gain or loss on a derivative asset in accordance with ASC 980 under US GAAP.

(bf) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Schedule 12 of Appendix 6 of the Joint Proposal in rate case 12-G-0202 discontinues this deferral mechanism. In addition, the pre-existing deferred amounts are partially amortized per Section 4.4.1 and Appendix 6, Schedule 13. The balance was further reduced by pro-rata deferral used to create the Gas Rate Plan Deferral Credit per rate case 17-G-0239 Appendix 3 Schedule 2 and 3 in April 2018.

(bg) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

As commodity costs, including realized gains and losses on commodity derivatives, are refunded to or recovered from customers through the Company's gas and electric cost recovery mechanisms, a regulatory asset or liability is recorded as an offset to the unrealized gain or loss on a derivative asset in accordance with ASC 980 under US GAAP.

(bh) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Section 10.1.17 of the Joint Proposal in Case 17-E-0238 permits the Company to accrue and amortize voltage migration fee amounts collected pursuant to PSC 220 Rule 44.2. Pursuant to Case 17-E-0238, the balance was reduced by Pro-rata Electric Rate Plan Deferral Credit in April 2018.

(bi) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The Company's Gas Tariff has a mechanism (PSC No. 219, Rule 32 effective April 2018 per rate case 17-G-0239) that permits the Company to defer the difference between revenue per customer targets and actual revenues.

(bj) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The account holds the deferral for Auction Debt True up deferral recovery mechanism stipulated by Section 10.1.5 of Joint Proposal (rate cases 17-E-0238 - Electric and 17-G-0239 - Gas) for Rate Year One only. Niagara Mohawk's capital structure includes variable rate pollution control revenue bonds. The Company reconciles the actual interest expense for these bonds with the amount reflected in rates and defer the difference for refund to or recovery from customers. Pursuant to PSC 220 Rule 44.2. Pursuant to Case 17-G-0239, the balance was reduced by Pro-rata Gas Rate Plan Deferral Credit in April 2018.

(bk) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Balance in account represents the Company's Fed Tax Refund 1991-1995 as per rate case 09-M-0554. This joint proposal resolves a dispute between staff and the Company as to the disposition of Federal Income Tax Return and the associate interest received by the Company from the IRS. Per rate cases 12-G-020, Appendix 6 Scheduled 13, $6.7 million is being amortized in the Pro-Rata Allocations of deferral credits for this account. Pursuant to rate case 17-G-0239, this mechanism is discontinued, and the Company was authorized to create an Gas Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for customers. In April 2018, $2.800 million was transferred from the Federal Tax Refund balance to the Rate Plan Deferral Credit.

(bl) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Section 6.1.1 of the Joint Proposal in Case 12-E-0201 and Section 7.1.1 of the Joint Proposal in Docket 12-G-0202 require the Company to defer the difference between actual Pension and OPEB costs and the annual revenue requirements for Pension and OPEB costs. Pursuant to the new electric and gas rate case 17-E-0238 & 17-G-0239, this mechanism is discontinued, and the Company was authorized to create a Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for our customers. In April 2018, $226K was transferred from the Excess Storm Reserve deferral balance to the Rate Plan Deferral Credit liability account.

(bm) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The Company entered into a 30-year Purchase Power Agreement (PPA) with the City of Oswego (City) to purchase power at fixed rate on October 5, 1993. A tracking provision in the agreement obligates the City to pay the Company the difference (being tracked in an Adjustment Account) between the fixed contract rate and the cost the Company would have incurred in producing the power itself. This difference has built in the Company’s favor over time. General Accounting has recorded a Regulatory Liability to track this difference. This account using a discounting schedule will wind down the regulatory liability balance based on the difference between the fixed contract rate and the internal production rate for monthly production and the amount withheld/prepaid monthly by the City.

(bn) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account processes the NYPA (New York Power Authority) Hydropower Benefit reconciliation as per Rule 46.2.6 of PSC tariff 220. The NYPA Hydropower Benefit is low-cost hydropower that NIMO procures from NYPA. Monthly forecasts of contracts are trued up to the actual costs, market prices, and customer loads. The true ups are reflected on the customers' bills on a two-month lag.

(bo) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Section 10.1.1 of the Joint Proposal in rate cases 17-E-0238 & 17-E-0239 require the Company to continue defer the difference between actual Pension and OPEB costs and the annual revenue requirements for Pension and OPEB costs.

(bp) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Section 10.1.1 of the Joint Proposal in rate cases 17-E-0238 & 17-E-0239 require the Company to continue to defer the difference between actual Pension and OPEB costs and the annual revenue requirements for Pension and OPEB costs.

(bq) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Beginning January 1, 2018 Niagara Mohawk implemented the Low Income Energy Affordability Program (EAP), which was approved by case 14-M-0565. Per Rate Case 17-E-0238, Section 10.1.2 and Section 13.1., each Rate Year, the Company will fully reconcile Energy Affordability Program costs to the rate allowance of $56.594 million. Amount in excess of the rate allowance will be deferred for future recovery from customers. Any under-expenditure will be deferred for future use in a low income program.

(br) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Section 10.1.6 of the Joint Proposals of 17-E-0238 and 17-E-0239 provides the recoveries of SIR expenses. The Company will reconcile the expense to the annual rate allowance of $27.321 million for electric and $4.821 million for gas. Any under- or over-expenditures will be deferred for future refund to, or recovery from, customers.

(bs) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account processes the Legacy Transition Charge (LTC) reconciliation as per Rule 46.2 PSC 220 tariff. The LTC is a true up mechanism for old purchases power contracts.

(bt) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account reconciles the deferred charges for RSS (Reliability Support Service) from Dunkirk paid to NRG Power Marketing, the related carrying charges, and recovery via revenue collection as per RSS agreement and rate case 12-E-0136. The reconciliation recovers only the total RSS cost exceeding the total 57 million. This mechanism is discontinued under Case 17-E-0238.

(bu) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

In accordance with rate case 11-E-0535, the Company allows customers who received the benefit of reduced delivery rates for existing allocations of New York Power Authority Expansion Power and Replacement Power to be phased-in to full standard tariff delivery rates over a five or seven-year period in order to allow these customers to plan and adjust for these electric bill impacts. The incremental revenues associated with these customers being phase-in to full standard tariff rates will be deferred for future benefit to customers. The balance was subject to pro-rata deferral, $3.5 million was used to create the Electric Rate Plan Deferral Credit per rate case 17-E-0238 Appendix 2 Schedule 3.5 in April 2018.

(bv) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Balance in this account represents 18-A Temporary State Energy & Utility Service Conservation Assessment (TSA). This account was established based on a new Temporary State Energy & Utility Services Conservation Assessment effective April 1, 2009. The account records the deferral of the difference between the payment to PSC and the recovery of that payment. The account was filed annually to the PSC for the period of (July-June) submitted at June 15. Pursuant to Case 09-M-0311, the TSA (18-A) expried December 2017 and effective April 1, 2018 utilities are no longer authorized to defer the difference between the TSA costs and TSA collections form customers. The disposition of the balance will be determind in the future rate case.

(bw) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per NMPC Case 12-E-0201, the Hydro One Network account was established to record $6.4 million of costs for the Hydro One project to be recovered over three years ($2.133 million per year) ending in Fiscal Year-End March 31, 2016. The estimated cost for Hydro One to recover of $6.4 million exceeds the actual cost resulting in a credit balance of $1.887 million. The balance was fully amortized in Fiscal Year 2016 and recorded as revenue.

(bx) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Account holds NIMO's miscellaneous penalties for an ethics penalty, as per Case 12-M-0366 and a field violation penalty. Pursuant to the new gas rate case 17-G-0239, this mechanism is discontinued, and the Company was authorized to create a Gas Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for our customers. In April 2018, a portion was transferred from the Misc. Gas Penalties balance to the Gas Rate Plan Deferral Credit.

(by) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Schedule 12 of Appendix 6 of the Joint Proposal in Case 12-G-0202 discontinued this deferral mechanism. The pre-existing deferred amounts were reduced in April 2014 stipulated by Case 12-G-0202 and April 2018 stipulated by Case 17-G-0239 via pro-rata Gas Rate Plan Deferral Credits.

(bz) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per rate case 14-E-0423 National Grid will continue its electric Demand Response Programs. Each Rate Year, the Company will fully reconcile its Demand Response Program costs to the amount reflected in rates. Amounts below or above value collected in rates will be deferred. Demand Response programs are as follow: Distribution Load Relief, Commercial System Relief, Direct Load Control.

(ca) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account contains the deferral balance of the Net Utility Plant tracker pertaining to the electric service for fiscal year 2017. As determined by rate case 15-M-0744, the Company will reconcile its annual actual electric average net utility plant and depreciation expense revenue requirements to the target amounts. There will be no further activity in this account due to the close out of this balance using existing deferred credits specified in case 15-M-0744.

(cb) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account contains the deferral balance of the Net Utility Plant tracker pertaining to the gas service for fiscal year 2017. As determined by rate case 15-M-0744, the Company will reconcile its annual actual gas average net utility plant and depreciation expense revenue requirements to the target amounts. There will be no further activity in this account due to the end of the close out of this balance using existing deferred credits specified in case 15-M-0744.

(cc) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per Case 14-M-0101 (“Proceeding on Motion of the Commission in Regard to Reforming the Energy Vision,” I/E 02/26/2015), Appendix C, NMPC will include a Self-Direct Program for large commercial and industrial customers in their energy efficiency portfolios no later than January 1, 2017. The Self-Direct Programs will allow large commercial and industrial customers to self-direct funds that would otherwise support the utilities’ portfolio of energy efficiency programs toward the customers’ unique suite of energy management investments and allow the customers’ energy savings to count toward the utilities’ goals. The Self-Direct Program is implemented on a three-year cycle. Throughout the cycle, participants will be able to access at least 85% of their contributions to fund eligible projects, as agreed upon by the customer and the utility. Beginning January 1 of the first year of the cycle, the utility will regularly allocate a Self-Direct participant’s contributions to the utility’s energy efficiency portfolio into the participant’s Energy Savings Account (ESA), excluding the up-to 15% that is retained by the utility for program administration and EM&V For deferral purposes, 85% of monthly revenues from customers enrolled in the program are deferred in this account.

(cd) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

As stipulated by the latest rate case 17-E-0238, Section 2.3, the Company created a new electric deferral credit of $44.88 million ("Rate Plan Settlement Credit"). This will resolve several pending issues addressed in the rate case proceeding. The Company will use $6.2 million of the electric Rate Plan Settlement Credit in each Rate Year ($18.6 Million in total) to amortize an equivalent amount of its undepreciated investment in pre-Automated Meter Reading meters.

(ce) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

As stipulated by the latest rate order 17-G-0239, Section 2.3, the Company created a new gas deferral credit of $28.42 million ("Rate Plan Settlement Credit"). This will resolve several pending issues addressed in the rate case proceeding. The Company will utilize $8.971 million of the Gas Rate Plan Settlement Credits to fund Gas Safety programs identified in section 7.5 of the Joint Proposal. The Company will also reserve $5 million to fund future gas safety and compliance improvement programs.

(cf) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per rate case 17-E-0238, the Company's electric rates assume an annual rate of municipal conversions to LED technology of ten percent. To enable the Company to implement municipal conversions of up to 20 percent annually, the Company will implement an LED capital investment tracker for municipal LED street light conversions. Each rate year NMPC will reconcile the amount reflected in rates to convert municipal roadway luminaires to LEDs and defer for future recovery from or refund to customers, the revenue requirement impact of the over or under spend capped at an annual 20 percent LED conversion level.

(cg) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per Case 17-E-0238, each rate year the company reconciles the actual level of transaction fee cost to the respective rate allowance ($1.12 million for electric and $0.414 million for gas). Any under-or over-recovery will be deferred for future refund to or recovery from customers, this balance represents the electric portion of the deferral.

(ch) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per Case 17-G-0239, each rate year the company reconciles the actual level of transaction fee cost to the respective rate allowance ($1.12 million for electric and $0.414 million for gas). Any under-or over-recovery will be deferred for future refund to or recovery from customers, this balance represents the gas portion of the deferral.

(ci) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

As set forth through rate case 17-E-0238, the Company will implement a downward-only reconciliation of transmission and distribution vegetation management program costs. The reconciliation will apply to the Company’s aggregate total vegetation management costs over the term of the Rate Plan. ($71.844 million for FY19, $74.653 million for FY20, and $76.220 million for FY21). Any under-expenditure in total program costs in a given Rate Year will be carried forward and reconciled at the end of Rate Year Three.

(cj) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per rate case 17-E-0238, the Company will implement a platform service revenue sharing mechanism for its electric business each year under the rate plan. The Company will retain 20% of fees collected from vendors and defer 80% for future credit to customers.

(ck) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account contains the deferral balance of the Net Utility Plant and depreciation expense reconciliation mechanism. pertaining to the gas service for fiscal years 2019, 2020, and 2021. As determined by rate case 17-G-0239, the Company reconciles its annual actual average net utility plant and depreciation expense revenue requirements to the target amounts. Any underexpenditure in a given rate year will be carried forward and reconciled at the end of rate year three.

(cl) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Balance in this account represents Economic Development Fund Program which provides discounted gas delivery rates to qualified customers. Each Rate Year, the Company will fully reconcile economic development discounts to the amount reflected in rates ($1.150 million, $0.935 million and $0.762 million) for refund to or recovery from customers as authorized in section 10.1.3 in rate case 17-G-0239.

(cm) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Pursuant to rate case 17-G-0239, the Economic Development Grant program offers financial assistance for projects that promote the economic health of New York State by facilitating the creation and or retention of jobs or the increase of business activity in the State. This account contains the deferral balance for the Economic Development grant program deferral for gas, which is the difference between the cumulative allowance and the cumulative actual expenditures. The reconciliation is subject to a down-ward only reconciliation over the term of the rate plan. Any difference between the respective rate allowance and actual program costs in a given rate year will be carried forward and reconciled at the end of rate year Three, with any under-expenditure to be deferred for future use in the Economic Development Grant Programs.

(cn) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The Economic Development Grant Program is funded by PSC in which the Company is funded grants to improve the economic state of the community. This account contains the deferral balance for the Economic Development grant program deferral for electric, which is the difference between the cumulative allowance (as allowed per the PSC) and the cumulative expenditures for the program. Pursuant to case 17-E-0238, the reconciliation is subject to downward-only reconciliations over the term of the rate plan. Any difference between the respective rate allowance and actual program costs in a given rate year will be carried forward and reconciled at the end of rate year Three, with any under-expenditure to be deferred for future use in the program.

(co) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The Affordability Program provides assistance to a small number of eligible low income residential consumers with arrears owed to the company who enter into a payment plan to make current payments and retire arrears. The Affordability Program discontinued new enrollment in its arrear forgiveness program in March 2017. This program was discontinued per rate cases 17-E-0238 & 17-G-0239. The program will be phased-out gradually, as existing customers participating in the program either complete the program, default, or voluntarily remove themselves from the program.

(cp) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Balance in the account represents Property Tax Deferral (Gas) as per rate case 17-G-0239. As stated in Section 10.1.7 of the rate case, the Company will reconcile actual property tax expense to the rate allowance ($43.072 million, $45.311 million, and $47.730 million). The difference will be deferred for future refund to or recovery from customers. The difference between actual tax expense and the rate allowance will be shared 80/20 percent between customers and the Company respectively. In addition, the deferral credit balance was reduced by $9.006 million for a pro-rata allocation pursuant to rate case 17-G-0239, Appendix 5, Schedule 23.

(cq) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The account holds the deferral for Variable Pay - Gas, stipulated by the Niagara Mohawk’s Rate Case 17-G-0239, section 10.1.12 and Appendix 6, Schedule 12. Each rate year, the Company reconciles the actual variable compensation amount with the target amounts reflected in rates and defers for refund to customers any variable pay compensation reflected in rates that are not paid to employees. This is a downward only reconciliation.

(cr) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The purpose of this account is to process rate case 12-E-0201 - NYPA Discount Reconciliation Section 6.2.1. The amount of NYPA Expansion Power, Replacement Power, and High Load Factor Power discounts are fully reconciled each rate year. Any differences between the actual discounts and the level reflected in rates will be deferred and recovered from or credited to customers on a monthly basis. Pursuant to the new electric rate case 17-E-0238, the Company was authorized to create an Electric Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for our customers. In April 2018, $0.999 million was transferred from the NYPA Discount deferral balance to the Electric Rate Plan Deferral Credit.

(cs) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per rate case of 17-E-0238, this mechanism is discontinued, and carrying charges of deferral balance is continued but calculated separately in the Company's Community Carrying Charge account. The company was authorized per rate case 17-E-0238 to create a Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for customers. Accordingly, a portion was transferred from this account to the Electric Rate Plan Deferral Credit.

(ct) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per rate case of 17-E-0238, this mechanism is discontinued, and carrying charges of deferral balance is continued but calculated separately in the Company's Community Carrying Charge account. The company was authorized per rate case 17-E-0238 to create a Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for customers. Accordingly, a portion was transferred from this account to Eclectic Rate Plan Deferral Credit.

(cu) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per rate case of 17-E-0238, this mechanism is discontinued, and carrying charges of deferral balance is continued but calculated separately in the Company's Community Carrying Charge account. The company was authorized per rate case 17-E-0238 to create a Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for customers. Accordingly, a portion was transferred from this account to Electric Rate Plan Deferral Credit.

(cv) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per rate case of 17-E-0238, this mechanism is discontinued, and carrying charges of deferral balance is continued but calculated separately in the Company's Community Carrying Charge account. The company was authorized per rate case 17-E-0238 to create a Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for customers. Accordingly, a portion was transferred from this account to Electric Rate Plan Deferral Credit.

(cw) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The purpose of this account is to record Federal Income Tax (FIT) repair cost, a deferred rate case liability for gas per rate case 12-G-0202, Section 7.2.4. Additionally, in accordance with Case 15-M-0744, this account was used as an offset to the recognition of the earned revenue requirement when analyzing the balance of the Net Utility Plant Depreciation (NUPD) Gas account. Pursuant to the new gas rate case 17-G-0239, this mechanism is discontinued, and the Company was authorized to create an Gas Rate Plan Deferral Credit to promote rate stability and mitigate bill impacts for customers. In April 2018, $28.12 million was transferred from the FIT Repair Costs account to the Gas Rate Plan Deferral Credit.

(cx) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The account holds Pro-Rata Allocation of Deferral Credits amortization stipulated by the latest Rate Case 17-E-0238. The Company will credit customers with a portion of the forecast electric deferral balance in amount of $200.4 Million. For the gradual transition to full cost-of-service rates, the credits are allocated (April 2018 - March 2022) to Rate Year One $116.916 million, Rate Year Two $59.295 million, Rate Year Three $19.46 million and 12 months ending March 31, 2022 $4.729 million. The credits are calculated by taking a pro rata share from the overall projected deferred credit balances.

(cy) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

The account holds Pro-Rata Allocation of Deferral Credit to create the Gas Rate Plan Deferral Credit stipulated by the latest Rate Case 17-G-0239. The Company will credit customers with a portion of the forecast gas deferral balance in amount of $56.123 million. For the gradual transition to full cost-of-service rates, the credits are allocated (April 2018 - March 2022) to Rate Year One $32.315 Million, Rate Year Two $16.924 million, Rate Year Three $5.344 million and 12 months ending March 31, 2022 $1.54 million. The credits are calculated by taking a pro rata share from the overall projected deferred credit balances.

(cz) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per rate case 15-M-0744, the Company is allowed to recover 100 percent of the revenue requirement associated with these proposed capital expenditures. It is reasonable for customers to receive the entire tax benefit associated with bonus depreciation from the expenditures. This account holds the deferred tax benefit for the gas business that is owed to customers. Pursuant to case 17-G-0239, the balance was reduced by pro-rate Gas Rate Plan Deferral Credit in April 2018. There will be no further activity in this account due to the end of the rate case.

(da) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account balance represents the Refund/Surcharge for prior years’ Merchant Function Charge (MFC) imbalance account (i.e. net under- or over-recovered position vs forecast), plus associated carrying charges. The MFC account balance is filed annually for the fiscal year period (April - March) and is submitted to the PSC in May.

(db) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Section 10.1 of the Joint Proposal in Case 17-G-0239 requires the Company to defer interest on regulatory assets and liabilities. This account holds interest on regulatory liabilities (gas) using the pre-tax weighted average cost of capital rate authorized in the current rate case.

(dc) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account represents the Refund/Surcharge for prior years’ SPA (System Performance Adjustment) imbalances (i.e. over/under collection). This SPA account balance is filed annually for the period of September - August and is submitted to the PSC by October 15th.

(dd) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

In accordance with rate case 04-M-0159 - Proceeding on Motion of the Commission to Examine the Safety of Electric Transmission and Distribution Systems, the Company in this account addresses the disposition of savings resulting from the modified Electric Safety Standards through a deferral for customer benefit, inclusive of carrying charges. Pursuant to Case 15-M-0744, the balance at March 2018 was decreased offsetting the NUPD Reconciliation Mechanism in amount $8.234 million. Pursuant to Case 17-E-0238, the deferral was discontinued, and the balance was further reduced by pro-rata deferred credit in amount $6.202 Million.

(de) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per Case 17-G-0239, System Benefit Charge costs (SBC), which include the Clean Energy Fund (CEF) surcharge, will continue to be reconciled pursuant to PSC 219 Rule 31. The Company compares actual CEF expenditures (NYSERDA payment) to the actual CEF collections from customers. Carrying charges are calculated on the deferral balance using the other Customer Capital Rate (net of Tax), which is set annually by the PSC.

(df) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per Case 17-E-0238, SBC costs, which include the CEF surcharge, will continue to be reconciled pursuant to PSC 220 Rule 41. The Company will compare the actual CEF expenditures (NYSERDA Payments) to actual CEF collections. Carrying charges are calculated on the deferral balance using the Other Customer Capital Rate (net of tax), which is set annually by the PSC.

(dg) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

To recognize upfront the Tier Fall to Rotterdam Transmission Line total settlement amount (borne by shareholders) for incremental O&M cost on the maintenance of the steel structures on the Spier Falls to Ro Herdam Transmission line pursuant to case 10-T-0080, and amortization over the average service life of the assets.

(dh) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per Case 17-G-0239, SBC costs, which include the CEF surcharge, will continue to be reconciled pursuant to PSC 219 Rule 31. Carrying charges are calculated on the deferral balance using the Other Customer Capital Rate (net of tax), which is set annually by the PSC. Per Case 14-M-0094, interest for Energy Efficiency Portfolio Standard and CEF is to be segregated in the company's books for the future benefit of ratepayers. The deferred interest related to CEF was reclassified into a separate account on the company's books in June 2018.

(di) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Per Case 17-E-0238, System Benefit Charge costs, which include the Clean Energy Fund (CEF) surcharge, will continue to be reconciled pursuant to Public Service Commission 220 Rule 41. On a monthly basis, the Company will compare monthly amounts due to NYS Energy Research Development Authority (if any) to Actual CEF Collections/Revenues. On a monthly basis, carrying charges are calculated on the deferral balance using the “Other Customer Capital Rate,” which is set annually by the NY PSC.

(dj) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

Energy Efficiency Portfolio Standard interest was re-classed to a separate GL account per Public Service Commission request in July 2018.

(dk) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account represents standalone former System Benefit Charge (SBC) interest deferral. As a result of 2018 PSC request to view Clean Energy Fund deferrals separately from other deferrals, it was necessary to re-class principal and interest balances related to other programs to their own accounts. Per previous PSC Case 14-M-0094 (Issued/Effective January 21, 2016), NYSERDA’s clean energy activities was consolidated under the umbrella of the Clean Energy Fund (CEF). Legacy programs (and their associated deferral balances) existing prior to this case, including the System Benefit Charge, were consolidated into CEF.

(dl) Concept: DescriptionAndPurposeOfOtherRegulatoryLiabilities

This account represents standalone Renewable Portfolio Standard (RPS) interest deferral. As a result of 2018 PSC request to view Clean Energy Fund deferrals separately from other deferrals, it was necessary to re-class principal and interest balances related to Renewable Portfolio Standard to their own accounts. Per previous PSC Case 14-M-0094 (Issued/Effective January 21, 2016), NYSERDA’s clean energy activities was consolidated under the umbrella of the Clean Energy Fund (CEF). Legacy programs (and their associated deferral balances) existing prior to this case, including the Renewable Portfolio Standard, were consolidated into CEF.


