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LP&L LPSC Jurisdiction. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, LP&L was granted rate relief with respect to costs associated with Waterford 3 and LP&L's share of capacity and en_ from Grand Gulf 1, subject to certain terms and conditions. With respect to Waterford 3, an increase aggregating $170.9 million over the period 1985-1988, and LP&L agreed to t LP&L was grar permanently absco, and not recover from retail ratepayers, $284 million ofits investment in the unit and to defer I $266 million ofits costs related to the years 1985-1988 to be recovered over approxunately 8.6 years beguunng in April 1988. As of December 31,1993, LP&L's unrecovered deferral balance was $82.5 million. With respect to Grand Gulf 1, LP&L agreed to absorb, and not recover from retail ratepayers,18% ofits 14% share (approxunately 2.52%) of the costs of Grand GulfI capacity and energy. LP&L is allowed to recover, through the fuel adjustment I clause, 4.6 cents per KWH (currently 2.55 cents per KWH through May 1994) for the energy related to the permanently absorbed percentage, with LP&L's permanently absorbed retained percentage to be avadable for sale l to non-affiliated parties, subject to LPSC approval. (See Note 2 of LP&L's Notes to Financial Statements, " Rate and Regulatory Matters - Waterford 3 and Grand Gulf 1." incorporated herein by reference, for further information on LP&L's Grand Gulf I and Waterford 3-related rates.) | LP&L LPSC Jurisdiction. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, LP&L was granted rate relief with respect to costs associated with Waterford 3 and LP&L's share of capacity and en_ from Grand Gulf 1, subject to certain terms and conditions. With respect to Waterford 3, an increase aggregating $170.9 million over the period 1985-1988, and LP&L agreed to t LP&L was grar permanently absco, and not recover from retail ratepayers, $284 million ofits investment in the unit and to defer I $266 million ofits costs related to the years 1985-1988 to be recovered over approxunately 8.6 years beguunng in April 1988. As of December 31,1993, LP&L's unrecovered deferral balance was $82.5 million. With respect to Grand Gulf 1, LP&L agreed to absorb, and not recover from retail ratepayers,18% ofits 14% share (approxunately 2.52%) of the costs of Grand GulfI capacity and energy. LP&L is allowed to recover, through the fuel adjustment I clause, 4.6 cents per KWH (currently 2.55 cents per KWH through May 1994) for the energy related to the permanently absorbed percentage, with LP&L's permanently absorbed retained percentage to be avadable for sale l to non-affiliated parties, subject to LPSC approval. (See Note 2 of LP&L's Notes to Financial Statements, " Rate and Regulatory Matters - Waterford 3 and Grand Gulf 1." incorporated herein by reference, for further information on LP&L's Grand Gulf I and Waterford 3-related rates.) | ||
In a subsequent rate proceedmg, on March 1,1989, the LPSC issued an order providing that, in effect, LP&L was entitled to an approximately S45.9 million annual retail rate increase, but that, in lieu of a rate increase, LP&L would be permitted to retam $188.6 million of the proceeds of a 1988 settlement oflitigation with a gas supplier, and to amortize such proceeds into revenues over a period of approxunately 5.3 years. The amortization of the proceeds will expire in mid-1994 and this source of revenue will no longer be avadable to LP&L. LP&L believes that the amortization has resulted in approximately the same amount of additional net income as an annual rate increase of $45.9 million would have provided over the same period. In connection with this order, LP&L agreed to a five-year base rate freeze scheduled to expire in March 1994 at then current levels subject to certam conditions. (See Note 2 of LP&L's Notes to Financial Statements, " Rate and Regulatory Matters - March 1989 Order." incorporated herein by reference, for further information on the terms of this order.) | In a subsequent rate proceedmg, on March 1,1989, the LPSC issued an order providing that, in effect, LP&L was entitled to an approximately S45.9 million annual retail rate increase, but that, in lieu of a rate increase, LP&L would be permitted to retam $188.6 million of the proceeds of a 1988 settlement oflitigation with a gas supplier, and to amortize such proceeds into revenues over a period of approxunately 5.3 years. The amortization of the proceeds will expire in mid-1994 and this source of revenue will no longer be avadable to LP&L. LP&L believes that the amortization has resulted in approximately the same amount of additional net income as an annual rate increase of $45.9 million would have provided over the same period. In connection with this order, LP&L agreed to a five-year base rate freeze scheduled to expire in March 1994 at then current levels subject to certam conditions. (See Note 2 of LP&L's Notes to Financial Statements, " Rate and Regulatory Matters - March 1989 Order." incorporated herein by reference, for further information on the terms of this order.) | ||