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
Electric Operating Revenues
  1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages.
  2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
  3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of each month.
  4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
  5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.
  6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.)
  7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
  8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
  9. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.
Title of Account
(a)
Operating Revenues Year to Date Quarterly/Annual
(b)
Operating Revenues Previous year (no Quarterly)
(c)
MEGAWATT HOURS SOLD Year to Date Quarterly/Annual
(d)
MEGAWATT HOURS SOLD Amount Previous year (no Quarterly)
(e)
AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly)
(f)
AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly)
(g)
1
SalesOfElectricityHeadingAbstract
Sales of Electricity
2
ResidentialSalesAbstract
(440) Residential Sales
1,295,349,921
1,244,399,075
9,952,519
9,134,204
1,269,781
1,243,100
3
CommercialAndIndustrialSalesAbstract
(442) Commercial and Industrial Sales
4
CommercialSalesAbstract
Small (or Comm.) (See Instr. 4)
330,455,990
294,245,175
3,340,677
3,089,384
104,751
102,134
5
IndustrialSalesAbstract
Large (or Ind.) (See Instr. 4)
57,910,684
49,816,324
907,388
893,575
546
542
6
PublicStreetAndHighwayLightingAbstract
(444) Public Street and Highway Lighting
20,216,814
19,393,340
67,086
67,588
2,892
2,922
7
OtherSalesToPublicAuthoritiesAbstract
(445) Other Sales to Public Authorities
8
SalesToRailroadsAndRailwaysAbstract
(446) Sales to Railroads and Railways
9
InterdepartmentalSalesAbstract
(448) Interdepartmental Sales
10
SalesToUltimateConsumersAbstract
TOTAL Sales to Ultimate Consumers
1,703,933,409
1,607,853,914
(e)
14,267,670
13,184,751
1,377,970
1,348,698
11
SalesForResaleAbstract
(447) Sales for Resale
596,785
556,778
6,215
5,906
135
135
12
SalesOfElectricityAbstract
TOTAL Sales of Electricity
1,704,530,194
1,608,410,692
14,273,885
13,190,657
1,378,105
1,348,833
13
ProvisionForRateRefundsAbstract
(Less) (449.1) Provision for Rate Refunds
14
RevenuesNetOfProvisionForRefundsAbstract
TOTAL Revenues Net of Prov. for Refunds
1,704,530,194
1,608,410,692
14,273,885
13,190,657
1,378,105
1,348,833
15
OtherOperatingRevenuesAbstract
Other Operating Revenues
16
ForfeitedDiscounts
(450) Forfeited Discounts
12,630,792
12,561,488
17
MiscellaneousServiceRevenues
(451) Miscellaneous Service Revenues
(a)
6,485,183
(c)
3,822,718
18
SalesOfWaterAndWaterPower
(453) Sales of Water and Water Power
19
RentFromElectricProperty
(454) Rent from Electric Property
14,711,678
16,911,855
20
InterdepartmentalRents
(455) Interdepartmental Rents
21
OtherElectricRevenue
(456) Other Electric Revenues
(b)
66,519,088
(d)
50,698,267
22
RevenuesFromTransmissionOfElectricityOfOthers
(456.1) Revenues from Transmission of Electricity of Others
206,453,609
211,023,642
23
RegionalTransmissionServiceRevenues
(457.1) Regional Control Service Revenues
24
MiscellaneousRevenue
(457.2) Miscellaneous Revenues
25
OtherMiscellaneousOperatingRevenues
Other Miscellaneous Operating Revenues
25.1
OtherMiscellaneousOperatingRevenues
(456.2) Revenues From Distribution of Electricity
590,650,495
644,661,644
26
OtherOperatingRevenues
TOTAL Other Operating Revenues
897,450,845
838,283,080
27
ElectricOperatingRevenues
TOTAL Electric Operating Revenues
2,601,981,039
2,446,693,772


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: MiscellaneousServiceRevenues

Customer Reimbursible Income

(5,788,761)

NSF Fee

412,658

NUB

9,936,331

NUB Credit

(394,609)

Other

2,299,707

Rental

600

Service

19,257

 

 

Total

6,485,183

 

 

 

(b) Concept: OtherElectricRevenue

Open Access Revenue - Transmission

 

Commercial Transmission

11,484,545

Industrial Transmission

3,692,545

Residential Transmission

(1,096,308)

Street Lighting Transmission

12,706

NYPA Marcy

19,009

Supp Agreement O&M

120,818

 

 

Open Access Revenue - Distribution

 

Commercial Distribution

67,083,687

Residential Distribution

17,533,970

Industrial Distribution

997,116

Street Lighting Distribution

3,656,727

Unbilled Distribution Revenue

(6,729,972)

Look Back True up

(2,055,598)

Minor items < $100,000

(1,240)

 

 

Other Electric Revenue - Miscellaneous

 

Sithe O&M Amortization

53,233

Unbilled Transmission Revenue

(585,736)

Deferrals

(23,685,215)

Commodity True-Ups

(4,689,591)

EDF Funds

(2,806,186)

GRT Revenue

1,585,507

ESCO Third Party Billing

841,294

Revenue Decoupling Mech

(12,249,016)

Dunkirk Settlement

(7,098,171)

Capital Tracker Adjustment

13,896

Recharge New York RCD Payment

4,000,953

Other Electric Revenues

14,180,203

Contribute Miscellaneous Electric Revenue

203,478

Supervision & Administration Burden

2,036,434

 

 

Total

66,519,088

 

 

 

(c) Concept: MiscellaneousServiceRevenues

Customer Reimbursible Income

(24,367,384)

Invoice

(22,502)

NSF Fee

375,895

NUB

26,438,897

NUB Credit

(1,057,635)

Other

2,389,354

Rental

38,152

Service

27,941

 

3,822,718

 

(d) Concept: OtherElectricRevenue

Open Access Revenue - Transmission

 

Commercial Transmission

(8,753,075)

Industrial Transmission

(2,814,314)

Residential Transmission

835,563

Street Lighting Transmission

(9,684)

NYPA Marcy

(14,488)

Supp Agreement O&M

(92,083)

 

 

Open Access Revenue - Distribution

 

Commercial Distribution

(51,128,581)

Residential Distribution

(13,363,712)

Industrial Distribution

(759,963)

Street Lighting Distribution

(2,787,016)

Unbilled Distribution Revenue

5,129,323

Look Back True up

1,566,697

Minor items < $100,000

945

 

 

Other Electric Revenue - Miscellaneous

 

Sithe O&M Amortization

(40,572)

Unbilled Transmission Revenue

446,425

Deferrals

18,051,952

Commodity True-Ups

3,574,225

EDF Funds

2,138,766

GRT Revenue

(1,208,412)

ESCO Third Party Billing

(641,202)

Revenue Decoupling Mech

9,335,724

Dunkirk Settlement

5,409,950

Capital Tracker Adjustment

(10,591)

Recharge New York RCD Payment

(3,049,371)

Other Electric Revenues

(10,807,600)

Contribute Miscellaneous Electric Revenue

(155,083)

Supervision & Administration Burden

(1,552,090)

 

 

Total

(50,698,267)

 

(e) Concept: MegawattHoursSoldSalesToUltimateConsumers
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 22, Column: b, Value: 0

Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
  1. The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.
Line No.
Description of Service
(a)
Balance at End of Quarter 1
(b)
Balance at End of Quarter 2
(c)
Balance at End of Quarter 3
(d)
Balance at End of Year
(e)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
TOTAL


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
  1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
  2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading.
  3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers.
  4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly).
  5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
  6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
SCH. 214-S.C.1
2,004
469,953
133
1,119,917
0.2345
2
SCH. 207-S.C.1
9,777,486
1,278,658,636
133
1,119,917
0.1308
3
SCH. 207-S.C.1C
163,955
14,712,962
133
1,119,917
0.0897
4
SCH. 207-S.C.2 DEMAND
2,033
247,045
133
1,119,917
0.1215
5
SCH. 207-S.C.2 NON-DEMAND
7,041
1,261,325
133
1,119,917
0.1791
6
Subtotal (Account 440)
9,952,519
1,295,349,921
133
1,119,917
0.1302
7
SCH. 214-S.C.1
12,049
2,559,652
133
1,119,917
0.2124
8
SCH. 207-S.C.2 DEMAND
1,719,771
178,754,114
133
1,119,917
0.1039
9
SCH. 207-S.C.2 NON-DEMAND
416,491
48,163,273
133
1,119,917
0.1156
10
SCH. 207-S.C.3
1,127,756
100,028,427
133
1,119,917
0.0887
11
SCH. 207-S.C.3A
540,456
34,563,815
133
1,119,917
0.064
12
SCH. 207-S.C.4
221,509
12,677,199
133
1,119,917
0.0572
13
SCH. 207-S.C.7
45,071
2,908,047
133
1,119,917
0.0645
14
SCH. 207-S.C.12
164,962
8,712,146
133
1,119,917
0.0528
15
Subtotal (Account 442)
4,248,065
388,366,673
133
1,119,917
0.0914
16
214-S.C.2
56,758
18,674,435
133
1,119,917
0.329
17
214-S.C.3
1,898
210,619
133
1,119,917
0.111
18
SPECIAL CONTRACTS
8,430
1,331,760
133
1,119,917
0.158
19
Subtotal (Account 444)
67,086
20,216,814
133
1,119,917
0.3014
20
Other Revenues
21
Forfeited Discounts
12,630,792
22
Miscellaneous Service Revenue
6,485,183
23
Rent from Electric Properties
14,711,678
24
Other Electric Revenues
66,519,088
25
Revenues from Trans of Electric
206,453,609
26
Revenues from Dist of Electricity
590,650,496
27
Subtotal - Other Revenues
897,450,846
28
TOTAL Billed
14,267,670
2,601,384,254
133
1,119,917
0.1823
41 TOTAL Billed - All Accounts
42 TOTAL Unbilled Rev. (See Instr. 6) - All Accounts
43 TOTAL - All Accounts


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
SALES FOR RESALE (Account 447)
  1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327).
  2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser.
  3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:

    RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers.

    LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract.

    IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years.

    SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less.

    LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit.

    IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years.

    OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote.

    AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment.

  4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (g) through (k).
  5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided.
  6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
  7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
  8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser.
  9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,line 24.
  10. Footnote entries as required and provide explanations following all required data.
ACTUAL DEMAND (MW) REVENUE
Line No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
FERC Rate Schedule or Tariff Number
(c)
Average Monthly Billing Demand (MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
Megawatt Hours Sold
(g)
Demand Charges ($)
(h)
Energy Charges ($)
(i)
Other Charges ($)
(j)
Total ($) (h+i+j)
(k)
1
Borderline Sales:
2
Central Hudson Gas & Electric
102
13,592
13,592
3
Central Vermont Public
29
4,195
4,195
4
Delaware County Electric
2
521
521
5
Pennsylvania Electric (GPU)
294
34,436
34,436
6
New York State Electric & Gas
5,228
480,615
480,615
7
Rochester Gas & Electric
560
63,426
63,426
8
New York Independent System Operator
15
Subtotal - RQ
(a)
6,215
596,785
596,785
16
Subtotal-Non-RQ
17 Total
6,215
596,785
596,785


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: MegawattHoursSoldRequirementsSales
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 23, Column: b, Value: 0

Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES

If the amount for previous year is not derived from previously reported figures, explain in footnote.

Line No.
Account
(a)
Amount for Current Year
(b)
Amount for Previous Year (c)
(c)
1
PowerProductionExpensesAbstract
1. POWER PRODUCTION EXPENSES
2
SteamPowerGenerationAbstract
A. Steam Power Generation
3
SteamPowerGenerationOperationAbstract
Operation
4
OperationSupervisionAndEngineeringSteamPowerGeneration
(500) Operation Supervision and Engineering
5
FuelSteamPowerGeneration
(501) Fuel
6
SteamExpensesSteamPowerGeneration
(502) Steam Expenses
7
SteamFromOtherSources
(503) Steam from Other Sources
8
SteamTransferredCredit
(Less) (504) Steam Transferred-Cr.
9
ElectricExpensesSteamPowerGeneration
(505) Electric Expenses
10
MiscellaneousSteamPowerExpenses
(506) Miscellaneous Steam Power Expenses
11
RentsSteamPowerGeneration
(507) Rents
12
Allowances
(509) Allowances
13
SteamPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of Lines 4 thru 12)
14
SteamPowerGenerationMaintenanceAbstract
Maintenance
15
MaintenanceSupervisionAndEngineeringSteamPowerGeneration
(510) Maintenance Supervision and Engineering
16
MaintenanceOfStructuresSteamPowerGeneration
(511) Maintenance of Structures
17
MaintenanceOfBoilerPlantSteamPowerGeneration
(512) Maintenance of Boiler Plant
18
MaintenanceOfElectricPlantSteamPowerGeneration
(513) Maintenance of Electric Plant
19
MaintenanceOfMiscellaneousSteamPlant
(514) Maintenance of Miscellaneous Steam Plant
20
SteamPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of Lines 15 thru 19)
21
PowerProductionExpensesSteamPower
TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)
22
NuclearPowerGenerationAbstract
B. Nuclear Power Generation
23
NuclearPowerGenerationOperationAbstract
Operation
24
OperationSupervisionAndEngineeringNuclearPowerGeneration
(517) Operation Supervision and Engineering
25
NuclearFuelExpense
(518) Fuel
26
CoolantsAndWater
(519) Coolants and Water
27
SteamExpensesNuclearPowerGeneration
(520) Steam Expenses
28
SteamFromOtherSourcesNuclearPowerGeneration
(521) Steam from Other Sources
29
SteamTransferredCreditNuclearPowerGeneration
(Less) (522) Steam Transferred-Cr.
30
ElectricExpensesNuclearPowerGeneration
(523) Electric Expenses
31
MiscellaneousNuclearPowerExpenses
(524) Miscellaneous Nuclear Power Expenses
32
RentsNuclearPowerGeneration
(525) Rents
33
NuclearPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of lines 24 thru 32)
34
NuclearPowerGenerationMaintenanceAbstract
Maintenance
35
MaintenanceSupervisionAndEngineeringNuclearPowerGeneration
(528) Maintenance Supervision and Engineering
36
MaintenanceOfStructuresNuclearPowerGeneration
(529) Maintenance of Structures
37
MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration
(530) Maintenance of Reactor Plant Equipment
38
MaintenanceOfElectricPlantNuclearPowerGeneration
(531) Maintenance of Electric Plant
39
MaintenanceOfMiscellaneousNuclearPlant
(532) Maintenance of Miscellaneous Nuclear Plant
40
NuclearPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of lines 35 thru 39)
41
PowerProductionExpensesNuclearPower
TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)
42
HydraulicPowerGenerationAbstract
C. Hydraulic Power Generation
43
HydraulicPowerGenerationOperationAbstract
Operation
44
OperationSupervisionAndEngineeringHydraulicPowerGeneration
(535) Operation Supervision and Engineering
45
WaterForPower
(536) Water for Power
46
HydraulicExpenses
(537) Hydraulic Expenses
47
ElectricExpensesHydraulicPowerGeneration
(538) Electric Expenses
48
MiscellaneousHydraulicPowerGenerationExpenses
(539) Miscellaneous Hydraulic Power Generation Expenses
49
RentsHydraulicPowerGeneration
(540) Rents
50
HydraulicPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of Lines 44 thru 49)
51
HydraulicPowerGenerationContinuedAbstract
C. Hydraulic Power Generation (Continued)
52
HydraulicPowerGenerationMaintenanceAbstract
Maintenance
53
MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration
(541) Mainentance Supervision and Engineering
54
MaintenanceOfStructuresHydraulicPowerGeneration
(542) Maintenance of Structures
55
MaintenanceOfReservoirsDamsAndWaterways
(543) Maintenance of Reservoirs, Dams, and Waterways
56
MaintenanceOfElectricPlantHydraulicPowerGeneration
(544) Maintenance of Electric Plant
57
MaintenanceOfMiscellaneousHydraulicPlant
(545) Maintenance of Miscellaneous Hydraulic Plant
58
HydraulicPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of lines 53 thru 57)
59
PowerProductionExpensesHydraulicPower
TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)
60
OtherPowerGenerationAbstract
D. Other Power Generation
61
OtherPowerGenerationOperationAbstract
Operation
62
OperationSupervisionAndEngineeringOtherPowerGeneration
(546) Operation Supervision and Engineering
63
Fuel
(547) Fuel
64
GenerationExpenses
(548) Generation Expenses
64.1
OperationOfEnergyStorageEquipment
(548.1) Operation of Energy Storage Equipment
65
MiscellaneousOtherPowerGenerationExpenses
(549) Miscellaneous Other Power Generation Expenses
66
RentsOtherPowerGeneration
(550) Rents
67
OtherPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of Lines 62 thru 67)
68
OtherPowerGenerationMaintenanceAbstract
Maintenance
69
MaintenanceSupervisionAndEngineeringOtherPowerGeneration
(551) Maintenance Supervision and Engineering
70
MaintenanceOfStructures
(552) Maintenance of Structures
71
MaintenanceOfGeneratingAndElectricPlant
(553) Maintenance of Generating and Electric Plant
71.1
MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration
(553.1) Maintenance of Energy Storage Equipment
72
MaintenanceOfMiscellaneousOtherPowerGenerationPlant
(554) Maintenance of Miscellaneous Other Power Generation Plant
73
OtherPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of Lines 69 thru 72)
74
PowerProductionExpensesOtherPower
TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)
75
OtherPowerSuplyExpensesAbstract
E. Other Power Supply Expenses
76
PurchasedPower
(555) Purchased Power
740,000,496
702,730,223
76.1
PowerPurchasedForStorageOperations
(555.1) Power Purchased for Storage Operations
77
SystemControlAndLoadDispatchingElectric
(556) System Control and Load Dispatching
78
OtherExpensesOtherPowerSupplyExpenses
(557) Other Expenses
35,708
79
OtherPowerSupplyExpense
TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)
740,036,204
702,730,223
80
PowerProductionExpenses
TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)
740,036,204
702,730,223
81
TransmissionExpensesAbstract
2. TRANSMISSION EXPENSES
82
TransmissionExpensesOperationAbstract
Operation
83
OperationSupervisionAndEngineeringElectricTransmissionExpenses
(560) Operation Supervision and Engineering
2,283,957
2,115,929
85
LoadDispatchReliability
(561.1) Load Dispatch-Reliability
165,673
138,877
86
LoadDispatchMonitorAndOperateTransmissionSystem
(561.2) Load Dispatch-Monitor and Operate Transmission System
5,614,388
5,502,862
87
LoadDispatchTransmissionServiceAndScheduling
(561.3) Load Dispatch-Transmission Service and Scheduling
88
SchedulingSystemControlAndDispatchServices
(561.4) Scheduling, System Control and Dispatch Services
3,111,507
2,586,321
89
ReliabilityPlanningAndStandardsDevelopment
(561.5) Reliability, Planning and Standards Development
409,524
367,072
90
TransmissionServiceStudies
(561.6) Transmission Service Studies
91
GenerationInterconnectionStudies
(561.7) Generation Interconnection Studies
92
ReliabilityPlanningAndStandardsDevelopmentServices
(561.8) Reliability, Planning and Standards Development Services
873,066
741,043
93
StationExpensesTransmissionExpense
(562) Station Expenses
2,374,982
2,692,341
93.1
OperationOfEnergyStorageEquipmentTransmissionExpense
(562.1) Operation of Energy Storage Equipment
94
OverheadLineExpense
(563) Overhead Lines Expenses
1,910,038
2,422,462
95
UndergroundLineExpensesTransmissionExpense
(564) Underground Lines Expenses
188,030
195,058
96
TransmissionOfElectricityByOthers
(565) Transmission of Electricity by Others
97
MiscellaneousTransmissionExpenses
(566) Miscellaneous Transmission Expenses
6,246,480
8,968,324
98
RentsTransmissionElectricExpense
(567) Rents
7,325,605
12,072,795
99
TransmissionOperationExpense
TOTAL Operation (Enter Total of Lines 83 thru 98)
30,503,250
37,803,084
100
TransmissionMaintenanceAbstract
Maintenance
101
MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses
(568) Maintenance Supervision and Engineering
1,341,272
1,415,793
102
MaintenanceOfStructuresTransmissionExpense
(569) Maintenance of Structures
103
MaintenanceOfComputerHardwareTransmission
(569.1) Maintenance of Computer Hardware
428
104
MaintenanceOfComputerSoftwareTransmission
(569.2) Maintenance of Computer Software
66,212
105
MaintenanceOfCommunicationEquipmentElectricTransmission
(569.3) Maintenance of Communication Equipment
2,208
11,435
106
MaintenanceOfMiscellaneousRegionalTransmissionPlant
(569.4) Maintenance of Miscellaneous Regional Transmission Plant
222,580
681,666
107
MaintenanceOfStationEquipmentTransmission
(570) Maintenance of Station Equipment
4,764,819
4,232,157
107.1
MaintenanceOfEnergyStorageEquipmentTransmission
(570.1) Maintenance of Energy Storage Equipment
108
MaintenanceOfOverheadLinesTransmission
(571) Maintenance of Overhead Lines
43,650,456
35,821,832
109
MaintenanceOfUndergroundLinesTransmission
(572) Maintenance of Underground Lines
16,793
300,196
110
MaintenanceOfMiscellaneousTransmissionPlant
(573) Maintenance of Miscellaneous Transmission Plant
983,942
1,410,632
111
TransmissionMaintenanceExpenseElectric
TOTAL Maintenance (Total of Lines 101 thru 110)
50,536,910
43,940,351
112
TransmissionExpenses
TOTAL Transmission Expenses (Total of Lines 99 and 111)
81,040,160
81,743,435
113
RegionalMarketExpensesAbstract
3. REGIONAL MARKET EXPENSES
114
RegionalMarketExpensesOperationAbstract
Operation
115
OperationSupervision
(575.1) Operation Supervision
116
DayAheadAndRealTimeMarketAdministration
(575.2) Day-Ahead and Real-Time Market Facilitation
117
TransmissionRightsMarketAdministration
(575.3) Transmission Rights Market Facilitation
118
CapacityMarketAdministration
(575.4) Capacity Market Facilitation
119
AncillaryServicesMarketAdministration
(575.5) Ancillary Services Market Facilitation
120
MarketMonitoringAndCompliance
(575.6) Market Monitoring and Compliance
121
MarketFacilitationMonitoringAndComplianceServices
(575.7) Market Facilitation, Monitoring and Compliance Services
5,411,455
4,678,558
122
RentsRegionalMarketExpenses
(575.8) Rents
123
RegionalMarketOperationExpense
Total Operation (Lines 115 thru 122)
5,411,455
4,678,558
124
RegionalMarketExpensesMaintenanceAbstract
Maintenance
125
MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses
(576.1) Maintenance of Structures and Improvements
126
MaintenanceOfComputerHardware
(576.2) Maintenance of Computer Hardware
127
MaintenanceOfComputerSoftware
(576.3) Maintenance of Computer Software
128
MaintenanceOfCommunicationEquipmentRegionalMarketExpenses
(576.4) Maintenance of Communication Equipment
129
MaintenanceOfMiscellaneousMarketOperationPlant
(576.5) Maintenance of Miscellaneous Market Operation Plant
130
RegionalMarketMaintenanceExpense
Total Maintenance (Lines 125 thru 129)
131
RegionalMarketExpenses
TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123 and 130)
5,411,455
4,678,558
132
DistributionExpensesAbstract
4. DISTRIBUTION EXPENSES
133
DistributionExpensesOperationAbstract
Operation
134
OperationSupervisionAndEngineeringDistributionExpense
(580) Operation Supervision and Engineering
8,130,624
11,773,615
135
LoadDispatching
(581) Load Dispatching
9,218,672
9,110,486
136
StationExpensesDistribution
(582) Station Expenses
6,592,391
6,714,054
137
OverheadLineExpenses
(583) Overhead Line Expenses
11,385,825
18,580,933
138
UndergroundLineExpenses
(584) Underground Line Expenses
6,932,735
6,423,330
138.1
OperationOfEnergyStorageEquipmentDistribution
(584.1) Operation of Energy Storage Equipment
139
StreetLightingAndSignalSystemExpenses
(585) Street Lighting and Signal System Expenses
772,439
639,048
140
MeterExpenses
(586) Meter Expenses
12,298,898
13,916,440
141
CustomerInstallationsExpenses
(587) Customer Installations Expenses
6,866,419
7,125,244
142
MiscellaneousDistributionExpenses
(588) Miscellaneous Expenses
40,948,655
41,272,754
143
RentsDistributionExpense
(589) Rents
76,045
740,531
144
DistributionOperationExpensesElectric
TOTAL Operation (Enter Total of Lines 134 thru 143)
103,222,703
116,296,435
145
DistributionExpensesMaintenanceAbstract
Maintenance
146
MaintenanceSupervisionAndEngineering
(590) Maintenance Supervision and Engineering
2,863,231
2,798,373
147
MaintenanceOfStructuresDistributionExpense
(591) Maintenance of Structures
1,561,572
1,849,059
148
MaintenanceOfStationEquipment
(592) Maintenance of Station Equipment
7,507,456
7,361,587
148.1
MaintenanceOfEnergyStorageEquipment
(592.2) Maintenance of Energy Storage Equipment
149
MaintenanceOfOverheadLines
(593) Maintenance of Overhead Lines
186,380,412
140,218,006
150
MaintenanceOfUndergroundLines
(594) Maintenance of Underground Lines
9,562,806
8,538,693
151
MaintenanceOfLineTransformers
(595) Maintenance of Line Transformers
1,679,094
2,176,107
152
MaintenanceOfStreetLightingAndSignalSystems
(596) Maintenance of Street Lighting and Signal Systems
6,159,541
5,830,281
153
MaintenanceOfMeters
(597) Maintenance of Meters
620,792
245,353
154
MaintenanceOfMiscellaneousDistributionPlant
(598) Maintenance of Miscellaneous Distribution Plant
3,592,002
3,946,951
155
DistributionMaintenanceExpenseElectric
TOTAL Maintenance (Total of Lines 146 thru 154)
219,926,906
172,964,410
156
DistributionExpenses
TOTAL Distribution Expenses (Total of Lines 144 and 155)
323,149,609
289,260,845
157
CustomerAccountsExpensesAbstract
5. CUSTOMER ACCOUNTS EXPENSES
158
CustomerAccountsExpensesOperationsAbstract
Operation
159
SupervisionCustomerAccountExpenses
(901) Supervision
2,665,983
2,049,558
160
MeterReadingExpenses
(902) Meter Reading Expenses
2,645,147
2,277,159
161
CustomerRecordsAndCollectionExpenses
(903) Customer Records and Collection Expenses
39,930,319
38,769,969
162
UncollectibleAccounts
(904) Uncollectible Accounts
35,873,187
30,824,983
163
MiscellaneousCustomerAccountsExpenses
(905) Miscellaneous Customer Accounts Expenses
2,853,510
3,242,359
164
CustomerAccountExpenses
TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)
83,968,146
77,164,028
165
CustomerServiceAndInformationalExpensesAbstract
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166
CustomerServiceAndInformationalExpensesOperationAbstract
Operation
167
SupervisionCustomerServiceAndInformationExpenses
(907) Supervision
273,003
108,008
168
CustomerAssistanceExpenses
(908) Customer Assistance Expenses
213,600,629
57,958,464
169
InformationalAndInstructionalAdvertisingExpenses
(909) Informational and Instructional Expenses
8,493,639
3,755,987
170
MiscellaneousCustomerServiceAndInformationalExpenses
(910) Miscellaneous Customer Service and Informational Expenses
2,176,777
1,172,870
171
CustomerServiceAndInformationExpenses
TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)
224,544,048
62,995,329
172
SalesExpenseAbstract
7. SALES EXPENSES
173
SalesExpenseOperationAbstract
Operation
174
SupervisionSalesExpense
(911) Supervision
163,621
175
DemonstratingAndSellingExpenses
(912) Demonstrating and Selling Expenses
338,497
173,514
176
AdvertisingExpenses
(913) Advertising Expenses
585,513
493,914
177
MiscellaneousSalesExpenses
(916) Miscellaneous Sales Expenses
47,534
12,482
178
SalesExpenses
TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)
1,135,165
679,910
179
AdministrativeAndGeneralExpensesAbstract
8. ADMINISTRATIVE AND GENERAL EXPENSES
180
AdministrativeAndGeneralExpensesOperationAbstract
Operation
181
AdministrativeAndGeneralSalaries
(920) Administrative and General Salaries
70,114,598
70,886,299
182
OfficeSuppliesAndExpenses
(921) Office Supplies and Expenses
60,723,332
67,526,694
183
AdministrativeExpensesTransferredCredit
(Less) (922) Administrative Expenses Transferred-Credit
23,872,297
184
OutsideServicesEmployed
(923) Outside Services Employed
15,521,851
25,184,142
185
PropertyInsurance
(924) Property Insurance
2,796,065
3,719,672
186
InjuriesAndDamages
(925) Injuries and Damages
8,790,864
10,565,357
187
EmployeePensionsAndBenefits
(926) Employee Pensions and Benefits
100,658,115
92,356,485
188
FranchiseRequirements
(927) Franchise Requirements
189
RegulatoryCommissionExpenses
(928) Regulatory Commission Expenses
9,297,198
22,129,461
190
DuplicateChargesCredit
(929) (Less) Duplicate Charges-Cr.
191
GeneralAdvertisingExpenses
(930.1) General Advertising Expenses
2,105
192
MiscellaneousGeneralExpenses
(930.2) Miscellaneous General Expenses
44,494,026
40,852,488
193
RentsAdministrativeAndGeneralExpense
(931) Rents
37,054,108
34,724,478
194
AdministrativeAndGeneralOperationExpense
TOTAL Operation (Enter Total of Lines 181 thru 193)
325,577,860
367,947,181
195
AdministrativeAndGeneralExpensesMaintenanceAbstract
Maintenance
196
MaintenanceOfGeneralPlant
(935) Maintenance of General Plant
2,223,708
3,286,138
197
AdministrativeAndGeneralExpenses
TOTAL Administrative & General Expenses (Total of Lines 194 and 196)
327,801,568
371,233,319
198
OperationsAndMaintenanceExpensesElectric
TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)
1,787,086,355
1,590,485,647


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
PURCHASED POWER (Account 555)
  1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
  2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
  3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:

    RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers.

    LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract.

    IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years.

    SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less.

    LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit.

    IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years.

    EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges.

    OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment.

    AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment.

  4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided.
  5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
  6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
  7. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote.
  8. The data in column (g) through (n) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13.
  9. Footnote entries as required and provide explanations following all required data.
Actual Demand (MW) POWER EXCHANGES COST/SETTLEMENT OF POWER
Line No.
NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Name of Company or Public Authority (Footnote Affiliations)
(a)
StatisticalClassificationCode
Statistical Classification
(b)
RateScheduleTariffNumber
Ferc Rate Schedule or Tariff Number
(c)
AverageMonthlyBillingDemand
Average Monthly Billing Demand (MW)
(d)
AverageMonthlyNonCoincidentPeakDemand
Average Monthly NCP Demand
(e)
AverageMonthlyCoincidentPeakDemand
Average Monthly CP Demand
(f)
MegawattHoursPurchasedOtherThanStorage
MegaWatt Hours Purchased (Excluding for Energy Storage)
(g)
MegawattHoursPurchasedForEnergyStorage
MegaWatt Hours Purchased for Energy Storage
(h)
EnergyReceivedThroughPowerExchanges
MegaWatt Hours Received
(i)
EnergyDeliveredThroughPowerExchanges
MegaWatt Hours Delivered
(j)
DemandChargesOfPurchasedPower
Demand Charges ($)
(k)
EnergyChargesOfPurchasedPower
Energy Charges ($)
(l)
OtherChargesOfPurchasedPower
Other Charges ($)
(m)
SettlementOfPower
Total (k+l+m) of Settlement ($)
(n)
1
Non - Associated Utilities
2
Central HudsonGas & Elec Corp
220
6,085
6,085
3
New York State Elec & Gas Corp.
3,133
316,586
316,586
4
Rochester Gas & Elec Corp
915
108,013
108,013
5
Other Non-Utilities
6
Black River Hydro C/O Enel - Denley
1,257
81,692
81,692
7
AHDC Hudson Falls
201,703
9,652,676
9,652,676
8
AHDC South Glens Falls
76,907
6,624,449
6,624,449
9
Ampersand - Alder Creek Hyrdro- Kayuta
1,313
1,388
36,412
37,800
10
Azure Mountain
2,443
61,276
4,227
65,503
11
KEI Power Mgmt - Battenkill Hydro Inc
13
13
12
Eagle Creek - Lower Beaver Falls
9,120
14,612
153,916
168,528
13
Eagle Creek - Upper Beaver Falls
4,765
8,227
76,176
84,403
14
Lyonsdale Associates
8,696
695,667
695,667
15
Silverstreet Hydro- Burt Dam Power Co.
457
14,286
950
15,236
16
Dunn Paper-Cellu-Tissue Corp-Natural
20
2
22
17
Eagle Creek-Champlain Spinners-Pwr Co.
809
26,070
1,490
27,560
18
Ampersand - Christine Falls
662
439
29,252
29,691
19
Enel-Copenhagen Hydro-High Falls 845"A
7,303
1,206,644
1,206,644
20
Ampersand - Cranberry Lake Hydro
1,515
1,862
46,636
48,498
21
Black River C/O Enel - Denley - New Gn
4,839
314,549
314,549
22
Enel - Dexter Hydro - HDG - - 845"C"
18,805
3,107,134
3,107,134
23
Enel - Diamond Island Hydro - - 845"F"
5,106
843,685
843,685
24
Edison Hydroelectric
490
13,579
848
14,427
25
Empire Hydro
4,817
6,155
206,533
212,688
26
Erie Blvd Hydropower L.P (Hewittville)
13,209
29,216
401,605
430,821
27
Erie Blvd Hydropower L.P. (Unionville)
12,479
33,143
384,957
418,100
28
FINCH PAPER LLC
191
1,469
5,022
6,491
29
Ampersand - Forestport Hydro
7,232
11,861
198,883
210,744
30
Fort Miller Hydro
22,662
2,016,872
2,016,872
31
Fortis USEnergy (Diana)
6,598
196,480
11,208
207,688
32
FortisUS Energy Corporation (Dolgevil)
1,217
37,232
453
37,685
33
FortisUS Energy Corporation(Moose Riv)
47,396
1,369,812
79,409
1,449,221
34
FortisUS Energy Corporation (Phil.Hyd)
10,197
312,921
16,882
329,803
35
Enel - Fowler Hydro
4,312
225,589
225,589
36
Enel - Hailesboro Hydro #3 - - 845"B"
3,724
615,235
615,235
37
Enel - Hailesboro Hydro #4 - - 845 "G"
10,258
1,694,935
1,694,935
38
Enel - Haliesboro Hydro #6 - - 845 "D"
4,223
697,696
697,696
39
City of Oswego - High Dam
28,486
979,732
979,732
40
Hollingsworth & Vose-Upper
971
971
41
Hollingsworth & Vose-Lower
693
22,826
22,826
42
Ampersand - Hollow Dam Hydro
2,821
86,256
5,005
91,261
43
Enel - Lachute Hydro - - 420 & 421
30,179
27,503
1,051,473
1,078,976
44
Lake Algonquin Hydro
1,582
94,919
94,919
45
Little Falls Hydro
57,914
6,896,964
6,896,964
46
Middle Falls
12,525
22,268
383,486
405,754
47
Ampersand - MT IDA Associates
8,850
26,018
307,518
333,536
48
Eagle Creek - Newport Hydro
5,881
352,871
352,871
49
OAKVALE CONSTRUCTION LTD.
1,956
47,287
3,284
50,571
50
Northline Energy - Wave Hydro
17
1,829
109
1,938
51
Ampersand - Ogdensburg Hydro
9,164
21,456
269,596
291,052
52
Curtis Palmer Hydroelectric
320,948
42,807,967
42,807,967
53
Eagle Creek - Phoenix Hydro
10,370
954,599
954,599
54
Black River Hydro C/O Enel - Port Leyd
16,002
1,040,105
1,040,105
55
Enel - Pyrites - New Hydro
23,507
1,604,009
1,604,009
56
Riverrat Glass & Electric
1
1
57
Rock City Falls - Cotterell Paper
10
401
401
58
Sandy Hollow Hydro
4
131
131
59
Stevens and Thompson (Dahowa)
30,292
39,293
991,485
1,030,778
60
Stillwater Hydro
6,508
514,119
514,119
61
GR Catalyst One - Stillwater Hydro
13,394
1,306,405
1,306,405
62
Ampersand - Tannery Island Power Co.
6,394
183,482
11,595
195,077
63
Enel - Theresa Hydro - - 845 "E"
5,825
962,531
962,531
64
KEI Power Mgmt - Union Falls Hydropwr
8,041
22,562
141,736
164,298
65
Mohawk Valley Water Auth-Utica-SR
1,450
1,097
43,627
44,724
66
Mohawk Valley Water Auth-Utica- TF
667
3,817
17,954
21,771
67
Enel - Valatie Falls Hydro
347
9,566
662
10,228
68
Valley Falls Hydro
7,074
495,153
495,153
69
EGPNA Renewable Energy Partners - VMH
6,588
395,255
395,255
70
Village of Saranac Lake, Inc.
524
497
13,562
14,059
71
Watertown, City of (Contract Plant)
11,264
2,441,021
2,441,021
72
Watervliet Hydro
2,705
97,971
4,194
102,165
73
Northbrook Carthage - West End Dam
21,435
46,736
614,425
661,161
74
Albany Engineering Inc
20,735
755,557
37,573
793,130
75
Ampersand Long Falls - Wamco
4,855
13,668
108,187
121,855
76
General Mills
1,567
3,504
61,484
64,988
77
Onondaga Co Resource Recovery
212,050
410,102
5,072,818
5,482,920
78
Oswego Cty Energy Recovery
4,285
239,282
239,282
79
Fortistar North Tonowanda, Inc. (oxbo)
427,124
427,124
80
US Gypsum Company
1,152
3,030
38,157
41,187
81
Allied Frozen Storage
60
3
2,866
2,869
82
Burrstone Energy Center (Luke)
925
801
47,463
48,264
83
Burrstone Energy Center (Utica)
125
454
4,239
4,693
84
St Elizabeth Medical Center
407
446
15,613
16,059
85
Albany Engineering Corp - Stuyvesant
19,032
652,067
30,170
682,237
86
Sustainable Bioelectric LLC
882
24,967
1,335
26,302
87
Gloversville Johnstown Joint Waste
1,207
3,016
49,459
52,475
88
Re Energy Black River LLc
203,428
481,894
6,029,603
6,511,497
89
MUNICIPALITIES
90
Brockton, Village of
31
1,827
1,827
91
Frankfort Power & Light
363
29,870
29,870
92
Richmondville Power & Light
90
8,603
8,603
93
Wellsville, City of
25
1,492
1,492
94
New York Power Authority - Niagara
191,625
9,528,596
9,528,596
95
Albany Eng.-Green Island Pwr Auth.
39,462
82,139
1,482,342
1,564,481
96
WINDMILL GENERATION
97
FARM WASTE
98
Walker Farms
99
PHOTOVOLTAIC GENERATION
100
Distributed Generation Avoided Costs
9,962
334,061
334,061
101
VDER - Energy Component
218
8,089
8,089
102
VDER - Capacity Component
3,062
3,062
103
VDER - Enivornmental Component
5,274
5,274
104
RTO/ISO
105
New York State ISO
12,952,784
52,234,340
479,612,506
24,205,902
556,052,748
106
Energy Marketers
107
Constellation Zone F Swap
1,808,806
1,808,806
108
Covanta Niagara LP
109
NextEra Marketing
1,812,000
1,812,000
110
BP Energy
6,688,000
6,688,000
111
Exelon Generating
4,190,000
4,190,000
112
PSEG Marketing
2,243,000
2,243,000
113
Evolution Marketing
28,522
28,522
114
TFS Energy Futures
37,248
37,248
115
Dynegy Inc.
800,000
800,000
116
NYSERDA
43,346,457
43,346,457
117
Con Edison
622,000
622,000
118
Canadian Niagara Power
143,059
143,059
15 TOTAL
(a)
14,817,660
69,830,727
602,407,043
67,762,726
740,000,496


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: MegawattHoursPurchasedOtherThanStorage
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 10, Column: b, Value: 0

Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
  1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
  2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
  3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c).
  4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
  5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided.
  6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract.
  7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
  8. Report in column (i) and (j) the total megawatthours received and delivered.
  9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
  10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively.
  11. Footnote entries and provide explanations following all required data.
TRANSFER OF ENERGY REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Line No.
PaymentByCompanyOrPublicAuthority
Payment By (Company of Public Authority) (Footnote Affiliation)
(a)
TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName
Energy Received From (Company of Public Authority) (Footnote Affiliation)
(b)
TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Energy Delivered To (Company of Public Authority) (Footnote Affiliation)
(c)
StatisticalClassificationCode
Statistical Classification
(d)
RateScheduleTariffNumber
Ferc Rate Schedule of Tariff Number
(e)
TransmissionPointOfReceipt
Point of Receipt (Substation or Other Designation)
(f)
TransmissionPointOfDelivery
Point of Delivery (Substation or Other Designation)
(g)
BillingDemand
Billing Demand (MW)
(h)
TransmissionOfElectricityForOthersEnergyReceived
Megawatt Hours Received
(i)
TransmissionOfElectricityForOthersEnergyDelivered
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
RevenuesFromTransmissionOfElectricityForOthers
Total Revenues ($) (k+l+m)
(n)
1
(a)
NYPA (TSC)
(p)
NYPA
(w)
NYPA NYS Municipal Customers
Various
(aj)
NYPA NYS Muni
89,496
89,496
657,545
657,545
2
(b)
NYPA
(q)
NYPA
(x)
Niagara Frontier Transit Authoriy
Various
Niagara Frontier
3
(c)
NYPA
(r)
NYPA
(y)
NYPA NYS Municipal Customers
Various
(ak)
NYPA NYS Muni
8
21,352
21,352
4
(d)
NYPA
(s)
NYPA
Consolidated Edison
Various
Crescent Vischer
5
Central Hudson Gas & Electric
Central Hudson Gas & Electric
Central Hudson Gas & Electric
Nine Mile 2 Station
Central Hudson Gas
103
2,175,360
2,175,360
6
Central Hudson Gas & Electric
Central Hudson Gas & Electric
Central Hudson Gas & Electric
North Catskill
North Catskill
195,300
195,300
7
(e)
LIPA
(t)
NYPA
(z)
LIPA
Fitzpatrick
Consolidated Edison
142
2,999,040
2,999,040
8
(f)
LIPA
(u)
LIPA
(aa)
LIPA
Nine Mile 2 Station
Consolidated Edison
206
4,350,720
4,350,720
9
(g)
NYSEG
(v)
NYSEG
(ab)
NYSEG
Various
Various
464
9,354,240
9,354,240
10
City of Watertown
City of Watertown
City of Watertown
Watertown Hydro
(al)
Watertown Muni
11,314
11,314
83,543
83,543
11
(h)
Selkirk Co-Gen
Selkirk Co-Gen
Consolidated Edison
Selkirk Station
Consolidated Edison
12
(i)
Sithe Independence
Sithe Independence
Consolidated Edison
Sithe Station
Consolidated Edison
13
(j)
Indeck
Indeck
Consolidated Edison
Indeck Station
Consolidated Edison
14
(k)
Muni Wheels / OATT
Various
Various
Various
Various
15
(l)
RG&E Tx Capacity Charge
Various
Various
Various
Various
319,896
319,896
16
(m)
ISO External Trans. TSC
Various
Various
Various
Various
291,134
291,134
2,076,066
2,076,066
17
(n)
NYMPA, Misc Villages, Jamestown, Griffiss (TS)
Various
Various
(ai)
N/A
Various
2,820,314
2,820,314
20,623,640
20,623,640
18
New York Power Authority
New York Power Authority
New York Power Authority
Edic Substation
Edic Substation
1,021,388
1,021,388
19
Brookfield Renewable
Support
Support
Brookfield Renewable
Brookfield Renewable
(an)
22,952
22,952
20
Carthage
Support
Support
Carthage
Carthage
(ao)
5,681
5,681
21
City of Oswego
Support
Support
City of Oswego
City of Oswego
(ap)
6,200
6,200
22
City of Salamanca
Support
Support
City of Salamanca
City of Salamanca
(aq)
2,400
2,400
23
Sithe
Support
Support
Sithe
Sithe
(ar)
75,240
75,240
24
Indeck Olean
Support
Support
Indeck Olean
Indeck Olean
(as)
24,637
24,637
25
Lake Colby
Support
Support
Lake Colby
Lake Colby
(at)
4,436
4,436
26
Marcy Facts
Support
Support
Marcy Facts
Marcy Facts
(au)
193,429
193,429
27
Rensselaer Generating
Support
Support
Rensselaer Generatig
(am)
Rensselaer Generatin
(av)
73,455
73,455
28
American Refuel Covanta
Support
Support
American Ref-Fuel Gt
American Ref-Fuel Gt
(aw)
24,074
24,074
29
South Glens Falls
Support
Support
Existing Circuit at
High Side of GSU aty
(ax)
2,523
2,523
30
Copenhagen Associates
Support
Support
Middle Road Station
Middle Road Station
(ay)
18,987
18,987
31
(o)
Lyonsdale Biomass, LLC
Support
Support
Lyonsdale facility
Burrows paper tap
(az)
2,430
2,430
32
Northern Electric Power
Support
Support
Existing Circuit - n
High side of GSU aty
(ba)
8,411
8,411
33
Hydro Development Group
Support
Support
Fowler Facilities
Fowler Facilities
(bb)
26,249
26,249
34
Canadian Niagara Power
Support
Support
Fort Erie
Fort Erie
(bc)
100,362
100,362
35 TOTAL
923
3,212,258
3,212,258
19,199,256
25,070,546
44,269,802


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: PaymentByCompanyOrPublicAuthority

NYPA -New York Power Authority
TSC - Transmission Service Charge

(b) Concept: PaymentByCompanyOrPublicAuthority

NYPA -New York Power Authority

(c) Concept: PaymentByCompanyOrPublicAuthority

NYPA -New York Power Authority

(d) Concept: PaymentByCompanyOrPublicAuthority

NYPA -New York Power Authority

(e) Concept: PaymentByCompanyOrPublicAuthority

LIPA - Long Island Power Authority

(f) Concept: PaymentByCompanyOrPublicAuthority

LIPA - Long Island Power Authority

(g) Concept: PaymentByCompanyOrPublicAuthority

NYSEG - New York Gas and Electric

(h) Concept: PaymentByCompanyOrPublicAuthority

Contract Expired

(i) Concept: PaymentByCompanyOrPublicAuthority

Contract Expired

(j) Concept: PaymentByCompanyOrPublicAuthority

Contract Expired

(k) Concept: PaymentByCompanyOrPublicAuthority

Contract Expired
Muni -Municipals
Wheels- Wheeling
OATT- Open Access Transmission Tariff

(l) Concept: PaymentByCompanyOrPublicAuthority

RG&E TX Capcity Charge- Rochester Gas & Electric Transmission Capacity Charge

(m) Concept: PaymentByCompanyOrPublicAuthority

ISO External Trans - Independent System Operation External Transmission

TSC - Transmission Service Charge

(n) Concept: PaymentByCompanyOrPublicAuthority

NYMP- New York Municipal Power Authority

Misc- Miscellaneous

(o) Concept: PaymentByCompanyOrPublicAuthority

LLC- Limited Liability Company

(p) Concept: TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName

NYPA -New York Power Authority

(q) Concept: TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName

NYPA -New York Power Authority

(r) Concept: TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName

NYPA -New York Power Authority

(s) Concept: TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName

NYPA -New York Power Authority

(t) Concept: TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName

NYPA -New York Power Authority

(u) Concept: TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName

LIPA - Long Island Power Authority

(v) Concept: TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName

NYSEG - New York Gas and Electric

(w) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName

NYPA NYS -New York Power Authority New York State

(x) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName

Contract Expired

(y) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName

NYPA -New York Power Authority

NYS - New York State

(z) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName

LIPA - Long Island Power Authority

(aa) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName

LIPA - Long Island Power Authority

(ab) Concept: TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName

NYSEG - New York Gas and Electric

(ac) Concept: RateScheduleTariffNumber

NYISO - New York Independent System Operation

OATT- Open Access Transmission Tariff

(ad) Concept: RateScheduleTariffNumber

NYISO - New York Independent System Operation
OATT- Open Access Transmission Tariff

(ae) Concept: RateScheduleTariffNumber

NYISO - New York Independent System Operation
OATT- Open Access Transmission Tariff

(af) Concept: RateScheduleTariffNumber

NYISO - New York Independent System Operation
OATT- Open Access Transmission Tariff

(ag) Concept: RateScheduleTariffNumber

NYISO - New York Independent System Operation
OATT- Open Access Transmission Tariff

(ah) Concept: RateScheduleTariffNumber

CLA 036-25.1-3.151

(ai) Concept: TransmissionPointOfReceipt

N/A- Not Applicable

(aj) Concept: TransmissionPointOfDelivery

NYPA -New York Power Authority
NYS -New York State
Muni -Municipals

(ak) Concept: TransmissionPointOfDelivery

NYPA -New York Power Authority
NYS -New York State
Muni -Municipals

(al) Concept: TransmissionPointOfDelivery

Muni -Municipals

(am) Concept: TransmissionPointOfDelivery

Rensselaer Generating

(an) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(ao) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(ap) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(aq) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(ar) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(as) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(at) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(au) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(av) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(aw) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(ax) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(ay) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(az) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(ba) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(bb) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement

(bc) Concept: OtherChargesRevenueTransmissionOfElectricityForOthers

Operating & Maintenance Expense Agreement


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
TRANSMISSION OF ELECTRICITY BY ISO/RTOs
  1. Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO.
  2. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a).
  3. In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
  4. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided.
  5. In column (d) report the revenue amounts as shown on bills or vouchers.
  6. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.
Payment Received by (Transmission Owner Name)
(a)
Statistical Classification
(b)
FERC Rate Schedule or Tariff Number
(c)
Total Revenue by Rate Schedule or Tariff
(d)
Total Revenue
(e)
1
(a)
NiMo - TCC Auction Revenue
(b)
NYISO OATT
49,910,803
177,145,380
2
NiMo - Congestion Revenue
NYISO OATT
3
NiMo - Congestion Balancing
NYISO OATT
8,805,343
16,209,474
4
NiMo - TCC Monthly Revenue
NYISO OATT
221,462
1,247,901
40
TOTAL
41,326,922
162,183,807


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: TransmissionPaymentByCompanyOrPublicAuthority

TCC - Transmission Congestion Contract

(b) Concept: RateScheduleTariffNumber

NYISO- New York Independent System Operator

OATT- Open Access Transmision Tariff


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
  1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter.
  2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported.
  3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
    FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
  4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
  5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
  6. Enter ""TOTAL"" in column (a) as the last line.
  7. Footnote entries and provide explanations following all required data.
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.
NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Name of Company or Public Authority (Footnote Affiliations)
(a)
StatisticalClassificationCode
Statistical Classification
(b)
TransmissionOfElectricityByOthersEnergyReceived
MegaWatt Hours Received
(c)
TransmissionOfElectricityByOthersEnergyDelivered
MegaWatt Hours Delivered
(d)
DemandChargesTransmissionOfElectricityByOthers
Demand Charges ($)
(e)
EnergyChargesTransmissionOfElectricityByOthers
Energy Charges ($)
(f)
OtherChargesTransmissionOfElectricityByOthers
Other Charges ($)
(g)
ChargesForTransmissionOfElectricityByOthers
Total Cost of Transmission ($)
(h)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
TOTAL


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.
Description
(a)
Amount
(b)
1
IndustryAssociationDues
Industry Association Dues
2
NuclearPowerResearchExpenses
Nuclear Power Research Expenses
3
OtherExperimentalAndGeneralResearchExpenses
Other Experimental and General Research Expenses
4
PublicationAndDistributionExpensesForSecuritiesToStockholders
Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities
5
OtherMiscellaneousGeneralExpenses
Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6
Research and Development Activities
1,482,328
7
Environmental Activities Expenses
29,415,750
8
Meter Data Services
1,667,268
9
Expense as Built
7,998,368
10
Computer Network Expenses
1,745,517
11
Other
2,184,795
46
MiscellaneousGeneralExpenses
TOTAL
44,494,026


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
  1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405).
  2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
  3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year.
    Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used.
    In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used.
    For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
  4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Line No.
FunctionalClassificationAxis
Functional Classification
(a)
DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments
Depreciation Expense (Account 403)
(b)
DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments
Depreciation Expense for Asset Retirement Costs (Account 403.1)
(c)
AmortizationOfLimitedTermPlantOrProperty
Amortization of Limited Term Electric Plant (Account 404)
(d)
AmortizationOfOtherElectricPlant
Amortization of Other Electric Plant (Acc 405)
(e)
DepreciationAndAmortization
Total
(f)
1
Intangible Plant
321,454
321,454
2
Steam Production Plant
3
Nuclear Production Plant
4
Hydraulic Production Plant-Conventional
32,543
32,543
5
Hydraulic Production Plant-Pumped Storage
6
Other Production Plant
80,707
80,707
7
Transmission Plant
64,476,570
432,420
64,908,990
8
Distribution Plant
145,912,815
550,220
146,463,035
9
Regional Transmission and Market Operation
10
General Plant
12,144,229
12,144,229
11
Common Plant-Electric
6,992,236
6,992,236
12
TOTAL
229,639,100
982,640
321,454
230,943,194
B. Basis for Amortization Charges
Base and Rates for Amortization of Electric Plant(404 & 405) Utility Account Base Rate Account 404 NIMO 101/106 35040 32,168 1.31% NIMO 101/106 36015 147 1.33% NIMO 101/106 36025 38,284 1.33% Account 405 Base Rate 36 101 30200 HUDSON FALLS RESERVOIR 2,417 5.56% 36 101 30200 SOUTH GLENS FALLS HYDR 251 5.94% 30200 Total 2,667 5.59% *Base is calculated in thousands
C. Factors Used in Estimating Depreciation Charges
Line No.
AccountNumberFactorsUsedInEstimatingDepreciationCharges
Account No.
(a)
DepreciablePlantBase
Depreciable Plant Base (in Thousands)
(b)
UtilityPlantEstimatedAverageServiceLife
Estimated Avg. Service Life
(c)
UtilityPlantNetSalvageValuePercentage
Net Salvage (Percent)
(d)
UtilityPlantAppliedDepreciationRate
Applied Depr. Rates (Percent)
(e)
MortalityCurveType
Mortality Curve Type
(f)
UtilityPlantWeightedAverageRemainingLife
Average Remaining Life
(g)
12
0 years
0 years
13
6,358
0 years
0 years
14
1,269
0 years
0 years
15
7,627
0 years
0 years
16
0 years
0 years
17
0 years
0 years
18
0 years
0 years
19
0 years
0 years
20
1,854
0 years
4.54
0 years
21
1,854
0 years
0 years
22
0 years
0 years
23
3,480
0 years
0 years
24
7,083
0 years
0 years
25
1,722
0 years
0 years
26
62,685
0 years
0 years
27
33,067
(a)
75 years
1.2
1.32
H5
(bm)
37 years
28
48,709
(b)
55 years
33
2.42
R2.5
(bn)
33 years
29
1,216,255
(c)
45 years
2.53
L0.5
0 years
30
2,967
(d)
45 years
2.53
L0.5
0 years
31
51,759
(e)
25 years
5
4.2
H5
(bo)
7 years
32
121,323
(f)
75 years
35
1.8
R4
(bp)
29 years
33
850,940
(g)
65 years
45
2.23
R2.5
(bq)
52 years
34
927
(h)
80 years
1.69
R2.5
0 years
35
241,779
(i)
80 years
1.69
R2.5
0 years
36
335,375
(j)
80 years
1.69
R2.5
0 years
37
96
0 years
4.52
0 years
38
12,056
(k)
85 years
1.24
R3
0 years
39
30,211
(l)
85 years
1.24
R3
0 years
40
147,264
(m)
80 years
27
1.59
R3
(br)
54 years
41
10,259
(n)
75 years
1.33
H4
(bs)
60 years
42
3,177,957
0 years
0 years
43
0 years
0 years
44
32
0 years
0 years
45
10,286
0 years
0 years
46
147
(o)
75 years
1.33
0 years
47
463
0 years
0 years
48
44,091
(p)
75 years
1.33
0 years
49
49,587
(q)
80 years
33
1.66
R2.5
(bt)
54 years
50
720,684
(r)
60 years
1.92
0 years
51
2,879
(s)
60 years
1.92
0 years
52
89,114
(t)
25 years
5
4.2
S3
(bu)
8 years
53
1,191,823
(u)
65 years
20
1.85
R1.5
(bv)
51 years
54
1,323,550
(v)
60 years
40
2.33
R4
(bw)
38 years
55
2,735
(w)
22 years
4.52
L1
0 years
56
116,093
(x)
70 years
1.66
R0.5
0 years
57
98,993
(y)
70 years
1.66
R0.5
0 years
58
688,005
(z)
75 years
30
1.73
R3
(bx)
60 years
59
72,894
(aa)
40 years
2.65
R1.5
0 years
60
583,365
(ab)
40 years
2.65
R1.5
0 years
61
354,929
(ac)
40 years
35
3.38
R2
(by)
24 years
62
335,190
(ad)
55 years
45
2.64
R4
(bz)
33 years
63
9,783
(ae)
85 years
5
1.24
H4
(ca)
48 years
64
163,896
(af)
85 years
20
1.41
H2.5
(cb)
61 years
65
62,212
(ag)
20 years
25
6.25
H0.5
(cc)
16 years
66
56,198
(ah)
20 years
25
6.25
H0.5
(cd)
17 years
67
20,927
(ai)
20 years
1
5.05
H3
(ce)
13 years
68
32,592
(aj)
20 years
1
5.05
H3
(cf)
9 years
69
7,788
(ak)
42 years
11
2.64
R1.5
(cg)
25 years
70
56
0 years
2.64
0 years
71
43,499
(al)
60 years
30
2.17
H1.5
0 years
72
47,128
(am)
20 years
30
6.5
S3
(ch)
11 years
73
130,776
(an)
60 years
30
2.17
H1.5
0 years
74
53,510
(ao)
20 years
30
6.5
S3
(ci)
10 years
75
2,144
(ap)
25 years
30
5.2
S3
0 years
76
1,694
0 years
0 years
77
6,317,063
0 years
0 years
78
0 years
0 years
79
2,339
0 years
0 years
80
2
0 years
0 years
81
110,265
(aq)
45 years
13
2.51
H0.5
(cj)
36 years
82
1,746
(ar)
22 years
4.55
SQ
0 years
83
1,112
(as)
22 years
4.55
SQ
0 years
84
5,187
(at)
5 years
20
SQ
0 years
85
56
(au)
15 years
3.33
0 years
86
8,007
(av)
15 years
50
3.33
SQ
(ck)
14 years
87
60
(aw)
22 years
4.55
SQ
(cl)
1 year
88
6,548
(ax)
22 years
4.55
SQ
0 years
89
2,511
(ay)
22 years
4.55
SQ
0 years
90
38,837
(az)
22 years
4.55
SQ
0 years
91
12,632
(ba)
22 years
4.55
SQ
0 years
92
279
(bb)
22 years
4.55
SQ
(cm)
17 years
93
4,380
(bc)
22 years
4.55
SQ
0 years
94
43,429
(bd)
8 years
12.5
SQ
0 years
95
9,296
(be)
22 years
4.5
SQ
0 years
96
49
(bf)
22 years
4.5
SQ
0 years
97
6,682
(bg)
22 years
4.5
SQ
(cn)
10 years
98
6,444
(bh)
22 years
4.5
SQ
(co)
7 years
99
9,009
(bi)
22 years
4.5
SQ
0 years
100
632
(bj)
22 years
4.5
SQ
(cp)
1 year
101
763
(bk)
22 years
4.5
SQ
0 years
102
183
(bl)
22 years
4.5
SQ
0 years
103
31,661
0 years
0 years
104
302,109
0 years
0 years
105
9,806,610
0 years
0 years


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(b) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 55
(c) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 45
(d) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 45
(e) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 25
(f) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(g) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(h) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 80
(i) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 80
(j) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 80
(k) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 85
(l) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 85
(m) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 80
(n) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(o) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(p) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(q) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 80
(r) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 60
(s) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 60
(t) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 25
(u) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(v) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 60
(w) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(x) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 70
(y) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 70
(z) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(aa) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 40
(ab) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 40
(ac) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 40
(ad) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 55
(ae) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 85
(af) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 85
(ag) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(ah) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(ai) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(aj) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(ak) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 42
(al) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 60
(am) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(an) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 60
(ao) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(ap) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 25
(aq) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 45
(ar) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(as) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(at) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 5
(au) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 15
(av) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 15
(aw) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(ax) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(ay) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(az) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(ba) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(bb) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(bc) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(bd) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 8
(be) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(bf) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(bg) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(bh) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(bi) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(bj) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(bk) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(bl) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(bm) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 37.22
(bn) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 33.09
(bo) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 7.12
(bp) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 29.38
(bq) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 52.08
(br) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 53.75
(bs) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 59.95
(bt) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 53.57
(bu) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 8.22
(bv) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 51.45
(bw) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 38.15
(bx) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 59.92
(by) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 24.44
(bz) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 33.49
(ca) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 48.11
(cb) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 60.61
(cc) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 15.88
(cd) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 16.51
(ce) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 12.87
(cf) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 9.03
(cg) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 25.01
(ch) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 10.8
(ci) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 10.42
(cj) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 36.19
(ck) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 14.5
(cl) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 1
(cm) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 16.71
(cn) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 10.5
(co) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 7.42
(cp) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 1

Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
REGULATORY COMMISSION EXPENSES
  1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
  2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years.
  3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
  4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
  5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
EXPENSES INCURRED DURING YEAR
Line No.
RegulatoryCommissionDescription
Description (Furnish name of regulatory commission or body the docket or case number and a description of the case)
(a)
RegulatoryExpensesAssessedByRegulatoryCommission
Assessed by Regulatory Commission
(b)
RegulatoryExpensesOfUtility
Expenses of Utility
(c)
RegulatoryCommissionExpensesAmount
Total Expenses for Current Year
(d)
OtherRegulatoryAssetsRegulatoryCommissionExpenses
Deferred in Account 182.3 at Beginning of Year
(e)
NameOfDepartmentRegulatoryCommissionExpensesCharged
Department
(f)
AccountNumberRegulatoryCommissionExpensesCharged
Account No.
(g)
RegulatoryCommissionExpenses
Amount
(h)
RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets
Deferred to Account 182.3
(i)
DeferredRegulatoryCommissionExpensesAmortizedInContraAccount
Contra Account
(j)
DeferredRegulatoryCommissionExpensesAmortized
Amount
(k)
OtherRegulatoryAssetsRegulatoryCommissionExpenses
Deferred to Account 182.3 End of Year
(l)
1
Public Service Commission of the State of
2
New York (NYPSC)
4
Expenses of the NYPSC
5
General and Temporary Assessments 18-A
10,311,842
10,311,842
822,473
Electric
8,215,028
1,753,161
6
Gas
2,096,814
8
Rate Case Expenses Deferred
1,353,665
9
Amortization (Apr 2018 - Mar 2021)
Electric
88,575
369,750
847,960
10
Gas
72,470
297,000
12
Management Audit Expenses Deferred
13
Amortization (Apr 2018 - Mar 2023)
Electric
112,399
50,400
76,340
14
Gas
23,941
9,600
16
MISCELLANEOUS:
17
1,052,406
1,052,406
18
Miscellaneous FERC and PSC expenses relating
Electric
862,994
19
to permit fees, regulatory requirements, legal
Gas
189,412
20
fees, environmental activities, and other
21
various matters.
46
TOTAL
10,311,842
1,052,406
11,364,248
531,192
11,364,248
297,385
726,750
828,861


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
  1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts).
  2. Indicate in column (a) the applicable classification, as shown below:
    Classifications:
    1. Electric R, D and D Performed Internally:
      1. Generation
        1. hydroelectric
          1. Recreation fish and wildlife
          2. Other hydroelectric
        2. Fossil-fuel steam
        3. Internal combustion or gas turbine
        4. Nuclear
        5. Unconventional generation
        6. Siting and heat rejection
      2. Transmission
        1. Overhead
        2. Underground
      3. Distribution
      4. Regional Transmission and Market Operation
      5. Environment (other than equipment)
      6. Other (Classify and include items in excess of $50,000.)
      7. Total Cost Incurred
    2. Electric, R, D and D Performed Externally:
      1. Research Support to the electrical Research Council or the Electric Power Research Institute
      2. Research Support to Edison Electric Institute
      3. Research Support to Nuclear Power Groups
      4. Research Support to Others (Classify)
      5. Total Cost Incurred
  3. Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity.
  4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e).
  5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year.
  6. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est.""
  7. Report separately research and related testing facilities operated by the respondent.
AMOUNTS CHARGED IN CURRENT YEAR
Line No.
ResearchDevelopmentAndDemonstrationClassification
Classification
(a)
ResearchDevelopmentAndDemonstrationDescription
Description
(b)
ResearchDevelopmentAndDemonstrationCostsIncurredInternally
Costs Incurred Internally Current Year
(c)
ResearchDevelopmentAndDemonstrationCostsIncurredExternally
Costs Incurred Externally Current Year
(d)
AccountNumberForResearchDevelopmentAndDemonstrationCosts
Amounts Charged In Current Year: Account
(e)
ResearchDevelopmentAndDemonstrationCosts
Amounts Charged In Current Year: Amount
(f)
ResearchDevelopmentAndDemonstrationExpenditures
Unamortized Accumulation
(g)
1
Other
R&D Related Activities
150,417
1,331,911
1,482,328
2
R&D Operations
3
$25,335 in Transmission - Internal
4
$336,252 in Transmissio - External


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
DISTRIBUTION OF SALARIES AND WAGES

Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.

Line No.
Classification
(a)
Direct Payroll Distribution
(b)
Allocation of Payroll Charged for Clearing Accounts
(c)
Total
(d)
1
SalariesAndWagesElectricAbstract
Electric
2
SalariesAndWagesElectricOperationAbstract
Operation
3
SalariesAndWagesElectricOperationProduction
Production
4
SalariesAndWagesElectricOperationTransmission
Transmission
301,861
5
SalariesAndWagesElectricOperationRegionalMarket
Regional Market
6
SalariesAndWagesElectricOperationDistribution
Distribution
71,888,394
7
SalariesAndWagesElectricOperationCustomerAccounts
Customer Accounts
22,843,452
8
SalariesAndWagesElectricOperationCustomerServiceAndInformational
Customer Service and Informational
10,663,337
9
SalariesAndWagesElectricOperationSales
Sales
529,357
10
SalariesAndWagesElectricOperationAdministrativeAndGeneral
Administrative and General
57,206,156
11
SalariesAndWagesElectricOperation
TOTAL Operation (Enter Total of lines 3 thru 10)
163,432,557
12
SalariesAndWagesElectricMaintenanceAbstract
Maintenance
13
SalariesAndWagesElectricMaintenanceProduction
Production
14
SalariesAndWagesElectricMaintenanceTransmission
Transmission
37,505
15
SalariesAndWagesElectricMaintenanceRegionalMarket
Regional Market
16
SalariesAndWagesElectricMaintenanceDistribution
Distribution
73,788,420
17
SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral
Administrative and General
18
SalariesAndWagesElectricMaintenance
TOTAL Maintenance (Total of lines 13 thru 17)
73,825,925
19
SalariesAndWagesElectricOperationAndMaintenanceAbstract
Total Operation and Maintenance
20
SalariesAndWagesElectricProduction
Production (Enter Total of lines 3 and 13)
21
SalariesAndWagesElectricTransmission
Transmission (Enter Total of lines 4 and 14)
339,366
22
SalariesAndWagesElectricRegionalMarket
Regional Market (Enter Total of Lines 5 and 15)
23
SalariesAndWagesElectricDistribution
Distribution (Enter Total of lines 6 and 16)
145,676,814
24
SalariesAndWagesElectricCustomerAccounts
Customer Accounts (Transcribe from line 7)
22,843,452
25
SalariesAndWagesElectricCustomerServiceAndInformational
Customer Service and Informational (Transcribe from line 8)
10,663,337
26
SalariesAndWagesElectricSales
Sales (Transcribe from line 9)
529,357
27
SalariesAndWagesElectricAdministrativeAndGeneral
Administrative and General (Enter Total of lines 10 and 17)
57,206,156
28
SalariesAndWagesElectricOperationAndMaintenance
TOTAL Oper. and Maint. (Total of lines 20 thru 27)
237,258,482
209,055
237,049,427
29
SalariesAndWagesGasAbstract
Gas
30
SalariesAndWagesGasOperationAbstract
Operation
31
SalariesAndWagesGasOperationProductionManufacturedGas
Production - Manufactured Gas
32
SalariesAndWagesGasOperationProductionNaturalGas
Production-Nat. Gas (Including Expl. And Dev.)
33
SalariesAndWagesGasOperationOtherGasSupply
Other Gas Supply
7,724
34
SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing
Storage, LNG Terminaling and Processing
1,140,810
35
SalariesAndWagesGasOperationTransmission
Transmission
1,140,127
36
SalariesAndWagesGasOperationDistribution
Distribution
19,608,921
37
SalariesAndWagesGasCustomerAccounts
Customer Accounts
5,981,642
59
SalariesAndWagesGasCustomerServiceAndInformational
Customer Service and Informational
2,631,981
60
SalariesAndWagesGasSales
Sales
409,229
40
SalariesAndWagesGasOperationAdministrativeAndGeneral
Administrative and General
16,602,270
41
SalariesAndWagesGasOperation
TOTAL Operation (Enter Total of lines 31 thru 40)
47,522,704
42
SalariesAndWagesGasMaintenanceAbstract
Maintenance
43
SalariesAndWagesGasMaintenanceProductionManufacturedGas
Production - Manufactured Gas
44
SalariesAndWagesGasMaintenanceProductionNaturalGas
Production-Natural Gas (Including Exploration and Development)
45
SalariesAndWagesGasMaintenanceOtherGasSupply
Other Gas Supply
46
SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing
Storage, LNG Terminaling and Processing
47
SalariesAndWagesGasMaintenanceTransmission
Transmission
802,736
48
SalariesAndWagesGasMaintenanceDistribution
Distribution
10,380,337
49
SalariesAndWagesGasMaintenanceAdministrativeAndGeneral
Administrative and General
50
SalariesAndWagesGasMaintenance
TOTAL Maint. (Enter Total of lines 43 thru 49)
11,183,073
51
SalariesAndWagesGasOperationAndMaintenanceAbstract
Total Operation and Maintenance
52
SalariesAndWagesGasProductionManufacturedGas
Production-Manufactured Gas (Enter Total of lines 31 and 43)
53
SalariesAndWagesGasProductionNaturalGas
Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54
SalariesAndWagesGasOtherGasSupply
Other Gas Supply (Enter Total of lines 33 and 45)
7,724
55
SalariesAndWagesGasStorageLngTerminalingAndProcessing
Storage, LNG Terminaling and Processing (Total of lines 31 thru
1,140,810
56
SalariesAndWagesGasTransmission
Transmission (Lines 35 and 47)
1,942,863
57
SalariesAndWagesGasDistribution
Distribution (Lines 36 and 48)
29,989,258
58
SalariesAndWagesGasCustomerAccounts
Customer Accounts (Line 37)
5,981,642
59
SalariesAndWagesGasCustomerServiceAndInformational
Customer Service and Informational (Line 38)
2,631,981
60
SalariesAndWagesGasSales
Sales (Line 39)
409,229
61
SalariesAndWagesGasAdministrativeAndGeneral
Administrative and General (Lines 40 and 49)
16,602,270
62
SalariesAndWagesGasOperationAndMaintenance
TOTAL Operation and Maint. (Total of lines 52 thru 61)
58,705,777
43,337
58,662,440
63
SalariesAndWagesOtherUtilityDepartmentsAbstract
Other Utility Departments
64
SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance
Operation and Maintenance
65
SalariesAndWagesOperationsAndMaintenance
TOTAL All Utility Dept. (Total of lines 28, 62, and 64)
295,964,259
252,392
295,711,867
66
SalariesAndWagesUtilityPlantAbstract
Utility Plant
67
SalariesAndWagesUtilityPlantConstructionAbstract
Construction (By Utility Departments)
68
SalariesAndWagesUtilityPlantConstructionElectricPlant
Electric Plant
148,350,341
6,514,863
154,865,204
69
SalariesAndWagesUtilityPlantConstructionGasPlant
Gas Plant
34,646,385
1,881,276
36,527,661
70
SalariesAndWagesUtilityPlantConstructionOther
Other (provide details in footnote):
71
SalariesAndWagesUtilityPlantConstruction
TOTAL Construction (Total of lines 68 thru 70)
182,996,726
8,396,139
191,392,865
72
SalariesAndWagesPlantRemovalAbstract
Plant Removal (By Utility Departments)
73
SalariesAndWagesPlantRemovalElectricPlant
Electric Plant
74
SalariesAndWagesPlantRemovalGasPlant
Gas Plant
75
SalariesAndWagesPlantRemovalOther
Other (provide details in footnote):
76
SalariesAndWagesPlantRemoval
TOTAL Plant Removal (Total of lines 73 thru 75)
77
SalariesAndWagesOtherAccountsAbstract
Other Accounts (Specify, provide details in footnote):
78
SalariesAndWagesOtherAccountsDescription
Other work in progress (174)
10,873,919
5,730
10,879,649
79
SalariesAndWagesOtherAccountsDescription
Misc Income Deductions
233,637
233,637
80
SalariesAndWagesOtherAccountsDescription
81
SalariesAndWagesOtherAccountsDescription
82
SalariesAndWagesOtherAccountsDescription
83
SalariesAndWagesOtherAccountsDescription
84
SalariesAndWagesOtherAccountsDescription
85
SalariesAndWagesOtherAccountsDescription
86
SalariesAndWagesOtherAccountsDescription
87
SalariesAndWagesOtherAccountsDescription
88
SalariesAndWagesOtherAccountsDescription
89
SalariesAndWagesOtherAccountsDescription
90
SalariesAndWagesOtherAccountsDescription
91
SalariesAndWagesOtherAccountsDescription
92
SalariesAndWagesOtherAccountsDescription
93
SalariesAndWagesOtherAccountsDescription
94
SalariesAndWagesOtherAccountsDescription
95
SalariesAndWagesOtherAccounts
TOTAL Other Accounts
11,107,556
5,730
11,113,286
96
SalariesAndWagesGeneralExpense
TOTAL SALARIES AND WAGES
490,068,541
8,149,477
498,218,018


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
COMMON UTILITY PLANT AND EXPENSES
  1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
  2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used.
  3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation.
  4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other authorization.
Niagara Mohawk Power Corporation 2018 Q4 Acct. Beginning Ending No. Item Balance Additions Retirements Transfers Adjustments Balance 301 Organization $0 302 Franchises and Consents 0 303 Miscellaneous Intangible 0 0 0 0 0 0 Total Intangible Plant 0 0 0 0 0 $0 Other (specify) Total Other 0 0 0 0 0 0 389 Land and Land Rights 5,274,371 -35,538 0 0 0 5,238,833 390 Structures & Improvements 211,677,424 8,090,358 -1,107,779 0 -214,111 218,445,892 391 Office furniture & equipment 14,041,239 16,486 -2,861,603 0 0 11,196,122 392 Transportation Equipment 4,931,995 0 0 0 0 4,931,995 393 Stores Equipment 1,142,478 0 -140,647 0 0 1,001,831 394 Tools, Shop & Garage Equip. 4,245,913 0 -254,996 0 0 3,990,917 395 Laboratory Equip 0 0 0 0 0 396 Power Operated Equipment 0 0 0 0 0 0 397 Communication Equipment 29,272,643 24,807 -226,682 0 0 29,070,769 398 Misc Equipment 512,315 0 -4,237 0 508,078 399 Asset Retirement Cost 616,919 0 -567,445 0 1,013,490 1,062,964 Total General Plant $ 271,715,297 8,096,113 -5,163,389 0 799,379 275,447,400 Total Common Utility Plant $ 271,715,297 8,096,113 -5,163,389 0 799,379 275,447,400 RESERVE FOR DEPRECIATION OF COMMON UTILITY PLANT Balance January 1, 2018 91,110,247 Depreciation and Amortization Provisions for year charged to: Depreciation - Electric 6,995,052 Depreciation - Gas 1,432,721 __________ Total Amortization and Amortization Provisions 8,427,773 __________ Net Charges for Plant Retired: Book Cost of Plant Retired -5,163,388 Cost of Removal -996,602 Salvage (Credit) Net Charges for Plant Retired -6,159,989 __________ Other Debit or Credit items: Asset Retirement Obligation Adjustment 799,735 Net Increase in Retirement Work in Progress -78,079 ___________ Balance December 31, 2018 94,099,687 FERC pg201 ln22 colh ___________ Depreciation Expense Allocation Factors to Common Plant Assets 17% Gas Segment 83% Electric Segment


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
  1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.
Description of Item(s)
(a)
Balance at End of Quarter 1
(b)
Balance at End of Quarter 2
(c)
Balance at End of Quarter 3
(d)
Balance at End of Year
(e)
1 Energy
2 Net Purchases (Account 555)
150,823,543
79,213,768
134,979,182
112,681,202
2.1 Net Purchases (Account 555.1)
3 Net Sales (Account 447)
4 Transmission Rights
5 Ancillary Services
6,949,849
7,182,008
6,105,232
6,521,510
6 Other Items (list separately)
7
Installed Capacity
2,514,190
16,873,599
25,377,808
7,490,563
46 TOTAL
160,287,582
103,269,375
166,462,222
126,693,275


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
  1. On line 1 columns (b), (c), (d), and (e) report the amount of ancillary services purchased and sold during the year.
  2. On line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year.
  3. On line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year.
  4. On line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year.
  5. On lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period.
  6. On line 7 columns (b), (c), (d), and (e) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant
Line No.
Type of Ancillary Service
(a)
Number of Units
(b)
Unit of Measure
(c)
Dollar
(d)
Number of Units
(e)
Unit of Measure
(f)
Dollars
(g)
1
Scheduling, System Control and Dispatch
15,351,155
mwh
8,057,987
2
Reactive Supply and Voltage
mwh
5,679,927
3
Regulation and Frequency Response
mwh
2,193,493
4
Energy Imbalance
mwh
5
Operating Reserve - Spinning
mwh
8,891,098
6
Operating Reserve - Supplement
7
Other
mwh
113,467
8
Total (Lines 1 thru 7)
15,351,155
24,935,972


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
  1. Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system.
  2. Report on Column (b) by month the transmission system's peak load.
  3. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
  4. Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.
Month
(a)
Monthly Peak MW - Total
(b)
Day of Monthly Peak
(c)
Hour of Monthly Peak
(d)
Firm Network Service for Self
(e)
Firm Network Service for Others
(f)
Long-Term Firm Point-to-point Reservations
(g)
Other Long-Term Firm Service
(h)
Short-Term Firm Point-to-point Reservation
(i)
Other Service
(j)
NAME OF SYSTEM: 0
1
January
2
February
3
March
4
Total for Quarter 1
5
April
5,585
6
12
4,115
573
897
6
May
6,676
30
18
5,201
542
933
7
June
7,115
18
14
5,598
584
933
8
Total for Quarter 2
14,914
1,699
2,763
9
July
7,604
2
14
6,186
485
933
10
August
7,544
6
15
6,117
494
933
11
September
7,428
5
19
6,023
472
933
12
Total for Quarter 3
18,326
1,451
2,799
13
October
6,136
9
20
4,729
474
933
14
November
6,145
7
18
4,732
516
897
15
December
6,090
11
18
4,538
655
897
16
Total for Quarter 4
13,999
1,645
2,727
17
Total
47,239
4,795
8,289


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: MonthlyPeakLoadExcludingIsoAndRto

Q1 2018 reporting data is not available due to the restructure of the NYISO server. The

server restructure caused disruption in the automated data extraction process and Q1 2018

data could not be extracted. The error was resolved at the beginning of Q2 2018 and the

data became available.


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
Monthly ISO/RTO Transmission System Peak Load
  1. Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system.
  2. Report on Column (b) by month the transmission system's peak load.
  3. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
  4. Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f).
  5. Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.
Month
(a)
Monthly Peak MW - Total
(b)
Day of Monthly Peak
(c)
Hour of Monthly Peak
(d)
Import into ISO/RTO
(e)
Exports from ISO/RTO
(f)
Through and Out Service
(g)
Network Service Usage
(h)
Point-to-Point Service Usage
(i)
Total Usage
(j)
NAME OF SYSTEM: Enter System
1
January
2
February
3
March
4
Total for Quarter 1
5
April
6
May
7
June
8
Total for Quarter 2
9
July
10
August
11
September
12
Total for Quarter 3
13
October
14
November
15
December
16
Total for Quarter 4
17
Total Year to Date/Year


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

2019-04-17
Year/Period of Report

End of:
2018
/
Q4
ELECTRIC ENERGY ACCOUNT

Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.

Line No. Item
(a)
MegaWatt Hours
(b)
Line No. Item
(a)
MegaWatt Hours
(b)
1
SOURCES OF ENERGY
21
DISPOSITION OF ENERGY
2
Generation (Excluding Station Use):
22
Sales to Ultimate Consumers (Including Interdepartmental Sales)
(a)
14,267,670
3
Steam
23
Requirements Sales for Resale (See instruction 4, page 311.)
(b)
6,215
4
Nuclear
24
Non-Requirements Sales for Resale (See instruction 4, page 311.)
5
Hydro-Conventional
25
Energy Furnished Without Charge
6
Hydro-Pumped Storage
26
Energy Used by the Company (Electric Dept Only, Excluding Station Use)
17,328
7
Other
27
Total Energy Losses
526,223
8
Less Energy for Pumping
27.1
Total Energy Stored
9
Net Generation (Enter Total of lines 3 through 8)
28
TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES
14,817,436
10
Purchases (other than for Energy Storage)
(c)
14,817,660
10.1
Purchases for Energy Storage
11
Power Exchanges:
12
Received
13
Delivered
14
Net Exchanges (Line 12 minus line 13)
15
Transmission For Other (Wheeling)
16
Received
(d)
3,212,258
17
Delivered
(e)
3,212,258
18
Net Transmission for Other (Line 16 minus line 17)
19
Transmission By Others Losses
20
TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)
(f)
14,817,660


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

2019-04-17
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: MegawattHoursSoldSalesToUltimateConsumers
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 22, Column: b, Value: 0
(b) Concept: MegawattHoursSoldRequirementsSales
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 23, Column: b, Value: 0
(c) Concept: MegawattHoursPurchasedOtherThanStorage
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 10, Column: b, Value: 0
(d) Concept: ElectricPowerWheelingEnergyReceived
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 16, Column: b, Value: 0
(e) Concept: ElectricPowerWheelingEnergyDelivered
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 17, Column: b, Value: 0
(f) Concept: SourcesOfEnergy
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 20, Column: b, Value: 0

Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
MONTHLY PEAKS AND OUTPUT
  1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system.
  2. Report in column (b) by month the system’s output in Megawatt hours for each month.
  3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
  4. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system.
  5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.
MonthAxis
Month
(a)
EnergyActivity
Total Monthly Energy
(b)
NonRequiredSalesForResaleEnergy
Monthly Non-Requirement Sales for Resale & Associated Losses
(c)
MonthlyPeakLoad
Monthly Peak - Megawatts
(d)
DayOfMonthlyPeak
Monthly Peak - Day of Month
(e)
HourOfMonthlyPeak
Monthly Peak - Hour
(f)
NAME OF SYSTEM: 0
29
January
1,393,554
394
6,024
5
30
February
1,150,082
935
5,500
7
31
March
1,202,285
332
5,101
8
32
April
1,102,160
736
4,688
6
33
May
1,076,029
445
5,766
30
34
June
1,112,091
583
6,112
18
35
July
1,426,552
370
6,495
16
36
August
1,497,582
630
6,610
6
37
September
1,201,364
623
6,500
5
38
October
1,051,295
416
5,197
9
39
November
1,247,125
371
5,238
27
40
December
1,357,317
609
5,193
11
41
Total


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: HourOfMonthlyPeak
Original value: HE 18
(b) Concept: HourOfMonthlyPeak
Original value: HE 8
(c) Concept: HourOfMonthlyPeak
Original value: HE 19
(d) Concept: HourOfMonthlyPeak
Original value: HE 12
(e) Concept: HourOfMonthlyPeak
Original value: HE 18
(f) Concept: HourOfMonthlyPeak
Original value: HE 14
(g) Concept: HourOfMonthlyPeak
Original value: HE 15
(h) Concept: HourOfMonthlyPeak
Original value: HE 15
(i) Concept: HourOfMonthlyPeak
Original value: HE 19
(j) Concept: HourOfMonthlyPeak
Original value: HE 20
(k) Concept: HourOfMonthlyPeak
Original value: HE 18
(l) Concept: HourOfMonthlyPeak
Original value: HE 18

Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
Steam Electric Generating Plant Statistics

1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

Line No.
Item
(a)
Plant Name:
Plant Name:
1
PlantKind
Kind of Plant (Internal Comb, Gas Turb, Nuclear)
2
PlantConstructionType
Type of Constr (Conventional, Outdoor, Boiler, etc)
3
YearPlantOriginallyConstructed
Year Originally Constructed
4
YearLastUnitOfPlantInstalled
Year Last Unit was Installed
5
InstalledCapacityOfPlant
Total Installed Cap (Max Gen Name Plate Ratings-MW)
6
NetPeakDemandOnPlant
Net Peak Demand on Plant - MW (60 minutes)
7
PlantHoursConnectedToLoad
Plant Hours Connected to Load
8
NetContinuousPlantCapability
Net Continuous Plant Capability (Megawatts)
9
NetContinuousPlantCapabilityNotLimitedByCondenserWater
When Not Limited by Condenser Water
10
NetContinuousPlantCapabilityLimitedByCondenserWater
When Limited by Condenser Water
11
PlantAverageNumberOfEmployees
Average Number of Employees
12
NetGenerationExcludingPlantUse
Net Generation, Exclusive of Plant Use - KWh
13
CostOfLandAndLandRightsSteamProduction
Cost of Plant: Land and Land Rights
14
CostOfStructuresAndImprovementsSteamProduction
Structures and Improvements
15
CostOfEquipmentSteamProduction
Equipment Costs
16
AssetRetirementCostsSteamProduction
Asset Retirement Costs
17
CostOfPlant
Total cost (total 13 thru 20)
18
CostPerKilowattOfInstalledCapacity
Cost per KW of Installed Capacity (line 17/5) Including
19
OperationSupervisionAndEngineeringExpense
Production Expenses: Oper, Supv, & Engr
20
FuelSteamPowerGeneration
Fuel
21
CoolantsAndWater
Coolants and Water (Nuclear Plants Only)
22
SteamExpensesSteamPowerGeneration
Steam Expenses
23
SteamFromOtherSources
Steam From Other Sources
24
SteamTransferredCredit
Steam Transferred (Cr)
25
ElectricExpensesSteamPowerGeneration
Electric Expenses
26
MiscellaneousSteamPowerExpenses
Misc Steam (or Nuclear) Power Expenses
27
RentsSteamPowerGeneration
Rents
28
Allowances
Allowances
29
MaintenanceSupervisionAndEngineeringSteamPowerGeneration
Maintenance Supervision and Engineering
30
MaintenanceOfStructuresSteamPowerGeneration
Maintenance of Structures
31
MaintenanceOfBoilerPlantSteamPowerGeneration
Maintenance of Boiler (or reactor) Plant
32
MaintenanceOfElectricPlantSteamPowerGeneration
Maintenance of Electric Plant
33
MaintenanceOfMiscellaneousSteamPlant
Maintenance of Misc Steam (or Nuclear) Plant
34
PowerProductionExpensesSteamPower
Total Production Expenses
35
ExpensesPerNetKilowattHour
Expenses per Net KWh
35
FuelKindAxis
Plant Name
36
FuelKind
Fuel Kind
37
FuelUnit
Fuel Unit
38
QuantityOfFuelBurned
Quantity (Units) of Fuel Burned
39
FuelBurnedAverageHeatContent
Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
40
AverageCostOfFuelPerUnitAsDelivered
Avg Cost of Fuel/unit, as Delvd f.o.b. during year
41
AverageCostOfFuelPerUnitBurned
Average Cost of Fuel per Unit Burned
42
AverageCostOfFuelBurnedPerMillionBritishThermalUnit
Average Cost of Fuel Burned per Million BTU
43
AverageCostOfFuelBurnedPerKilowattHourNetGeneration
Average Cost of Fuel Burned per KWh Net Gen
44
AverageBritishThermalUnitPerKilowattHourNetGeneration
Average BTU per KWh Net Generation


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
Hydroelectric Generating Plant Statistics
  1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
  2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number.
  3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
  4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.
  5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
  6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Line No.
Item
(a)
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
1
PlantKind
Kind of Plant (Run-of-River or Storage)
2
PlantConstructionType
Plant Construction type (Conventional or Outdoor)
3
YearPlantOriginallyConstructed
Year Originally Constructed
4
YearLastUnitOfPlantInstalled
Year Last Unit was Installed
5
InstalledCapacityOfPlant
Total installed cap (Gen name plate Rating in MW)
6
NetPeakDemandOnPlant
Net Peak Demand on Plant-Megawatts (60 minutes)
7
PlantHoursConnectedToLoad
Plant Hours Connect to Load
8
NetPlantCapabilityAbstract
Net Plant Capability (in megawatts)
9
NetPlantCapabilityUnderMostFavorableOperatingConditions
(a) Under Most Favorable Oper Conditions
10
NetPlantCapabilityUnderMostAdverseOperatingConditions
(b) Under the Most Adverse Oper Conditions
11
PlantAverageNumberOfEmployees
Average Number of Employees
12
NetGenerationExcludingPlantUse
Net Generation, Exclusive of Plant Use - Kwh
13
CostOfPlantAbstract
Cost of Plant
14
CostOfLandAndLandRightsHydroelectricProduction
Land and Land Rights
15
CostOfStructuresAndImprovementsHydroelectricProduction
Structures and Improvements
16
CostOfReservoirsDamsAndWaterwaysHydroelectricProduction
Reservoirs, Dams, and Waterways
17
EquipmentCostsHydroelectricProduction
Equipment Costs
18
CostOfRoadsRailroadsAndBridgesHydroelectricProduction
Roads, Railroads, and Bridges
19
AssetRetirementCostsHydroelectricProduction
Asset Retirement Costs
20
CostOfPlant
Total cost (total 13 thru 20)
21
CostPerKilowattOfInstalledCapacity
Cost per KW of Installed Capacity (line 20 / 5)
22
ProductionExpensesAbstract
Production Expenses
23
OperationSupervisionAndEngineeringExpense
Operation Supervision and Engineering
24
WaterForPower
Water for Power
25
HydraulicExpenses
Hydraulic Expenses
26
ElectricExpensesHydraulicPowerGeneration
Electric Expenses
27
MiscellaneousHydraulicPowerGenerationExpenses
Misc Hydraulic Power Generation Expenses
28
RentsHydraulicPowerGeneration
Rents
29
MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration
Maintenance Supervision and Engineering
30
MaintenanceOfStructuresHydraulicPowerGeneration
Maintenance of Structures
31
MaintenanceOfReservoirsDamsAndWaterways
Maintenance of Reservoirs, Dams, and Waterways
32
MaintenanceOfElectricPlantHydraulicPowerGeneration
Maintenance of Electric Plant
33
MaintenanceOfMiscellaneousHydraulicPlant
Maintenance of Misc Hydraulic Plant
34
PowerProductionExpensesHydraulicPower
Total Production Expenses (total 23 thru 33)
35
ExpensesPerNetKilowattHour
Expenses per net KWh


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
Pumped Storage Generating Plant Statistics
  1. Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings).
  2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number.
  3. If net peak demand for 60 minutes is not available, give the which is available, specifying period.
  4. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to each plant.
  5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
  6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes.
  7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.
Item
(a)
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
1
PlantConstructionType
Type of Plant Construction (Conventional or Outdoor)
2
YearPlantOriginallyConstructed
Year Originally Constructed
3
YearLastUnitOfPlantInstalled
Year Last Unit was Installed
4
InstalledCapacityOfPlant
Total installed cap (Gen name plate Rating in MW)
5
NetPeakDemandOnPlant
Net Peak Demaind on Plant-Megawatts (60 minutes)
6
PlantHoursConnectedToLoad
Plant Hours Connect to Load While Generating
7
NetContinuousPlantCapability
Net Plant Capability (in megawatts)
8
PlantAverageNumberOfEmployees
Average Number of Employees
9
NetGenerationExcludingPlantUse
Generation, Exclusive of Plant Use - Kwh
10
EnergyUsedForPumping
Energy Used for Pumping
11
NetOutputForLoad
Net Output for Load (line 9 - line 10) - Kwh
12
CostOfPlantAbstract
Cost of Plant
13
CostOfLandAndLandRightsPumpedStoragePlant
Land and Land Rights
14
CostOfStructuresAndImprovementsPumpedStoragePlant
Structures and Improvements
15
CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant
Reservoirs, Dams, and Waterways
16
CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant
Water Wheels, Turbines, and Generators
17
CostOfAccessoryElectricEquipmentPumpedStoragePlant
Accessory Electric Equipment
18
CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant
Miscellaneous Powerplant Equipment
19
CostOfRoadsRailroadsAndBridgesPumpedStoragePlant
Roads, Railroads, and Bridges
20
AssetRetirementCostsPumpedStoragePlant
Asset Retirement Costs
21
CostOfPlant
Total cost (total 13 thru 20)
22
CostPerKilowattOfInstalledCapacity
Cost per KW of installed cap (line 21 / 4)
23
ProductionExpensesAbstract
Production Expenses
24
OperationSupervisionAndEngineeringExpense
Operation Supervision and Engineering
25
WaterForPower
Water for Power
26
PumpedStorageExpenses
Pumped Storage Expenses
27
ElectricExpensesPumpedStoragePlant
Electric Expenses
28
MiscellaneousPumpedStoragePowerGenerationExpenses
Misc Pumped Storage Power generation Expenses
29
RentsPumpedStoragePlant
Rents
30
MaintenanceSupervisionAndEngineeringPumpedStoragePlant
Maintenance Supervision and Engineering
31
MaintenanceOfStructuresPumpedStoragePlant
Maintenance of Structures
32
MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant
Maintenance of Reservoirs, Dams, and Waterways
33
MaintenanceOfElectricPlantPumpedStoragePlant
Maintenance of Electric Plant
34
MaintenanceOfMiscellaneousPumpedStoragePlant
Maintenance of Misc Pumped Storage Plant
35
PowerProductionExpenseBeforePumpingExpenses
Production Exp Before Pumping Exp (24 thru 34)
36
PumpingExpenses
Pumping Expenses
37
PowerProductionExpensesPumpedStoragePlant
Total Production Exp (total 35 and 36)
38
ExpensesPerNetKilowattHour
Expenses per KWh (line 37 / 9)
39
ExpensesPerNetKilowattHourGenerationAndPumping
Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
GENERATING PLANT STATISTICS (Small Plants)

1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote.

3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.

Production Expenses
Line No.
PlantName
Name of Plant
(a)
YearPlantOriginallyConstructed
Year Orig. Const.
(b)
InstalledCapacityOfPlant
Installed Capacity Name Plate Rating (MW)
(c)
Net Peak Demand MW (60 min)
(d)
NetGenerationExcludingPlantUse
Net Generation Excluding Plant Use
(e)
Cost of Plant
(f)
PlantCostPerMw
Plant Cost (Incl Asset Retire. Costs) Per MW
(g)
OperatingExpensesExcludingFuel
Operation Exc'l. Fuel
(h)
Fuel Production Expenses
(i)
MaintenanceProductionExpenses
Maintenance Production Expenses
(j)
FuelKind
Kind of Fuel
(k)
FuelCostPerMmbtus
Fuel Costs (in cents (per Million Btu)
(l)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
ENERGY STORAGE OPERATIONS (Large Plants)
  1. Large Plants are plants of 10,000 KW or more.
  2. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location.
  3. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage.
  4. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should include MWHs delivered/provided to a generator’s own load requirements or used for the provision of ancillary services.
  5. In columns (h), (i), and (j) report MWHs lost during conversion, storage and discharge of energy.
  6. In column (k) report the MWHs sold.
  7. In column (l), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity.
  8. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (n) and (o), report fuel costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power.
  9. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.
Line No.
Name of the Energy Storage Project
(a)
Functional Classification
(b)
Location of the Project
(c)
MWHs
(d)
MWHs delivered to the grid to support Production
(e)
MWHs delivered to the grid to support Transmission
(f)
MWHs delivered to the grid to support Transmission
(g)
MWHs Lost During Conversion, Storage and Discharge of Energy Production
(h)
MWHs Lost During Conversion, Storage and Discharge of Energy Transmission
(i)
MWHs Lost During Conversion, Storage and Discharge of Energy Distribution
(j)
MWHs Sold
(k)
Revenues from Energy Storage Operations
(l)
Power Purchased for Storage Operations (555.1) (Dollars)
(m)
Fuel Costs from associated fuel accounts for Storage Operations Associated with Self- Generated Power (Dollars)
(n)
Other Costs Associated with Self-Generated Power (Dollars)
(o)
Project Costs included in
(p)
Production (Dollars)
(q)
Transmission (Dollars)
(r)
Distribution (Dollars)
(s)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35 TOTAL


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
TRANSMISSION LINE STATISTICS
  1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
  2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page.
  3. Report data by individual lines for all voltages if so required by a State commission.
  4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
  5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line.
  6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated.
  7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g).
  8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company.
  9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company.
  10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
DESIGNATION VOLTAGE (KV) - (Indicate where other than 60 cycle, 3 phase) LENGTH (Pole miles) - (In the case of underground lines report circuit miles) COST OF LINE (Include in column (j) Land, Land rights, and clearing right-of-way) EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line No.
TransmissionLineStartPoint
From
TransmissionLineEndPoint
To
OperatingVoltageOfTransmissionLine
Operating
DesignedVoltageOfTransmissionLine
Designated
SupportingStructureOfTransmissionLineType
Type of Supporting Structure
LengthForStandAloneTransmissionLines
On Structure of Line Designated
LengthForTransmissionLinesAggregatedWithOtherStructures
On Structures of Another Line
NumberOfTransmissionCircuits
Number of Circuits
SizeOfConductorAndMaterial
Size of Conductor and Material
CostOfLandAndLandRightsTransmissionLines
Land
ConstructionAndOtherCostsTransmissionLines
Construction Costs
OverallCostOfTransmissionLine
Total Costs
OperatingExpensesOfTransmissionLine
Operation Expenses
MaintenanceExpensesOfTransmissionLine
Maintenance Expenses
RentExpensesOfTransmissionLine
Rents
OverallExpensesOfTransmissionLine
Total Expenses
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)
(m)
(n)
(o)
(p)
1
Clay
Dewitt
345
15.08
1
216.7 KIWI ACSR
900,555
5,049,249
5,949,805
2
Dewitt
Lafayette
345
8.31
1
2 - 1192.5 BUNTIN
541,168
5,074,079
5,615,247
3
Nine Mile Point 1
Clay
345
27.56
1
216.7 KIWI ACSR
1,220,182
5,292,053
6,512,235
4
Nine Mile Point 1
Scriba
345
0.4
1
216.7 KIWI ACSR
442,025
442,025
5
Oswego
Lafayette
345
48.55
1
2 - 1192.5 BUNTIN
5,625,110
20,896,361
26,521,471
6
Oswego
Volney
345
13.41
1
2 - 1192.5 BUNTIN
1,743,552
3,815,061
5,558,612
7
Oswego
Volney
345
13.41
1
2 - 1192.5 BUNTIN
4,197,269
4,197,269
8
Scriba
Volney
345
8.82
1
216.7 KIWI ACSR
208,643
3,891,599
4,100,243
9
Scriba
Volney
345
8.87
1
2 - 1192.5 BUNTIN
10
Volney
Clay
345
18.47
1
216.7 KIWI ACSR
887,691
887,691
11
Independence
Scriba
345
2.79
1
2 - 795 DRAKE ACS
27,103,218
27,103,218
12
Edic
New Scotland
345
83.62
1
2 - 795 DRAKE ACS
2,627,756
37,619,494
40,247,250
13
Marcy
New Scotland
345
83.91
1
2 - 1192.5 BUNTIN
2,322,341
29,633,497
31,955,837
14
2 - 1351.5 DIPPER
15
4 - 1351.5 DIPPER
16
Volney
Marcy
345
65.56
1
2 - 1192.5 BUNTIN
2,640,639
84,286
2,724,925
17
2 - 1431 BOBOLINK
18
4 - 1351.5 DIPPER
19
Alps
Berkshire
345
8.88
1
2 - 1192.5 BUNTIN
20
Leeds
Hurley
345
0.18
1
2 - 1033.5 ORTOLA
59,438
59,438
21
Athens
Pleasant Valley
345
39.17
1
2 - 795 DRAKE ACS
435,469
435,469
22
2 - 795 MALLARD A
23
Leeds
Pleasant Valley
345
38.76
1
2 - 795 MALLARD A
24
2 - 795 DRAKE ACS
25
New Scotland
Alps
345
30.65
1
2 - 1192.5 BUNTIN
2,587,038
19,671,534
22,258,572
26
3 - 1590 LAPWING
27
New Scotland
Leeds
345
25.73
1
2 - 795 DRAKE ACS
2,018,970
12,948,389
14,967,359
28
New Scotland
Leeds
345
25.86
1
2 - 795 DRAKE ACS
29
Reynolds Road
Alps
345
11.09
1
2 - 1192.5 BUNTIN
608,370
4,720,459
5,328,829
30
Independence
Clay
345
29.14
1
2 - 1192.5 BUNTIN
31
Leeds
Athens
345
0.49
1
2 - 795 DRAKE ACS
153,716
38,568,281
38,721,997
32
Reynolds Road
Empire
345
8.12
1
Unknown
33
Lafayette
Clarks Ciorner
345
38.59
1
2 - 1192.5 BUNTIN
34
Stolle Road
Five Mile Road
345
25.17
1
2 - 1192.5 BUNTIN
46,413
46,413
35
Pierce Brook (FE)
Five Mile Road
345
12.34
1
2 - 1192.5 BUNTIN
36
Beck
Packard
230
4.1
1
1158.4 ACSR
26,140
516,760
542,900
37
1192.5 BUNTING AC
38
Dunkirk
South Ripley
230
31.41
1
1192.5 BUNTING AC
586,893
3,325,951
3,912,844
39
1192.5 GRACKLE AC
40
South Ripley
Erie
230
0.15
1
1192.5 BUNTING AC
194,637
194,637
41
Gardenville
Dunkirk
230
47.39
1
1192.5 BUNTING AC
3,618,873
8,726,511
12,345,384
42
1192.5 GRACKLE AC
43
Gardenville
Dunkirk
230
47.16
1
1192.5 BUNTING AC
44
1192.5 GRACKLE AC
45
Huntley
Gardenville
230
20.19
1
1192.5 GRACKLE AC
1,053,702
9,035,107
10,088,809
46
795 COOT ACSR
47
Huntley
Gardenville
230
20.3
1
1192.5 GRACKLE AC
48
795 COOT ACSR
49
Niagara
Packard
230
3.37
1
1431 ACSR
68,648
574,375
643,023
50
Niagara
Packard
230
3.42
1
1431 ACSR
347,181
347,181
51
Packard
Huntley
230
12.31
1
1158.4 ACSR
1,239,863
5,145,759
6,385,622
52
1192.5 GRACKLE AC
53
795 COOT ACSR
54
Packard
Huntley
230
12.08
1
1158.4 1158.4 ACS
55
795 COOT ACSR
56
1192.5 GRACKLE AC
57
Adirondack
Porter
230
54.33
1
1431 BOBOLINK ACS
4,013,534
4,013,534
58
795 COOT ACSR
59
Edic
Porter
230
0.42
1
2 - 795 COOT ACSR
385,250
385,250
60
216.7 KIWI ACSR
61
Porter
Rotterdam
230
71.71
1
1431 BOBOLINK ACS
788,373
6,420,719
7,209,093
62
795 COOT ACSR
63
795 DRAKE ACSR
64
Porter
Rotterdam
230
72.09
1
1431 BOBOLINK ACS
178,309
13,730,293
13,908,602
65
795 DRAKE ACSR
66
795 COOT ACSR
67
Adirondack
Chases Lake
230
11.05
1
795 COOT ACSR
68
Chases Lake
Porter
230
43.41
1
1431 BOBOLINK ACS
69
795 COOT ACSR
70
Rotterdam
Eastover
230
23.52
1
1033.5 ORTOLAN AC
1,145,797
14,631,070
15,776,867
71
1113 FINCH ACSR
72
Eastover
Bear Swamp
230
20.42
1
1033.5 ORTOLAN AC
73
1113 FINCH ACSR
74
795 COOT ACSR
75
Huntley
Elm
230
7.9
1
2500 AL
76
Elm
Seneca
230
3.16
1
750 Copper
77
Elm
Seneca
230
3.03
1
750 Copper
78
Seneca
Gardenville
230
3
1
1500 Copper
79
Seneca
Gardenville
230
3.1
1
1500 Copper
80
Elm Street Bus Tie
230
0.04
1
2000 Copper
17,710
17,710
81
Conklin
Bailey (North)
230
0.3
1
2500 Copper
82
Conklin
Bailey (South)
230
0.3
1
2500 Copper
83
Various
115
4,519.74
298
Various
2,393,157
101,875,391
104,268,548
84
115
32.7
30
Various
28,085
28,085
36
5,765.03
383
34,297,795
389,404,198
423,701,994


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
TRANSMISSION LINES ADDED DURING YEAR
  1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines.
  2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
  3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.
LINE DESIGNATION SUPPORTING STRUCTURE CIRCUITS PER STRUCTURE CONDUCTORS LINE COST
Line No.
TransmissionLineStartPoint
From
TransmissionLineEndPoint
To
LengthOfTransmissionLineAdded
Line Length in Miles
SupportingStructureOfTransmissionLineType
Type
AverageNumberOfSupportingStructuresOfTransmissionLinePerMiles
Average Number per Miles
NumberOfTransmissionCircuitsPerStructurePresent
Present
NumberOfTransmissionCircuitsPerStructureUltimate
Ultimate
ConductorSize
Size
ConductorSpecification
Specification
ConductorConfigurationAndSpacing
Configuration and Spacing
OperatingVoltageOfTransmissionLine
Voltage KV (Operating)
CostOfLandAndLandRightsTransmissionLinesAdded
Land and Land Rights
CostOfPolesTowersAndFixturesTransmissionLinesAdded
Poles, Towers and Fixtures
CostOfConductorsAndDevicesTransmissionLinesAdded
Conductors and Devices
AssetRetirementCostsTransmissionLines
Asset Retire. Costs
CostOfTransmissionLinesAdded
Total
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)
(m)
(n)
(o)
(p)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
TOTAL


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
SUBSTATIONS
  1. Report below the information called for concerning substations of the respondent as of the end of the year.
  2. Substations which serve only one industrial or street railway customer should not be listed below.
  3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown.
  4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f).
  5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity.
  6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
VOLTAGE (In MVa)
Line No.
SubstationNameAndLocation
Name and Location of Substation
(a)
SubstationCharacterDescription
Character of Substation
(b)
PrimaryVoltageLevel
Primary Voltage (In MVa)
(c)
SecondaryVoltageLevel
Secondary Voltage (In MVa)
(d)
TertiaryVoltageLevel
Tertiary Voltage (In MVa)
(e)
SubstationInServiceCapacity
Capacity of Substation (In Service) (In MVa)
(f)
NumberOfTransformersInService
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
ConversionApparatusAndSpecialEquipmentType
Conversion Apparatus and Special Equipment, Type of Equipment
(i)
NumberOfConversionApparatusAndSpecialEquipmentUnits
Conversion Apparatus and Special Equipment, Number of Units
(j)
CapacityOfConversionApparatusAndSpecialEquipment
Conversion Apparatus and Special Equipment, Total Capacity (In MVa)
(k)
1
Akwesasne Station 825
Trans-Unattended
115
5.04
10
1
2
Akwesasne Station 825
Trans-Unattended
115
34.5
20
1
3
Albany High School Station 403
Dist-Unattended
34.4
13.8
4
1
4
Albion Station 80
Dist-Unattended
34.4
4.8
4
1
5
Albion Station 80
Dist-Unattended
34.5
4.8
4
1
6
Alder Creek Station 701
Dist-Unattended
43.8
5
2
3
7
Alder Creek Station 701
Dist-Unattended
43.8
13.8
4
1
8
Altamont Station 283
Dist-Unattended
115
13.8
12
1
9
Andover Station 09
Trans-Unattended
34.5
4.8
1
1
10
Andover Station 09
Trans-Unattended
110
34.5
20
1
11
Antwerp Station 801
Dist-Unattended
23
4.8
4
1
12
Arnold Pit 4746
Dist-Unattended
23
0.48
3
13
Arnold Station 656
Dist-Unattended
43.8
4.4
5
1
14
Arnold Station 656
Dist-Unattended
43.8
13.8
5
1
15
Ash Street Station 223
Trans-Unattended
34.4
4.4
15
2
16
Ash Street Station 223
Trans-Unattended
34.5
4.4
8
1
17
Ash Street Station 223
Trans-Unattended
110
34.5
30
1
18
Ash Street Station 223
Trans-Unattended
115
12.5
24
1
19
Ash Street Station 223
Trans-Unattended
115
12.5
12.5
24
1
20
Ash Street Station 223
Trans-Unattended
115
13.8
40
2
21
Ash Street Station 223
Trans-Unattended
115
34.5
30
1
22
Ashley Station 331 (Port PDS 7 East)
Dist-Unattended
34.5
13.2
8
1
23
Attica Station 12
Dist-Unattended
34.5
4.8
8
1
24
Ausable Forks Station 846
Dist-Unattended
46
5
3
1
25
Avenue A Station 291
Dist-Unattended
34.4
4.4
10
2
26
Avon Station 43
Dist-Unattended
34.5
4.8
4
1
27
Baker Street Station 150
Dist-Unattended
115
13.2
15
1
28
Ballina Station 221
Dist-Unattended
34.5
13.2
7.97
6
1
29
Ballston Station 12
Trans-Unattended
34.4
4.16
1
30
Ballston Station 12
Trans-Unattended
110
34.4
13.8
30
1
31
Ballston Station 12
Trans-Unattended
113
13.8
16
1
32
Balmat Station 904
Trans-Unattended
23
4.8
2
1
33
Balmat Station 904
Trans-Unattended
115
23
8
1
34
Barker Station 78
Dist-Unattended
34.5
4.8
4
1
35
Bartell Road Station 325
Dist-Unattended
115
13.8
15
1
36
Basom Station 15
Dist-Unattended
34.5
4.8
3
2
37
Batavia Station 01
Trans-Unattended
115
13.2
20
1
38
Batavia Station 01
Trans-Unattended
115
13.8
24
1
39
Batavia Station 01
Trans-Unattended
115
34.5
30
2
40
Battenkill Station 342
Trans-Unattended
110
34.4
13.8
30
1
41
Battenkill Station 342
Trans-Unattended
115
13.2
12
1
42
Belmont Station 260
Dist-Unattended
115
13.8
20
1
43
Belmont Station 260
Dist-Unattended
116
13.8
18
1
44
Bemus Point Station 159
Dist-Unattended
34.4
5
4
1
45
Bennett Road Station 99
Dist-Unattended
115
13.8
25
2
46
Berry Road Station 153
Dist-Unattended
115
13.8
15
1
47
Bethlehem Station 21
Trans-Unattended
115
13.8
15
1
48
Bethlehem Station 21
Trans-Unattended
115
34.4
5
30
1
49
Bethlehem Station 21
Trans-Unattended
115
34.4
13.8
30
1
50
Birch Avenue Station 322
Dist-Unattended
34.4
13.8
10
1
51
Black River Station 70
Trans-Unattended
115
23
15
1
52
Bloomingdale Station 841
Dist-Unattended
46
4.8
3
1
53
Blue Stores Station 303
Dist-Unattended
113
13.8
12
1
54
Bolton Station 284
Dist-Unattended
34.4
13.8
10
1
55
Bombay Station 897
Dist-Unattended
34.4
5
3
1
56
Boonville Station 707
Trans-Unattended
115
23
8
1
57
Boonville Station 707
Trans-Unattended
115
46
20
1
58
Boonville Station 707
Trans-Unattended
115
48
20
4
59
Boyntonville Station 333
Dist-Unattended
110
13.8
8
1
60
Brady Station 957
Dist-Unattended
115
13.8
15
1
61
Brasher Station 851
Dist-Unattended
34.4
5
6
3
62
Bremen Station 815
Dist-Unattended
115
13.8
5
1
63
Brewerton Station 7
Dist-Unattended
34.4
5
4
1
64
Bridge Street Station 295
Dist-Unattended
115
13.8
18
1
65
Bridgeport Station 168
Dist-Unattended
113
13.8
13
1
66
Brier Hill Station 953
Dist-Unattended
22
5
1
1
67
Brigham Road Station 64
Dist-Unattended
69
13.8
10
1
68
Bristol Hill Station 109
Trans-Unattended
115
34.5
20
1
69
Brockport Station 74
Trans-Unattended
115
13.8
28
2
70
Brockport Station 74
Trans-Unattended
115
34.5
30
2
71
Brook Road Station 369
Dist-Unattended
115
13.8
40
2
72
Brook Road Station 369
Dist-Unattended
115
34.5
30
1
73
Browns Falls Station 711
Trans-Unattended
115
34.5
15
4
74
Brunswick Station 264
Dist-Unattended
34.4
13.8
8
1
75
Buckley Corners Station 454
Dist-Unattended
113
13.8
8
1
76
Burdeck Street Station 265
Dist-Unattended
113
13.8
12
1
77
Burgoyne Avenue Station 337
Dist-Unattended
115
13.8
15
1
78
Busti Station 68
Dist-Unattended
34.4
5
2
1
79
Butler Station 362
Dist-Unattended
113
13.8
12
1
80
Butternut Station 255
Dist-Unattended
113
13.8
12
1
81
Butts Road Station 72
Dist-Unattended
34.4
13.8
5
1
82
Butts Road Station 72
Dist-Unattended
34.5
13.2
4
1
83
Byron Station 18
Dist-Unattended
34.5
4.8
3
2
84
Camillus Station 10
Dist-Unattended
34.5
4.4
4
3
85
Canawagus Station
Dist-Unattended
34.5
0.48
2
1
86
Cardiff Station 13
Dist-Unattended
34.5
2.4
2
3
87
Caroga Lake Station 219
Dist-Unattended
22.9
5
3
1
88
Carthage Station 717
Dist-Unattended
23
4.8
6
3
1
89
Cascade Tissue Station
Dist-Unattended
34.5
4.16
3
1
90
Cassadaga Station 61
Dist-Unattended
34.5
4.8
4
1
91
Cattaraugus Station 15
Dist-Unattended
34.5
4.8
3
1
92
Cavanaugh Road Station 616
Dist-Unattended
115
13.8
15
1
93
Cazenovia Station 220
Dist-Unattended
34.5
4.8
4
3
94
Cedar Station 453
Dist-Unattended
115
13.2
25
1
95
Center Street Station 379
Dist-Unattended
115
13.2
15
1
96
Central Square Station 15
Dist-Unattended
34.4
5
3
1
97
Chadwicks Station 668
Dist-Unattended
115
13.8
13
1
98
Charley Lake Station 254
Dist-Unattended
23
2.4
1
99
Chasm Falls Station 852
Trans-Unattended
34.5
13.2
5
1
100
Chautauqua Station 57
Dist-Unattended
34.5
4.8
8
1
101
Chestertown Station 42
Dist-Unattended
34.5
13.2
8
1
102
Chittenango Station 16
Dist-Unattended
34.4
5
4
1
103
Chrisler Avenue Station 257
Dist-Unattended
34.5
4.16
6
2
104
Church Street Station 43
Dist-Unattended
115
13.8
24
1
105
Church Street Station 43
Dist-Unattended
116
13.8
18
1
106
Clay Station 229
Trans-Unattended
345
120
13.8
538
2
1
107
Cleveland Station 11
Dist-Unattended
34.5
4.6
2
3
108
Clinton Road Station 366
Dist-Unattended
113
13.8
13
1
109
Clinton Station 604
Dist-Unattended
43.8
13.8
8
1
110
Cloverbank Station 91
Dist-Unattended
115
13.2
20
2
111
Clymer Station 55
Dist-Unattended
34.5
4.8
4
1
112
Cobleskill Station 214
Dist-Unattended
69
4.8
7
4
113
Coffeen Street Station 760
Trans-Unattended
113
13.8
12
1
114
Coffeen Street Station 760
Trans-Unattended
115
13.8
15
1
115
Coffeen Street Station 760
Trans-Unattended
115
24
30
2
116
Collins Station 83
Dist-Unattended
34.4
5.04
5
1
117
Collinsville Station 716
Dist-Unattended
22.9
5
5
1
118
Colosse Station 321
Dist-Unattended
34.4
13.8
6
1
119
Colvin Avenue Station 313
Dist-Unattended
34.5
4.16
5
1
120
Commerce Avenue Station 235
Dist-Unattended
34.4
13.8
8
1
121
Comstock Station 48
Dist-Unattended
115
5
5
1
122
Conesus Lake Station 52
Dist-Unattended
34.4
5.04
4
1
123
Conkling Station 652
Dist-Unattended
43.8
4.4
5
1
124
Constantia Station 19
Dist-Unattended
34.5
4.16
3
1
125
Coolidge Ventures Station 268
Dist-Unattended
115
13.2
8
1
126
Corfu Station 22
Dist-Unattended
34.5
4.8
3
2
127
Corinth Station 285
Dist-Unattended
34.4
13.2
8
1
128
Corliss Park Station 338
Dist-Unattended
34.4
4.16
5
1
129
Corning Station 970
Dist-Unattended
115
13.8
15
1
130
Cortland Line Station 277
Dist-Unattended
34.5
4.4
4
1
131
Cortland Station 502
Dist-Unattended
34.4
5
2
1
132
Cortland Station 502
Dist-Unattended
34.5
5
3
2
133
Cortland Station 502
Dist-Unattended
110
34.5
30
1
134
Cortland Station 502
Dist-Unattended
113
34.5
30
1
135
Cross Street Pump
Dist-Unattended
34.5
4.16
5
1
136
Cross Street Pump
Dist-Unattended
34.5
5
10
2
137
Crouse Hinds Station 239
Dist-Unattended
34.4
13.2
1
2
138
Crown Point Station 249
Dist-Unattended
115
13.8
8
1
139
Cuba Lake Station 37
Dist-Unattended
34.5
4.8
3
1
140
Cuba Station 05
Dist-Unattended
34.4
5.04
4
1
141
Curry Road Station 365
Dist-Unattended
113
13.8
1
142
Curry Road Station 365
Dist-Unattended
115
13.2
20
1
143
Curry Road Station 365
Dist-Unattended
115
13.8
20
1
144
Curtis Street Station 224
Trans-Unattended
110
34.5
30
2
145
Darien Station 16
Dist-Unattended
34.5
4.8
4
1
146
David Station 979
Dist-Unattended
22.3
5
6
3
147
Debalso Station 684
Dist-Unattended
115
13.8
15
1
148
Deerfield Station 606
Trans-Unattended
115
13.8
12
1
149
Deerfield Station 606
Trans-Unattended
115
46
20
1
150
Dekalb Station 984
Dist-Unattended
115
13.8
8
1
151
Delameter Station 93
Dist-Unattended
115
13.8
15
1
152
Delanson Station 269
Dist-Unattended
67
13.8
8
1
153
Delaware Avenue Station 330
Dist-Unattended
34.4
4.4
5
1
154
Delaware Avenue Station 330
Dist-Unattended
34.4
13.8
10
1
155
Delevan Station 11
Dist-Unattended
34.5
4.8
3
2
156
Delmar Station 279
Dist-Unattended
34.4
5
13
2
157
Delphi Station 262
Dist-Unattended
113
13.8
8
1
158
Depot Road Station 425
Dist-Unattended
34.5
13.2
10
1
159
Dewitt Station 241
Trans-Unattended
345
120
13.8
514
2
160
Dexter Station 726
Dist-Unattended
23
4.8
2
3
161
Dorwin Station 26
Dist-Unattended
34.4
4.4
5
1
162
Dugan Road Station 22
Dist-Unattended
115
13.2
15
1
163
Dugan Road Station 22
Dist-Unattended
115
13.8
15
1
164
Duguid Station 265
Dist-Unattended
115
13.8
20
1
165
Dunkirk Station
Trans-Unattended
115
34.5
50
2
166
Dunkirk Station
Trans-Unattended
230
120
13.2
150
2
167
E. J. West Station 38
Trans-Unattended
115
13.8
6
1
168
Eagle Bay Station 382
Dist-Unattended
43.8
5
4
3
169
Eagle Harbor Station 92
Dist-Unattended
34.5
4.8
3
1
170
East Batavia Station 28
Dist-Unattended
115
13.8
40
2
171
East Dunkirk Station 63
Dist-Unattended
115
20
2
172
East Fulton Station 100
Dist-Unattended
34.4
2.5
4
1
173
East Golah Station 51
Dist-Unattended
66
34.5
1
174
East Golah Station 51
Dist-Unattended
115
13.8
35
2
175
East Molloy Road Station 151
Dist-Unattended
115
13.5
15
1
176
East Norfolk Station 913
Trans-Unattended
23
4.8
3
3
177
East Oswegatchie Station 982
Trans-Unattended
115
24
8
1
178
East Otto Station 28
Dist-Unattended
34.5
4.8
3
1
179
East Pulaski Station 324
Dist-Unattended
110
13.8
8
1
180
East Schodack Station 447
Dist-Unattended
34.5
4.8
4
1
181
East Springfield Station 477
Dist-Unattended
115
13.8
6
1
182
East Watertown Station 817
Dist-Unattended
113
13.8
12
1
183
East Worcester Station 060
Dist-Unattended
34.5
13.2
5
1
184
Eastover Road Station 2931
Trans-Unattended
230
115
13.8
200
1
185
Eastover Road Station 2931
Trans-Unattended
230
120
13.8
200
1
186
Eden Center Station 88
Dist-Unattended
34.4
4.5
4
1
187
Edic Station 662
Trans-Unattended
345
120
13.8
1386
4
188
Edic Station 662
Trans-Unattended
345
230
13.2
304
1
189
Edwards Station 916
Dist-Unattended
34.4
5
1
1
190
Elba Station 20
Dist-Unattended
34.5
4.8
3
2
191
Elbridge Station 312
Trans-Unattended
115
34.5
20
1
192
Elbridge Station 312
Trans-Unattended
345
120
13.8
448
1
193
Ellicott Station 65
Dist-Unattended
34.4
5
3
1
194
Elm Street Station
Trans-Unattended
240
24
225
4
195
Elm Street Station 898
Dist-Unattended
34.4
5
5
3
196
Elnora Station 344
Dist-Unattended
115
13.8
15
1
197
Elsmere Station 407
Dist-Unattended
34.4
4.8
8
1
198
Emerald Equipment Systems Station 234
Dist-Unattended
34.5
13.2
5
1
199
Emmet Street Station 256
Dist-Unattended
34.4
4.2
3
1
200
Emmet Street Station 256
Dist-Unattended
34.5
4.16
3
1
201
Ephratah Station 18
Trans-Unattended
69
4.8
5
3
202
Ephratah Station 18
Trans-Unattended
69
23
13.2
5
1
203
Euclid Station 267
Dist-Unattended
115
13.8
40
2
204
Everett Road Station 420
Dist-Unattended
115
13.8
15
1
205
Fabius Station 55
Dist-Unattended
34.4
5
2
3
206
Fairdale Station 135
Dist-Unattended
34.4
5
3
1
207
Farmersville Station 27
Dist-Unattended
34.5
4.8
2
3
208
Farnan Road Station 476
Dist-Unattended
34.5
13.8
1
1
209
Fayette Street Station 28
Dist-Unattended
34.4
4.4
24
2
210
Fine Station 978
Dist-Unattended
34.5
5
1
1
211
Finley Lake Station 71
Dist-Unattended
34.4
5
3
1
212
Firehouse Road Station 449
Dist-Unattended
115
13.8
15
1
213
Fisher Avenue Station 270
Dist-Unattended
34.5
13.8
4.16
12
1
214
Five Mile Road 1325
Trans-Unattended
345
120
13.8
269
1
215
Florida Station 501
Dist-Unattended
69
13.8
15
1
216
Fly Road Station 261
Dist-Unattended
115
13.8
7.97
20
1
217
Fort Covington Station 896
Trans-Unattended
34.4
13.8
5
1
218
Fort Gage Station 319
Dist-Unattended
34.4
13.8
5
1
219
Forts Ferry Station 459
Dist-Unattended
115
13.2
15
1
220
Frankfort Station 677
Dist-Unattended
43.8
4.16
4
1
221
Frankhauser Substation 995
Dist-Unattended
115
13.8
48
2
222
Franklin Falls Station 843
Trans-Unattended
46
4.8
1
2
223
Franklinville Station 24
Dist-Unattended
34.4
5.04
4
1
224
French Creek Station 56
Dist-Unattended
34.4
13.8
1.6
5
1
225
French Mountain Station 1054
Dist-Unattended
34.4
13.8
5
1
226
Frewsburg Station 69
Dist-Unattended
34.5
4.8
5
1
227
Front Street Station 360
Dist-Unattended
113
13.8
24
1
228
Front Street Station 360
Dist-Unattended
115
13.8
24
1
229
Fuller Realty Station
Dist-Unattended
19.05
4.16
3
3
230
Gabriels Station 835
Dist-Unattended
46
4.8
1
1
231
Galeville Station 213
Dist-Unattended
34.4
4.36
5
1
232
Gardenville (New) 230 Station
Trans-Unattended
230
120
13.2
250
2
233
Gardenville (New) 230 Station
Trans-Unattended
230
120
13.8
200
1
234
Gasport Station 90
Dist-Unattended
34.5
5.04
4
1
235
Genesee Street Station 260
Dist-Unattended
34.4
4.4
5
1
1
236
Geneseo Station 55
Dist-Unattended
34.5
13.2
4
1
237
Gibson Station 106
Trans-Unattended
13.2
12
3
238
Gibson Station 106
Trans-Unattended
115
12
50
2
239
Gilbert Mills Station 247
Dist-Unattended
110
13.8
8
1
240
Gilmantown Road Station 154
Dist-Unattended
23
13.2
5
1
241
Gilpin Bay Station 956
Dist-Unattended
46
4.8
5
1
242
Glens Falls Hospital Station 414
Dist-Unattended
34.4
4.4
3
1
243
Glens Falls Hospital Station 414
Dist-Unattended
34.5
4.8
4
1
244
Glens Falls Station 75
Trans-Unattended
34.5
4.16
5
1
245
Glenwood Station 227
Dist-Unattended
34.4
4.4
5
1
246
Gloversville Station 72
Dist-Unattended
69
4.16
13.2
8
1
247
Gloversville Station 72
Dist-Unattended
69
13.8
15
1
248
Golah Station
Trans-Unattended
69
34.5
15
2
249
Golah Station
Trans-Unattended
115
34.5
25
1
250
Granby Center Station 293
Dist-Unattended
34.4
13.8
5
1
251
Grand Street Station 433
Dist-Unattended
69
13.2
5
1
252
Greenbush Station 78
Trans-Unattended
113
13.8
18
1
253
Greenbush Station 78
Trans-Unattended
115
13.2
20
1
254
Greenbush Station 78
Trans-Unattended
115
34.5
5
30
1
255
Greenbush Station 78
Trans-Unattended
115
34.5
13.8
30
1
256
Greenhurst Station 60
Dist-Unattended
34.5
4.8
3
1
257
Grooms Road Station 345
Dist-Unattended
115
13.8
48
2
258
Groveland Station 41
Dist-Unattended
34.5
4.8
1
1
259
Guilford Mills
Dist-Unattended
46
4.16
4
1
260
Hague Road Station 418
Dist-Unattended
115
13.8
13
1
261
Hammond Station 370
Dist-Unattended
22.9
4.8
4
1
262
Hancock Station 137
Dist-Unattended
34,500
2.4
3
3
263
Hanson 1 - General Crush - TS 4504
Dist-Unattended
34.5
0.48
2
3
264
Hanson Aggregate - Middleville
Dist-Unattended
46
4.8
2
3
265
Hanson Station 738
Dist-Unattended
23
2.4
3
3
266
Harper Station
Trans-Unattended
12
4.8
2
6
267
Harper Station
Trans-Unattended
115
12
64
2
268
Harris Road Station 235
Trans-Unattended
110
34.5
20
1
269
Harris Road Station 235
Trans-Unattended
115
13.8
44
2
270
Hartfield Station 79
Trans-Unattended
113
13.8
8
1
271
Hartfield Station 79
Trans-Unattended
115
34.5
15
1
272
Headson Station 146
Trans-Unattended
116
34.5
60
2
273
Hedley Park Place Station
Dist-Unattended
34.5
4.16
2
3
274
Hemlock Station 38
Dist-Unattended
34.5
13.2
4
1
275
Hemstreet Station 328
Dist-Unattended
115
13.8
10
1
276
Henry Street Station 316
Dist-Unattended
34.4
4.2
5
1
277
Henry Street Station 316
Dist-Unattended
34.4
4.4
5
1
278
Higley Station 473
Trans-Unattended
110
13.8
5
1
279
Hill Street Station 311
Dist-Unattended
69
4.2
10
1
280
Hinsdale Station 218
Dist-Unattended
34.5
4.4
5
1
281
Hoag Station 221
Dist-Unattended
34.5
7.62
5
1
282
Homer Hill Switch Structure
Trans-Unattended
115
34.5
15
2
283
Homer Station 129
Dist-Unattended
34.5
4.8
8
3
284
Hoosick Station 314
Trans-Unattended
113
13.8
8
1
285
Hoosick Station 314
Trans-Unattended
115
34.5
13.8
20
3
286
Hopkins Road Station 253
Dist-Unattended
115
13.8
38
2
287
Hudson Falls Station 88
Dist-Unattended
34.5
13.8
5
1
288
Hudson Station 87
Trans-Unattended
115
13.8
7.97
40
2
289
Hudson Station 87
Trans-Unattended
115
34.5
5
30
1
290
Huntley Station
Trans-Unattended
115
23.8
38
1
291
Indian Lake Station 310
Dist-Unattended
19.92
4.8
3
3
1
292
Indian River Station 323
Dist-Unattended
115
13.2
15
1
293
Indian River Station 323
Dist-Unattended
115
23
15
1
294
Industry Station 47
Dist-Unattended
34.5
4.8
1
1
295
Inghams Station 20
Trans-Unattended
113
13.8
8
1
296
Inghams Station 20
Trans-Unattended
115
46
20
1
297
Inghams Station 20
Trans-Unattended
115
115
156
1
298
Inman Road Station 370
Dist-Unattended
113
13.8
18
1
299
Inman Road Station 370
Dist-Unattended
115
13.8
20
1
300
Iroquois Rock Station
Dist-Unattended
34.5
0.48
1
3
301
Jewett Road Station 291
Dist-Unattended
34.4
13.8
2.4
10
1
302
Johnson Road Station 352
Dist-Unattended
115
13.8
24
2
303
Johnstown Station 61
Dist-Unattended
67
4.4
5
1
304
Johnstown Station 61
Dist-Unattended
69
4.2
4.8
10
1
305
Juniper Station 500
Dist-Unattended
34.5
13.2
4
1
306
Karner Station 317
Dist-Unattended
34.4
4.4
10
2
307
Kenmore Terminal Station 158
Dist-Unattended
115
23
27
2
308
Kensington Terminal Station
Trans-Unattended
115
23
90
3
309
Kensington Terminal Station
Trans-Unattended
115
23.7
30
1
310
Kilian Manufacturing Corporation - TS 2296
Dist-Unattended
34.4
0.24
1
2
311
Kilian Manufacturing Corporation - TS 2296
Dist-Unattended
34.5
0.24
1
312
Knapp Road Station 226
Dist-Unattended
115
13.8
15
1
313
Knights Creek Station 06
Dist-Unattended
34.5
4.8
2
1
314
Labrador Station 230
Trans-Unattended
34.5
13.8
2
1
315
Labrador Station 230
Trans-Unattended
115
34.5
8
1
316
Lake Colby Station 927
Trans-Unattended
110
46
18
1
317
Lake Colby Station 927
Trans-Unattended
115
13.8
13
1
318
Lake Colby Station 927
Trans-Unattended
115
15
50
1
319
Lake Colby Station 927
Trans-Unattended
115
46
20
1
320
Lake Road No. 2 Station 299
Dist-Unattended
115
13.8
12
1
321
Lakeview Station 182
Dist-Unattended
115
13.2
15
1
322
Lakeville Station 40
Dist-Unattended
34.5
4.8
4
1
323
Langford Station 180
Dist-Unattended
34.5
13.8
5
1
324
Lansingburgh Station 93
Dist-Unattended
13.2
4.16
5
2
325
Lansingburgh Station 93
Dist-Unattended
34.5
13.2
8
1
326
Lapp Station 26
Dist-Unattended
115
4.4
5
1
327
Latham Station 282
Dist-Unattended
34.4
13.8
10
1
328
Lawrence Avenue Station 976
Dist-Unattended
115
13.2
24
2
329
Leeds Station 377
Trans-Unattended
345
18
330
4
330
Lehigh Station 669
Dist-Unattended
115
13.8
15
1
1
331
Leray Station 813
Dist-Unattended
23
4.8
2
1
332
Levant Station 98
Dist-Unattended
34.5
4.8
1
1
333
Levitt Station 665
Dist-Unattended
110
5
8
1
334
Liberty Street Station 94
Dist-Unattended
34.4
4.36
10
2
335
Liberty Street Station 94
Dist-Unattended
34.4
4.4
5
1
336
Liberty Street Station 94
Dist-Unattended
34.5
13.8
10
1
337
Lighthouse Hill Station 61
Trans-Unattended
115
34.5
15
2
338
Lima Station 36
Dist-Unattended
34.5
4.8
3
1
339
Linden Station 21
Dist-Unattended
34.5
4.8
2
1
340
Lisbon Station 963
Dist-Unattended
22
5
2
1
341
Little River Station 955
Dist-Unattended
115
13.2
15
1
342
Little River Station 955
Dist-Unattended
115
24
10
1
343
Livingston Correctional Station 130
Dist-Unattended
34.5
13.2
2
3
344
Livonia Station 37
Dist-Unattended
34.5
4.8
4
1
345
Lockport Station
Trans-Unattended
115
12
8
1
346
Loon Lake Station 837
Dist-Unattended
46
4.8
1
2
347
Lords Hill Station 150
Dist-Unattended
34.4
5
4
1
348
Lorings Station 276
Dist-Unattended
34.4
13.8
4
1
349
Lowville Station 773
Trans-Unattended
110
24
12
1
350
Lowville Station 773
Trans-Unattended
115
13.8
15
1
351
Lyme Station 733
Dist-Unattended
115
13.8
15
1
352
Lyndonville Station 95
Dist-Unattended
34.5
4.8
4
1
353
Lynn Street Station 320
Dist-Unattended
34.5
13.2
8
1
354
Lysander Station 297
Dist-Unattended
113
13.8
12
1
355
Machias Station 13
Trans-Unattended
34.5
4.8
4
1
356
Machias Station 13
Trans-Unattended
115
34.5
50
2
357
Madison Station 654
Dist-Unattended
110
5
8
3
1
358
Mallory Road Station 40
Trans-Unattended
110
34.5
18
1
359
Mallory Road Station 40
Trans-Unattended
113
34.5
1
360
Malone Station 895
Trans-Unattended
115
13.8
15
1
361
Malone Station 895
Trans-Unattended
115
34.5
18
2
362
Malta Station 443
Dist-Unattended
115
13.8
15
1
363
Maplehurst Station 04
Dist-Unattended
34.4
5.04
4
1
364
Maplewood Station 307
Trans-Unattended
115
13.8
15
1
365
Maplewood Station 307
Trans-Unattended
115
34.4
13.8
30
1
366
Market Hill Station 324
Dist-Unattended
67
4.4
5
1
367
Market Hill Station 324
Dist-Unattended
69
4.4
5
1
368
Marshville Station 299
Trans-Unattended
110
67
13.8
30
1
369
Marshville Station 299
Trans-Unattended
115
69
23
50
1
370
Mayfield Station 356
Dist-Unattended
67
13.8
8
1
371
McAdoo Station 914
Dist-Unattended
115
13.8
12
1
372
McClellan Street Station 304
Dist-Unattended
34.5
13.2
10
1
373
McCrea Street Station 272
Dist-Unattended
33
4.8
3
1
374
McGraw Station 228
Dist-Unattended
34.4
5
1
1
375
McGraw Station 228
Dist-Unattended
34.5
5
2
2
376
Mcintosh Box & Pallet Corporation - TS 2766
Dist-Unattended
34.5
0.48
1
3
377
McIntyre Station 969
Trans-Unattended
110
24
12
1
378
McIntyre Station 969
Trans-Unattended
115
23
15
1
379
McKownville Station 327
Dist-Unattended
113
13.8
12
1
380
McKownville Station 327
Dist-Unattended
115
13.2
20
1
381
Meco Station 318
Dist-Unattended
69
23
1
382
Meco Station 318
Trans-Unattended
69
13.2
1
383
Meco Station 318
Trans-Unattended
113
67
5
40
1
384
Menands Station 101
Trans-Unattended
13.8
3.4
6
1
385
Menands Station 101
Trans-Unattended
110
4.36
8
1
386
Menands Station 101
Trans-Unattended
110
34.4
8.66
20
1
387
Menands Station 101
Trans-Unattended
115
13.8
27
2
388
Menands Station 101
Trans-Unattended
115
34.5
5
30
1
389
Merrillsville Station 838
Dist-Unattended
46
2.4
1
390
Mexico Station 43
Dist-Unattended
34.4
5
3
1
391
Middleburg Station 390
Dist-Unattended
67
13.8
8
1
392
Middleport Station 77
Dist-Unattended
34.5
4.8
4
1
393
Middleville Station 666
Dist-Unattended
43.8
4.2
4
1
394
Midler Station 145
Dist-Unattended
34.4
4.4
5
1
395
Midstate Construction Company Station 148
Dist-Unattended
34.5
2.4
1
2
396
Midstate Construction Company Station 148
Dist-Unattended
34.5
2.4
0.24
1
397
Midstate Correctional Facility
Dist-Unattended
46
2.4
3
4
398
Mill Street Station 748
Trans-Unattended
23
5
15
3
399
Miller Street Station 117
Dist-Unattended
34.5
4.8
8
3
400
Milton Avenue Station 266
Dist-Unattended
113
13.8
12
1
401
Milton Avenue Station 266
Dist-Unattended
115
13.8
24
1
402
Mine Road Station 777
Trans-Unattended
34.4
23
8
1
403
Minoa Station 44
Dist-Unattended
34.4
5
4
1
404
MOBILE SUB 7991 CENTRAL
Dist-Unattended
115
13.2
40
1
405
MOBILE SUB 8 CENTRAL
Dist-Unattended
115
13.2
40
1
406
Mohican Station 247
Trans-Unattended
113
34.4
5
30
1
407
Mohican Station 247
Trans-Unattended
115
34.5
20
3
408
Moira Station 859
Dist-Unattended
34.4
5
3
1
409
Monarch Machine Tool Station 264
Dist-Unattended
34.4
2.4
2
3
410
Morristown Station 933
Dist-Unattended
23
5.04
3
1
411
Mortimer Station
Trans-Unattended
115
63
11.5
20
1
412
Mountain Station
Trans-Unattended
115
34.5
40
2
413
Mumford Station 50
Dist-Unattended
115
13.2
15
1
414
Nassau Station 113
Dist-Unattended
34.4
19.8
5
1
415
New Haven Station 256
Dist-Unattended
113
13.8
8
1
416
New Krumkill Station 421
Dist-Unattended
13.8
4.4
8
1
417
New Krumkill Station 421
Dist-Unattended
113
13.8
18
1
418
New Scotland Station 325
Trans-Unattended
345
120
13.8
537
2
419
New Walden Station
Trans-Unattended
115
34.5
60
2
420
Newark Station 300
Dist-Unattended
34.5
13.2
20
2
421
Newton Falls Station 774
Dist-Unattended
34.5
2.4
1
3
422
Newtonville Station 305
Dist-Unattended
34.4
2.5
10
2
423
Nicholville Station 860
Trans-Unattended
34.5
4.8
4
3
424
Nicholville Station 860
Trans-Unattended
115
34.5
10
1
1
425
Nile Station
Trans-Unattended
115
34.5
8
1
426
Niles Station 294
Dist-Unattended
34.4
13.8
4
1
427
Norfolk Station 934
Trans-Unattended
115
24
10
1
428
North Akron Station
Trans-Unattended
115
34.5
15
2
429
North Angola Station
Trans-Unattended
115
34.5
30
2
430
North Ashford Station 36
Trans-Unattended
34.5
4.8
2
1
431
North Bangor Station 864
Dist-Unattended
34.4
5
2
1
432
North Bombay Station 866
Dist-Unattended
34.5
13.2
5
1
433
North Carthage Station 816
Dist-Unattended
115
13.2
12
1
434
North Carthage Station 816
Dist-Unattended
115
23
15
1
435
North Chautauqua Station
Dist-Unattended
34.5
4.8
1
1
436
North Collins Station 92
Dist-Unattended
34.5
4.8
3
1
437
North Creek Station 122
Dist-Unattended
115
13.8
40
2
438
North Eden Station 82
Dist-Unattended
34.5
13.2
4
1
439
North Gouverneur Station 983
Dist-Unattended
115
13.8
12
1
440
North Lakeville Station
Trans-Unattended
115
34.5
25
1
441
North Lawrence Station 861
Dist-Unattended
34
5
3
1
442
North LeRoy Station
Trans-Unattended
115
34.5
15
1
443
North LeRoy Station 04
Dist-Unattended
115
13.2
12
1
444
North Olean Station 30
Dist-Unattended
34.5
4.8
4
3
445
North Troy Station 123
Trans-Unattended
115
13.8
15
1
446
North Troy Station 123
Trans-Unattended
115
34.5
60
2
447
Northville Station 332
Dist-Unattended
69
13.8
10
1
448
Northville Station 332
Dist-Unattended
69
23
10
1
449
Norwood Station 936
Trans-Unattended
23
4.8
4
3
450
Oak Hill Station 62
Dist-Unattended
34.5
4.8
3
1
451
Oakfield Station 03
Trans-Unattended
34.5
4.8
4
1
452
Oakfield Station 03
Trans-Unattended
115
34.5
28
1
453
Oakwood Ave Station 232
Dist-Unattended
115
13.8
30
2
454
Oathout Station 402
Dist-Unattended
34.4
13.8
10
1
455
Ogdenbrook Station 423
Dist-Unattended
115
13.8
32
2
456
Ogdensburg Station 938
Trans-Unattended
115
13.8
15
1
457
Ogdensburg Stone Station 932
Dist-Unattended
23
0.48
1
1
458
Ogdensburg Stone Station 932
Dist-Unattended
23
5
2
459
Old Forge Station 383
Dist-Unattended
46
4.8
9
4
460
Oneida Station 501
Trans-Unattended
115
13.8
48
2
461
Orangeville Station 19
Dist-Unattended
34.5
4.8
3
1
462
Oswego Switch Yard
Trans-Unattended
115
34.5
30
3
1
463
Oswego Switch Yard
Trans-Unattended
345
120
13.8
448
1
464
Otten Station 412
Dist-Unattended
115
5
4
1
465
Packard Station
Trans-Unattended
230
120
13.2
150
2
1
466
Paloma Station 254
Dist-Unattended
115
13.8
36
2
467
Panama Station 70
Dist-Unattended
34.5
4.8
2
1
468
Parish Station 49
Dist-Unattended
34.4
5
3
1
469
Parishville Station 939
Trans-Unattended
4.8
2.4
1
2
470
Park Street Station 144
Dist-Unattended
34.4
4.36
5
1
471
Partridge Street Station 128
Dist-Unattended
34.4
4.4
20
2
472
Patroon Station 323
Trans-Unattended
110
34.4
13.8
30
1
473
Patroon Station 323
Trans-Unattended
115
13.2
15
1
474
Paul Smiths Station 384
Dist-Unattended
46
4.8
3
1
475
Peat Street Station 250
Dist-Unattended
113
13.8
12
1
476
Pebble Hill Station 290
Trans-Unattended
115
13.8
20
1
477
Pebble Hill Station 290
Trans-Unattended
116
34.5
20
1
478
Peckham Materials
Dist-Unattended
34.4
0.24
2
3
479
Perryville Station 50
Dist-Unattended
34.4
2.5
3
1
480
Peterboro Station 514
Dist-Unattended
115
13.2
15
1
481
Peterboro Station 514
Dist-Unattended
115
13.8
24
1
482
Petrolia Station 19
Dist-Unattended
34.5
4.8
3
3
483
Phoenix Station 51
Dist-Unattended
34.4
5
5
1
484
Piercefield Station 502
Trans-Unattended
43.8
2.4
1
3
485
Pine Grove Station 59
Dist-Unattended
115
13.8
44
2
486
Pinebush Station 371
Dist-Unattended
113
13.8
12
1
487
Pinebush Station 371
Dist-Unattended
115
13.8
15
1
488
Pleasant Station 664
Dist-Unattended
43.8
4.4
10
2
489
Poland Station 621
Dist-Unattended
43.6
13.8
10
1
490
Poland Station 66
Dist-Unattended
34.5
4.8
3
1
491
Pompey Station 120
Dist-Unattended
34.5
4.8
2
3
492
Port Henry Station 385
Dist-Unattended
113
13.8
8
1
493
Port Leyden Station 755
Dist-Unattended
23
5
2
3
494
Portage Street Station 754
Dist-Unattended
23
5
5
1
495
Porter Station 657
Trans-Unattended
230
115
13.2
534
2
496
Porter Station 657
Trans-Unattended
230
120
13.8
1
497
Pottersville Station 424
Dist-Unattended
34.4
13.2
8
1
498
Price Corners Station 14
Dist-Unattended
34.4
13.8
2.63
4
1
499
Prospect Hill Station 413
Dist-Unattended
113
13.8
12
1
500
Queensbury Station 295
Trans-Unattended
110
34.4
30
1
501
Queensbury Station 295
Trans-Unattended
115
13.8
48
2
502
Raquette Lake Station 398
Dist-Unattended
43.8
5
1
3
503
Raybrook Station 839
Dist-Unattended
115
13.8
15
1
504
RAYMOUR & FLANIGAN
Dist-Unattended
34.4
0.48
8
1
505
RAYMOUR & FLANIGAN
Dist-Unattended
34.5
0.48
1
2
506
Renaissance Drive Station 229
Dist-Unattended
115
13.8
40
2
507
Rensselaer Station 132
Trans-Unattended
34.5
13.2
10
1
508
Reservoir Station 103
Dist-Unattended
34.4
5.04
5
1
509
Reynolds Road Station 334
Trans-Unattended
115
13.8
30
2
510
Reynolds Road Station 334
Trans-Unattended
345
120
13.8
400
1
511
Richmond Station 32
Dist-Unattended
34.5
13.8
8
1
512
Ridge Road Station 219
Dist-Unattended
34.5
4.8
3
3
513
Ridge Station 142
Trans-Unattended
115
34.5
40
2
514
Riparius Station 293
Dist-Unattended
34.4
19.8
4
1
515
Ripley Station 53
Dist-Unattended
34.5
4.8
4
1
516
Riverside Station 288
Dist-Unattended
13.2
4.16
1
517
Riverside Station 288
Dist-Unattended
13.2
12
1
518
Riverside Station 288
Dist-Unattended
34.4
5.04
1
519
Riverside Station 288
Dist-Unattended
34.4
13.8
2
520
Riverside Station 288
Dist-Unattended
34.5
0.48
1
521
Riverside Station 288
Dist-Unattended
34.5
4.8
1
522
Riverside Station 288
Dist-Unattended
67
13.8
1
523
Riverside Station 288
Dist-Unattended
68.8
34.4
1
524
Riverside Station 288
Dist-Unattended
110
13.8
24
1
525
Riverside Station 288
Dist-Unattended
113
34.4
40
1
526
Riverside Station 288
Dist-Unattended
113
67
13.8
1
527
Riverside Station 288
Dist-Unattended
115
13.8
1
528
Riverside Station 288
Dist-Unattended
115
13.8
7.97
24
1
529
Riverside Station 288
Dist-Unattended
115
34.4
40
1
530
Riverside Station 288
Dist-Unattended
115
34.4
13.8
1
531
Riverview Station 847
Dist-Unattended
43.8
4.8
1
1
532
Roberts Road Station 154
Dist-Unattended
115
13.2
13
1
533
Rock City Falls Station 404
Dist-Unattended
34.5
4.8
4
1
534
Rock City Station 623
Dist-Unattended
43.8
4.4
6
1
535
Rock Cut Station 286
Dist-Unattended
115
13.8
24
1
536
Rock Cut Station 286
Dist-Unattended
116
13.8
18
1
537
Rome Station 762
Trans-Unattended
115
13.8
36
2
538
Rosa Road Station 137
Trans-Unattended
113
13.8
12
1
539
Rosa Road Station 137
Trans-Unattended
115
34.5
30
1
540
Rotterdam Station 138
Trans-Unattended
113
68
13.8
34
1
541
Rotterdam Station 138
Trans-Unattended
115
13.8
15
1
542
Rotterdam Station 138
Trans-Unattended
115
34.4
13.8
20
1
543
Rotterdam Station 138
Trans-Unattended
115
34.5
13.8
20
3
544
Rotterdam Station 138
Trans-Unattended
230
115
13.8
267
1
545
Rotterdam Station 138
Trans-Unattended
230
120
13.8
616
2
546
Royalton Station 98
Dist-Unattended
34.5
4.8
3
2
547
Ruth Road Station 381
Dist-Unattended
113
13.8
18
1
548
S/C - Batavia
Trans-Unattended
34.5
4.8
1
549
S/C - Campion Road
Dist-Unattended
12
0.48
2
550
S/C - Campion Road
Dist-Unattended
44
4.16
1
551
S/C - Eastern Region Warehouse - Clifton Park
Dist-Unattended
34.5
4.16
1
552
S/C - Fredonia
Dist-Unattended
34.5
13.8
1
553
S/C - Henry Clay Blvd.
Dist-Unattended
1
554
S/C - Henry Clay Blvd.
Dist-Unattended
34.4
4.36
1
555
S/C - Henry Clay Blvd.
Dist-Unattended
34.4
4.8
1
556
S/C - Henry Clay Blvd.
Dist-Unattended
34.5
2.4
6
557
S/C - Henry Clay Blvd.
Dist-Unattended
34.5
4.8
1
558
S/C - Henry Clay Blvd.
Dist-Unattended
115
5.04
1
559
S/C - Henry Clay Blvd.
Dist-Unattended
115
7.97
1
560
S/C - Henry Clay Blvd.
Dist-Unattended
115
13.2
1
561
S/C - Henry Clay Blvd.
Dist-Unattended
115
13.8
2
562
S/C - Henry Clay Blvd.
Dist-Unattended
115
23
1
563
S/C - Henry Clay Blvd.
Dist-Unattended
115
26.5
1
564
S/C - Henry Clay Blvd.
Dist-Unattended
115
34.5
1
565
S/C - Henry Clay Blvd.
Dist-Unattended
115
46
1
566
S/C - Henry Clay Blvd.
Dist-Unattended
34,400
5,040
1
567
S/C - Potsdam
Dist-Unattended
23
4.8
1
568
S/C - Potsdam
Dist-Unattended
23
5.04
1
569
S/C - Potsdam
Dist-Unattended
34.4
5
1
570
S/C - Potsdam
Dist-Unattended
115
4.8
1
571
S/C - South Watertown
Dist-Unattended
23
4.8
1
572
Saint Johnsville Station 335
Dist-Unattended
110
13.8
4.8
8
1
573
Saint Johnsville Station 335
Dist-Unattended
110
13.8
5
5
1
574
Saint Regis Station 977
Dist-Unattended
34.5
4.8
5
1
575
Salisbury Station 678
Dist-Unattended
110
13.8
6
1
576
Salisbury Station 678
Dist-Unattended
113
13.8
8
1
577
Sanborn Station
Trans-Unattended
115
34.5
15
1
578
Sand Creek Station 452
Dist-Unattended
115
13.2
15
1
579
Sand Road Station 131
Dist-Unattended
34.4
4.4
4
1
580
Sandy Creek Station 66
Dist-Unattended
34.5
13.8
5
1
581
Saratoga Station 142
Dist-Unattended
33
4.2
5
1
582
Saratoga Station 142
Dist-Unattended
34.4
13.8
8
1
583
Sawyer Avenue Station
Trans-Unattended
23
13.3
1
584
Sawyer Avenue Station
Trans-Unattended
230
23
180
3
1
585
Schenevus Station 261
Dist-Unattended
22
4.8
2
3
586
Schodack Station 451
Dist-Unattended
115
13.8
12
1
587
Schoharie Station 234
Trans-Unattended
67
13.8
8
1
588
Schroon Lake station 429
Dist-Unattended
34.4
13.8
5
1
589
Schuyler Station 663
Trans-Unattended
110
43.8
42
2
590
Schuyler Station 663
Trans-Unattended
115
13.8
20
1
591
Schuylerville Station 39
Trans-Unattended
34.4
4.8
5
1
592
Scofield Road Station 450
Dist-Unattended
113
13.8
8
1
593
Scotia Station 255
Dist-Unattended
34.5
4.16
10
2
594
Sealright Station 273
Dist-Unattended
113
2.4
10
1
595
Selkirk Station 149
Dist-Unattended
34.4
13.8
8
1
596
Seminole Station 339
Dist-Unattended
34.4
4.4
5
1
597
Seneca Terminal Station
Trans-Unattended
115
23
90
3
1
598
Sentinel Heights Station 128
Dist-Unattended
33
2.3
1
3
599
Seventh Avenue Station 244
Dist-Unattended
34.5
4.2
5
1
600
Seventh North Street Station 231
Dist-Unattended
34.4
5
6
1
601
Sewalls Island Station 766
Trans-Unattended
23
4.8
8
1
602
Shaleton Station 81
Trans-Unattended
115
34.5
8
1
603
Sharon Station 363
Dist-Unattended
69
13.2
8
1
604
Shelby Station 76
Dist-Unattended
115
13.2
15
1
605
Shelby Station 76
Dist-Unattended
115
13.8
15
1
606
Sheppard Road Station 29
Dist-Unattended
34.4
13.8
5
1
607
Sheppard Road Station 29
Dist-Unattended
34.5
13.2
4
1
608
Sherman Station 333
Dist-Unattended
46
13.8
10
1
609
Sherman Station 54
Dist-Unattended
34.5
4.8
3
1
610
Shore Road Station 281
Dist-Unattended
34.4
4.8
5
1
611
Silver Lake Station 845
Dist-Unattended
46
2.4
1
612
Sinclairville Station 72
Dist-Unattended
34.5
4.8
3
1
613
Smith Bridge Station 464
Dist-Unattended
115
13.8
15
1
614
Solvay Station 57
Trans-Unattended
110
34.5
25
5
615
Solvay Station 57
Trans-Unattended
115
34.5
15
3
616
Solvay Station 57
Trans-Unattended
116
33
10
2
617
Solvay Station 57
Trans-Unattended
116
34.5
10
2
618
Sonora Way Station 4381
Dist-Unattended
115
13.8
15
1
619
Sorrell Hill Station 269
Dist-Unattended
115
13.8
15
1
620
South Dow Station
Trans-Unattended
115
34.5
40
2
621
South Philadelphia Station 764
Dist-Unattended
23
4.8
5
1
622
South Randolph Station 32
Dist-Unattended
34.5
4.8
2
1
623
South Street Station 297
Dist-Unattended
34.4
13.2
10
1
624
South Washington Street Station 614
Dist-Unattended
46
13.8
5
1
625
South Wellsville Station 23
Dist-Unattended
34.5
4.8
4
1
626
Southland Station 84
Dist-Unattended
34.5
4.8
4
1
627
Southwood Station 244
Dist-Unattended
110
13.8
12
1
628
Spencer Haley
Dist-Unattended
34.5
0.48
1
3
629
Spier Falls Station 34
Trans-Unattended
115
34.4
5
50
1
630
Springfield Station 167
Dist-Unattended
34.4
4.16
5
1
631
Springfield Station 167
Dist-Unattended
34.5
4.4
5
1
632
Star Lake Station 727
Dist-Unattended
34.4
5
4
1
633
Starr Road Station 334
Dist-Unattended
115
13.8
30
2
634
Station 021
Dist-Unattended
23
4.16
15
4
635
Station 022
Dist-Unattended
23
4.4
15
4
636
Station 023
Dist-Unattended
22.9
4.36
15
4
637
Station 024
Dist-Unattended
23
4.4
15
4
638
Station 025
Dist-Unattended
22
4.3
8
3
639
Station 025
Dist-Unattended
23
4.33
3
1
640
Station 026
Dist-Unattended
23
4.4
15
4
641
Station 027
Dist-Unattended
22.9
4.3
15
4
642
Station 028
Dist-Unattended
23
4.4
15
4
643
Station 029
Dist-Unattended
22.9
4.36
15
4
644
Station 030
Dist-Unattended
22
4.3
10
4
645
Station 031
Dist-Unattended
22
4.3
8
3
646
Station 031
Dist-Unattended
22.9
4.36
3
1
647
Station 032
Dist-Unattended
23
4.16
3
1
648
Station 032
Dist-Unattended
23
4.33
8
3
649
Station 033
Dist-Unattended
23
4.36
15
4
650
Station 034
Dist-Unattended
22
4.3
5
2
651
Station 034
Dist-Unattended
23
4.16
3
1
652
Station 034
Dist-Unattended
23
4.3
3
1
653
Station 035
Dist-Unattended
22
4.3
8
3
654
Station 035
Dist-Unattended
23
4.3
3
1
655
Station 036
Dist-Unattended
2.29
4.36
4
1
656
Station 036
Dist-Unattended
23
4.4
11
3
657
Station 037
Dist-Unattended
22.9
4.3
15
4
658
Station 038
Dist-Unattended
22
4.3
10
4
659
Station 039
Dist-Unattended
22.9
4.4
15
4
660
Station 040
Dist-Unattended
23
4.16
15
4
661
Station 041
Dist-Unattended
23
4.16
10
4
662
Station 042 MITS
Dist-Unattended
34.5
13.8
10
1
663
Station 043
Dist-Unattended
22.9
4.16
4
1
664
Station 043
Dist-Unattended
22.9
4.36
4
1
665
Station 043
Dist-Unattended
23
4.16
8
2
666
Station 044
Dist-Unattended
22.9
4.36
15
4
667
Station 045
Dist-Unattended
22
4.3
3
1
668
Station 045
Dist-Unattended
23
4.16
8
3
669
Station 046
Dist-Unattended
2.29
4.36
4
1
670
Station 046
Dist-Unattended
22.9
4.36
4
1
671
Station 046
Dist-Unattended
23
4.4
8
2
672
Station 047
Dist-Unattended
23
4.36
11
3
673
Station 048
Dist-Unattended
22.4
4.4
8
2
674
Station 048
Dist-Unattended
22.9
4.4
8
2
675
Station 049
Dist-Unattended
22.9
4.4
15
4
676
Station 050
Dist-Unattended
22.9
4.4
8
2
677
Station 050
Dist-Unattended
23
4.36
4
1
678
Station 051
Dist-Unattended
22
4.3
10
4
679
Station 052
Dist-Unattended
23
4.16
15
4
680
Station 053
Dist-Unattended
22
4.3
8
3
681
Station 054
Dist-Unattended
115
4.3
8
1
682
Station 054
Dist-Unattended
115
4.33
8
1
683
Station 055
Dist-Unattended
115
4.3
8
2
684
Station 056
Dist-Unattended
22.9
4.3
11
3
685
Station 057
Dist-Unattended
22.9
4.4
11
3
686
Station 058
Dist-Unattended
34.4
4.36
4
1
687
Station 058
Dist-Unattended
34.4
4.4
11
3
688
Station 059
Dist-Unattended
22
4.3
5
2
689
Station 059
Dist-Unattended
23
4.16
3
1
690
Station 060 - Getzville
Trans-Unattended
115
13.8
24
2
691
Station 061
Dist-Unattended
115
4.16
8
1
692
Station 061
Dist-Unattended
115
4.36
8
1
693
Station 063
Dist-Unattended
22.9
4.36
4
1
694
Station 063
Dist-Unattended
23
4.16
9
2
695
Station 064 - Grand Island
Dist-Unattended
113
13.8
24
2
696
Station 066
Dist-Unattended
34.5
4.8
2
1
697
Station 067
Dist-Unattended
34.5
4.16
8
2
698
Station 068
Dist-Unattended
23
4.16
10
4
699
Station 071 - South Newfane
Dist-Unattended
34.4
5.04
4
1
700
Station 074
Dist-Unattended
22.9
4.36
3
1
701
Station 074
Dist-Unattended
23
4.16
6
2
702
Station 076 - Shawnee Road
Dist-Unattended
115
13.8
27
2
703
Station 077
Dist-Unattended
23
4.16
9
2
704
Station 078
Trans-Unattended
115
4.3
23
15
2
705
Station 078
Trans-Unattended
115
23
85
4
706
Station 079
Dist-Unattended
22
4.33
3
1
707
Station 079
Dist-Unattended
23
4.16
5
2
708
Station 080 - Eighth Street
Dist-Unattended
12
4.16
11
3
709
Station 081 - Beech Avenue
Dist-Unattended
12
4.16
11
3
710
Station 082 - Eleventh Street
Dist-Unattended
11
11
4
1
711
Station 082 - Eleventh Street
Dist-Unattended
11.4
5.04
4
1
712
Station 082 - Eleventh Street
Dist-Unattended
12
4.16
1
713
Station 082 - Eleventh Street
Dist-Unattended
12
4.8
4
1
714
Station 083 - Welch Avenue
Dist-Unattended
12
4.16
11
3
715
Station 085 - Stephenson Avenue
Dist-Unattended
12
4.8
11
3
716
Station 086 - Lewiston Heights
Dist-Unattended
34.5
4.8
5
1
717
Station 087 - Lewiston
Dist-Unattended
34.5
4.8
4
1
718
Station 088 - Youngstown
Dist-Unattended
34.4
5.04
4
1
719
Station 089 - Ransomville
Dist-Unattended
34.5
4.8
4
1
720
Station 093 - Wilson
Dist-Unattended
34.4
5.04
8
1
721
Station 097 - Summit Park
Dist-Unattended
113
13.8
24
2
722
Station 105 - Swann Road
Dist-Unattended
115
13.8
30
2
723
Station 121 - Clinton
Dist-Unattended
34.5
4.8
2
3
724
Station 122 - Tonawanda News
Dist-Unattended
23
4.16
12
4
725
Station 124 - Almeda Ave
Dist-Unattended
34.5
4.16
17
4
726
Station 126 - Gibson St
Dist-Unattended
23
4.16
5
2
727
Station 127 - Delaware Rd
Dist-Unattended
22
4.3
3
1
728
Station 127 - Delaware Rd
Dist-Unattended
23
4.16
5
2
729
Station 129 - Brompton Rd
Dist-Unattended
115
4.33
8
1
730
Station 129 - Brompton Rd
Dist-Unattended
115
4.36
8
1
731
Station 130
Dist-Unattended
115
13.8
40
2
732
Station 132
Dist-Unattended
34.5
4.8
4
1
733
Station 133 - Dupont
Dist-Unattended
115
4.16
13
1
734
Station 139 - Martin Rd
Dist-Unattended
115
4.33
8
2
735
Station 140
Dist-Unattended
115
13.8
36
2
736
Station 142 - Ridge
Trans-Unattended
115
4.33
8
1
737
Station 146 (Walden Ave)
Dist-Unattended
34.5
4.8
2
1
738
Station 146 (Walden Ave)
Dist-Unattended
34.5
13.8
4
1
739
Station 154
Dist-Unattended
115
4.16
8
2
740
Station 155 - Worthington
Dist-Unattended
115
4.16
8
1
741
Station 157
Dist-Unattended
23
4.16
5
1
742
Station 160 - Summer St
Dist-Unattended
23
4.16
12
3
743
Station 161 - Short St
Dist-Unattended
23
4.16
11
3
744
Station 162
Dist-Unattended
23
4.16
6
2
745
Station 170 - Newfane
Dist-Unattended
34.5
4.8
5
1
746
Station 171 - Burt
Dist-Unattended
34.4
5.04
4
1
747
Station 202
Dist-Unattended
23
4.16
4
1
748
Station 203
Dist-Unattended
23
4.16
2
1
749
Station 205
Dist-Unattended
23
13.2
15
4
750
Station 206 - Tonawanda Creek
Dist-Unattended
115
13.2
15
1
751
Station 206 - Tonawanda Creek
Dist-Unattended
115
13.8
15
1
752
Station 207 - Slade Road
Dist-Unattended
34.4
13.8
4
1
753
Station 208
Dist-Unattended
23
4.16
4
1
754
Station 208
Dist-Unattended
23
4.4
7
2
755
Station 209 - Long Rd
Dist-Unattended
115
13.2
15
1
756
Station 210 - Military Road
Dist-Unattended
115
13.8
40
2
757
Station 211 - Ayer Rd
Dist-Unattended
115
13.8
40
2
758
Station 212
Dist-Unattended
115
13.2
30
2
759
Station 213
Dist-Unattended
113
13.8
8
1
760
Station 214 - Youngs St
Dist-Unattended
115
4.16
8
1
761
Station 215 - Buffalo Avenue
Dist-Unattended
115
13.2
20
1
762
Station 215 - Buffalo Avenue
Dist-Unattended
115
13.8
20
1
763
Station 216 - Lockport Road
Dist-Unattended
115
13.8
15
1
764
Station 217 - Walmore Rd
Trans-Unattended
113
13.8
13
1
765
Station 219 - Park Club Ln
Trans-Unattended
115
13.2
5
1
766
Station 224 - Sweethome Rd
Dist-Unattended
115
13.2
20
1
767
Station 224 - Sweethome Rd
Dist-Unattended
115
13.8
20
1
768
Stiles Station 58
Dist-Unattended
34.4
5
5
3
769
Stittville Station 670
Dist-Unattended
113
13.8
8
1
770
Stoner Station 358
Dist-Unattended
113
13.8
12
1
771
Stow Station 52
Dist-Unattended
34.5
4.8
3
1
772
Stuyvesant Station 977
Trans-Unattended
34.4
13.8
10
1
773
Summit Station 347
Dist-Unattended
67
5
8
1
774
Summit Station 347
Dist-Unattended
67
23
8
1
775
Sunday Creek Station 876
Dist-Unattended
115
13.8
3
1
776
Swaggertown Station 364
Dist-Unattended
115
13.2
12
1
777
Sweden Station
Trans-Unattended
115
34.5
15
1
778
Sycaway Station 372
Dist-Unattended
113
13.8
12
1
779
Sycaway Station 372
Dist-Unattended
115
13.8
7.97
15
1
780
Taylorville Station 770
Trans-Unattended
115
23
20
1
781
Teall Avenue Station 72
Trans-Unattended
115
13.8
7.97
24
1
782
Teall Avenue Station 72
Trans-Unattended
115
34.5
60
2
783
Telegraph Road Station
Trans-Unattended
115
19.92
30
1
784
Telegraph Road Station
Trans-Unattended
115
34.5
30
1
785
Temple Station 243
Dist-Unattended
113
13.8
48
2
786
Temple Station 243
Dist-Unattended
115
13.8
27
1
787
Terminal Station 651
Trans-Unattended
110
13.2
27
1
788
Terminal Station 651
Trans-Unattended
115
13.8
7.97
24
1
789
Third Street Station 216
Dist-Unattended
34.4
5
4
1
790
Thousand Islands Station 814
Dist-Unattended
115
13.2
30
2
791
Tibbits Avenue Station 292
Dist-Unattended
34.4
4.4
5
1
792
Tilden Station 73
Trans-Unattended
110
34.5
40
2
793
Townline Station
Trans-Unattended
115
46
30
1
794
Trinity Station 164
Dist-Unattended
13.8
4.36
8
1
795
Trinity Station 164
Dist-Unattended
113
13.8
67
2
796
Truxton Station 74
Dist-Unattended
33
4.6
1
797
Truxton Station 74
Dist-Unattended
33
4.8
1
4
798
Truxton Station 74
Dist-Unattended
34.5
4.8
1
799
Tuller Hill Station 246
Dist-Unattended
110
13.8
5
1
800
Tully Center Station 278
Dist-Unattended
115
13.8
15
1
801
Tupper Lake Station 830
Dist-Unattended
46
7
13
1
802
Turin Station 653
Trans-Unattended
115
13.8
15
1
803
Union Falls Station 844
Trans-Unattended
44
2.4
1
3
804
Union Street Station 376
Dist-Unattended
34.4
13.8
8
1
805
Unionville Station 276
Dist-Unattended
34.5
13.2
10
1
806
University Station 81
Dist-Unattended
115
13.8
12
1
807
Vail Mills Station 392
Dist-Unattended
115
13.8
15
1
808
Vail Mills Station 392
Dist-Unattended
115
69
13.8
30
1
809
Valkin Station 427
Dist-Unattended
115
13.8
12
1
810
Valley Station 44
Dist-Unattended
115
13.8
35
2
811
Valley Station 594
Dist-Unattended
115
4.16
15
2
812
Valley Station 594
Dist-Unattended
115
46
30
3
813
Vandalia Station 104
Dist-Unattended
34.5
13.2
5
1
814
Veterans Hospital
Dist-Unattended
34.4
13.8
15
2
815
Voorhees Station 83
Dist-Unattended
115
34.5
8
1
1
816
Voorheesville Station 178
Dist-Unattended
115
13.8
15
1
817
Walesville Station 331
Dist-Unattended
115
13.8
15
1
818
Warrensburg Station 321
Dist-Unattended
115
13.8
10
1
819
Warrensburg Station 321
Dist-Unattended
115
34.4
30
1
820
Waterfront Health Care Station
Dist-Unattended
23
0.21
1
1
821
Waterfront School Station 204
Dist-Unattended
23
4.16
4
1
822
Waterport Station 73
Trans-Unattended
34.5
4.8
4
1
823
Watt Street Station 380
Dist-Unattended
34.4
13.8
8
1
824
Weaver Street Station
Dist-Unattended
34.5
13.2
10
1
825
Weibel Avenue Station 415
Dist-Unattended
115
13.8
40
2
826
Wells Station 208
Dist-Unattended
23
4.8
3
1
827
West Adams Station 875
Dist-Unattended
115
13.8
15
1
828
West Albion Station 79
Dist-Unattended
34.5
13.2
10
2
829
West Cleveland Station 326
Dist-Unattended
34.4
13.2
1
1
830
West Cleveland Station 326
Dist-Unattended
34.5
13.8
1
2
831
West Hamlin Station 82
Dist-Unattended
115
13.8
20
1
832
West Herkimer Station 676
Dist-Unattended
43.8
13.8
5
1
833
West Monroe Station 274
Dist-Unattended
34.4
13.8
5
1
834
West Olean Station 33
Dist-Unattended
115
13.8
27
2
835
West Perrysburg Station 181
Dist-Unattended
34.5
13.8
5
1
836
West Salamanca Station 16
Trans-Unattended
34.5
4.8
2
1
837
West Seneca Storage Yard
Trans-Unattended
11
4.6
1
838
West Seneca Storage Yard
Trans-Unattended
13.2
12
4
839
West Seneca Storage Yard
Trans-Unattended
13.8
2.4
4.16
1
840
West Seneca Storage Yard
Trans-Unattended
22
4.3
1
841
West Seneca Storage Yard
Trans-Unattended
22.9
4.36
2
842
West Seneca Storage Yard
Trans-Unattended
23
2.4
3
843
West Seneca Storage Yard
Trans-Unattended
23
4.06
1
844
West Seneca Storage Yard
Trans-Unattended
23
4.16
3
845
West Seneca Storage Yard
Trans-Unattended
34.4
4.36
1
846
West Seneca Storage Yard
Trans-Unattended
34.4
5.04
2
847
West Seneca Storage Yard
Trans-Unattended
34.4
13.8
1
848
West Seneca Storage Yard
Trans-Unattended
34.5
0.48
1
849
West Seneca Storage Yard
Trans-Unattended
34.5
4.16
1
850
West Seneca Storage Yard
Trans-Unattended
34.5
4.8
1
851
West Seneca Storage Yard
Trans-Unattended
34.5
13.2
1
852
West Seneca Storage Yard
Trans-Unattended
34.5
13.8
4
853
West Seneca Storage Yard
Trans-Unattended
66
13.8
1
854
West Seneca Storage Yard
Trans-Unattended
115
4.33
1
855
West Seneca Storage Yard
Trans-Unattended
115
34.5
2
856
West Seneca Storage Yard
Trans-Unattended
230
120
13.8
2
857
West Valley Station 25
Dist-Unattended
34.5
4.8
3
1
858
Westvale Station 133
Dist-Unattended
34.5
4.16
8
1
859
Westville Station 885
Dist-Unattended
34.4
5
1
1
860
Westville Station 885
Dist-Unattended
34.5
5
3
2
861
Wethersfield Station 23
Dist-Unattended
34.5
4.8
2
2
862
Wetzel Road Station
Dist-Unattended
115
13.8
48
2
863
Whitaker Station 296
Dist-Unattended
115
13.8
18
1
864
White Lake Station 399
Dist-Unattended
43.8
5
2
3
865
Whitehall Station 187
Trans-Unattended
115
13.2
11
1
866
Whitesboro Station 632
Dist-Unattended
43.8
4.4
5
1
867
Whitesville Station 101
Dist-Unattended
34.5
4.8
2
1
868
Whitman Station 671
Trans-Unattended
115
34.5
8
1
869
Willow Specialties Station 24
Dist-Unattended
34.5
4.8
3
1
870
Wilton Station 329
Dist-Unattended
34.5
13.2
12
1
871
Wine Creek Station 283
Dist-Unattended
116
13.8
12
1
872
Wolf Road Station 344
Dist-Unattended
113
13.8
18
1
873
Wolf Road Station 344
Dist-Unattended
115
13.8
18
1
874
Woodard Station 233
Trans-Unattended
110
34.5
60
2
875
Woodlawn Station 188
Trans-Unattended
110
34.4
30
1
876
Woodlawn Station 188
Trans-Unattended
110
34.4
13.8
20
3
877
Worcester Station 189
Dist-Unattended
23
13.8
5.04
4
1
878
Yahnundasis Station 646
Trans-Unattended
113
46
21
1
879
Yahnundasis Station 646
Trans-Unattended
115
13.2
18
1
880
Yahnundasis Station 646
Trans-Unattended
115
46
20
1
881
York Center Station 53
Dist-Unattended
69
13.2
8
1
882
Youngmann Terminal Station
Trans-Unattended
115
34.5
40
2


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
  1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
  2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general".
  3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line No.
Description of the Good or Service
(a)
Name of Associated/Affiliated Company
(b)
Account(s) Charged or Credited
(c)
Amount Charged or Credited
(d)
1
Non-power Goods or Services Provided by Affiliated
2
NGUSA Service Company
(a)
372,174,175
3
Massachusetts Electric Company
(b)
921,421
4
KeySpan Gas East Corporation
(c)
270,328
19
20
Non-power Goods or Services Provided for Affiliated
21
Massachusetts Electric Company
(d)
6,942,044
22
Boston Gas Company
(e)
6,863,738
23
Narrangansett Electric Company
(f)
3,573,607
24
Brooklyn Union Gas
(g)
2,125,921
25
KeySpan Gas East Corporation
(h)
1,468,322
26
New England Power Company
(i)
803,965
27
Colonial Gas Company
(j)
742,551
28
NGUSA Service Company
(k)
469,635
42


Name of Respondent:

Niagara Mohawk Power Corporation
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/17/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

Advertising

554,177

AFUDC

384

Agency

4,193,882

Bad Debt Expense

217,827

Claims

3,166,449

Clothing and Shoes

110,679

Commission

11,939

Construction Contributions/Reimbursement

25

Consultant

30,509,980

Depreciation Expense

4,435,403

Donations

1,974,319

Dues and Subscriptions

1,895,725

Electric Generation

6,130

Electric Plant Amortization

22,427,505

Expense Reimbursements

(9,191)

FAS 112

(166,378)

Fleet Leasing

(356,550)

Fleet Pricing

233,216

Gain Sharing

15,701

Gas/Fuel

(9,167)

General/Other

38,698,698

Government Payments

96,080

Group Life

899,487

Hardware

850,460

Healthcare

15,768,642

Home Cost Center Residual Charges

631,686

Inventory

3,000,897

Legal

2,335,027

Management

102,580,189

Monthly

234,079

NGT Share Awards

1,715,769

OPEB

2,739,415

OPEB NSC

149,352

Operations

2,340,758

Other Benefits

944,659

Other Employee Expenses

1,536,494

Other Expense

23,005,676

Outside Vendor

2,274,886

Pave/Hot Patch

59

Payroll Tax

2,202,462

Pensions

10,342,645

Pensions NSC

7,563,970

Personnel

3,519,534

Police/Summons

2,580

Printing and Mail

9,887,640

Regulatory Assessments

9,705

Rent Non-Real Estate

1,266,337

Rents Real Estate

2,315,641

Research and Development

4,659

Sales and Use Tax

129

Service Company

80,993

Software

13,886,347

Sponsorships

552,337

Stores Handling

148,944

Supervision

(9,737,280)

Telecommunications

12,459,395

Thrift Plan

6,665,681

Time Not Worked

17,092,919

Training

1,015,461

Union

1,750,317

Variable and Misc. Pay

19,603,354

Variable Pay

1,763,006

Weekly

108,286

Workers Comp.

654,745

 

$ 372,174,175

 

(b) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

Advertising

3,601

Agency

163

Consultant

21,055

FAS 112

2,061

Fleet Leasing

32

Fleet Pricing

119,840

Gain Sharing

10,715

General/Other

476,334

Group Life

5,780

Healthcare

50,793

Management

103,098

Monthly

951

OPEB

2,222

Operations

485

Payroll Tax

1,850

Pensions

33,052

Printing and Mail

(5,612)

Rent Non-Real Estate

115,952

Software

20,414

Supervision

(383,920)

Thrift Plan

13,139

Time Not Worked

64,396

Union

248,265

Variable and Misc. Pay

12,133

Workers Comp.

4,622

 

$ 921,421

 

(c) Concept: DueToOrChargedByTheTransactionsWithAssociatedAffiliatedCompanies

FAS 112

768

Fleet Pricing

32,531

Gain Sharing

158

Group Life

1,490

Hardware

498

Healthcare

24,819

Management

128,902

OPEB

9,544

Operations

4,893

Payroll Tax

1,120

Pensions

19,336

Printing and Mail

(4,009)

Supervision

(1,632)

Thrift Plan

4,381

Time Not Worked

18,553

Union

7,464

Variable and Misc. Pay

19,209

Workers Comp.

2,303

 

$ 270,328

 

(d) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies

Advertising

8,022

Consultant

95,135

FAS 112

27,014

Fleet Pricing

145,017

Gain Sharing

121,922

General/Other

363,906

Group Life

16,959

Healthcare

435,831

Management

290,113

Monthly

7

OPEB

178,923

Operations

169

Other Employee Expenses

649

Other Expense

410

Outside Vendor

16,380

Payroll Tax

101,575

Pensions

235,410

Police/Summons

3,387

Printing and Mail

16,935

Supervision

1,196,811

Thrift Plan

104,972

Time Not Worked

560,396

Training

1,290

Union

2,906,775

Variable and Misc. Pay

59,449

Weekly

(88)

Workers Comp.

54,675

 

$ 6,942,044

 

(e) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies

Advertising

7,786

Consultant

39,435

FAS 112

27,917

Fleet Pricing

494,010

Gain Sharing

36,103

General/Other

59,162

Group Life

18,904

Healthcare

424,641

Management

2,292,713

Monthly

3

OPEB

178,499

Other Expense

206

Payroll Tax

11,203

Pensions

218,821

Printing and Mail

9,816

Supervision

1,181,807

Thrift Plan

107,007

Time Not Worked

533,060

Training

270

Union

862,774

Variable and Misc. Pay

300,073

Workers Comp.

59,528

 

$ 6,863,738

 

(f) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies

Consultant

43,000

FAS 112

14,474

Fleet Pricing

93,145

Gain Sharing

65,359

General/Other

59,792

Group Life

9,095

Healthcare

235,081

Management

147,370

Monthly

2

OPEB

96,603

Operations

178

Other Employee Expenses

378

Other Expense

241

Payroll Tax

53,405

Pensions

125,672

Printing and Mail

8,825

Supervision

639,606

Thrift Plan

55,928

Time Not Worked

301,051

Training

2,400

Union

1,560,476

Variable and Misc. Pay

32,410

Weekly

(86)

Workers Comp.

29,202

 

$ 3,573,607

 

(g) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies

Advertising

3,168

Consultant

7,352

FAS 112

8,658

Fleet Pricing

33,313

Gain Sharing

35,505

General/Other

84,574

Group Life

5,502

Hardware

19

Healthcare

139,389

Management

160,104

Monthly

67

OPEB

56,714

Operations

6,890

Other Expense

384

Outside Vendor

4,174

Payroll Tax

358

Pensions

73,742

Printing and Mail

14,124

Supervision

380,126

Thrift Plan

33,396

Time Not Worked

177,951

Union

854,119

Variable and Misc. Pay

28,685

Workers Comp.

17,607

 

$ 2,125,921

 

(h) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies

Advertising

3,168

Consultant

5,754

FAS 112

6,099

Fleet Pricing

33,779

Gain Sharing

25,124

General/Other

48,800

Group Life

3,969

Healthcare

95,650

Management

88,186

Monthly

40

OPEB

39,124

Other Expense

193

Payroll Tax

143

Pensions

50,660

Printing and Mail

10,751

Supervision

264,606

Thrift Plan

23,562

Time Not Worked

121,727

Union

618,195

Variable and Misc. Pay

16,134

Workers Comp.

12,658

 

$ 1,468,322

 

(i) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies

Consultant

775

FAS 112

3,255

Fleet Pricing

10,160

Gain Sharing

12,383

General/Other

34,843

Group Life

2,068

Healthcare

52,157

Management

86,990

Monthly

2

OPEB

21,439

Operations

175

Other Employee Expenses

323

Other Expense

34

Payroll Tax

9,138

Pensions

27,633

Printing and Mail

1,453

Supervision

143,072

Thrift Plan

12,596

Time Not Worked

66,744

Training

2,400

Union

295,038

Variable and Misc. Pay

14,653

Workers Comp.

6,634

 

$ 803,965

 

(j) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies

Advertising

7,786

Consultant

11,808

FAS 112

2,892

Fleet Pricing

51,063

Gain Sharing

5,956

General/Other

16,096

Group Life

1,918

Healthcare

44,858

Management

188,822

Monthly

1

OPEB

18,888

Other Expense

56

Payroll Tax

2,240

Pensions

23,377

Printing and Mail

1,556

Supervision

123,935

Thrift Plan

11,106

Time Not Worked

56,638

Union

142,051

Variable and Misc. Pay

25,434

Workers Comp.

6,070

 

$ 742,551

 

(k) Concept: DueFromOrCreditedByTheTransactionsWithAssociatedAffiliatedCompanies

FAS 112

1,955

Fleet Pricing

17,678

Gain Sharing

8,421

Group Life

1,291

Healthcare

30,285

Management

16,353

OPEB

12,226

Other Employee Expenses

3,038

Payroll Tax

18,722

Pensions

14,543

Printing and Mail

77

Supervision

84,144

Thrift Plan

7,543

Time Not Worked

38,391

Union

208,332

Variable and Misc. Pay

2,534

Workers Comp.

4,102

 

$ 469,635

 

XBRL Instance File
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