By letter dated July 27,1993, the LPSC requested LP&L to explain its "relatively high cost of debt" compared to other electric utilities subject to LPSC jurisdiction. LP&L responded to the request on August 11,1993. On August 14,1993, the LPSC's consultants acknowledged LP&L's rationale for its cost of debt and suggested that certain aspects of LP&L's cost of debt could be taken up in rate proceedmgs after the expiration of LP&L's rate freeze. On October 7,1993, the LPSC approved a schedule to conduct a review of LP&L's rates and rate structure upon the expiration of the rate freeze in March 1994. | By {{letter dated|date=July 27, 1993|text=letter dated July 27,1993}}, the LPSC requested LP&L to explain its "relatively high cost of debt" compared to other electric utilities subject to LPSC jurisdiction. LP&L responded to the request on August 11,1993. On August 14,1993, the LPSC's consultants acknowledged LP&L's rationale for its cost of debt and suggested that certain aspects of LP&L's cost of debt could be taken up in rate proceedmgs after the expiration of LP&L's rate freeze. On October 7,1993, the LPSC approved a schedule to conduct a review of LP&L's rates and rate structure upon the expiration of the rate freeze in March 1994. | ||
CouncilJurisdiction. Under the Algiers rate settlement entered into with the Council in 1989, LP&L was granted rate relief with respect to its Grand Gulf I and Waterford 3-related costs, subject to certam terms and conditions. LP&L was granted an annual rate increase of $9.5 million that was phased-in over the two-year period begmnmg in Julf 1989, and was permitted to retain $4.2 million (the Council's jurisdictional portion) of the proceeds oflitigation with a gas supplier and to amortize such proceeds plus interest into revenues over the same two-year period. LP&L agreed to absorb and not recover from Algiers retail ratepayers $17 million of fixed costs associated with Grand Gulf I and Waterford 3 incurred prior to the date of the settlement, $5.9 million of its investment in Waterford 3, and 18% of the Algiers portion of LP&L's Grand Gulf 1-related costs incurred after the settlement. However, LP&L is allowed to recover 4.6 cents per KWH or the avoided cost, whichever is higher, for the energy related to the permanendy absorbed percentage through the fuel adjustment clause, with the permanently absorbed percentage to be available for sale to non-affiliated parties, subject to the Council's right of first refusal. | CouncilJurisdiction. Under the Algiers rate settlement entered into with the Council in 1989, LP&L was granted rate relief with respect to its Grand Gulf I and Waterford 3-related costs, subject to certam terms and conditions. LP&L was granted an annual rate increase of $9.5 million that was phased-in over the two-year period begmnmg in Julf 1989, and was permitted to retain $4.2 million (the Council's jurisdictional portion) of the proceeds oflitigation with a gas supplier and to amortize such proceeds plus interest into revenues over the same two-year period. LP&L agreed to absorb and not recover from Algiers retail ratepayers $17 million of fixed costs associated with Grand Gulf I and Waterford 3 incurred prior to the date of the settlement, $5.9 million of its investment in Waterford 3, and 18% of the Algiers portion of LP&L's Grand Gulf 1-related costs incurred after the settlement. However, LP&L is allowed to recover 4.6 cents per KWH or the avoided cost, whichever is higher, for the energy related to the permanendy absorbed percentage through the fuel adjustment clause, with the permanently absorbed percentage to be available for sale to non-affiliated parties, subject to the Council's right of first refusal. | ||
LP&L also agreed to a rate freeze for Algiers customers m.il July 6,1994, except in the case of catastrophic events, changes in federal tax laws, or changes in LP&L's Grand GulfI costs resulting from FERC proceedmgs. | LP&L also agreed to a rate freeze for Algiers customers m.il July 6,1994, except in the case of catastrophic events, changes in federal tax laws, or changes in LP&L's Grand GulfI costs resulting from FERC proceedmgs. | ||
Latest revision as of 17:18, 27 September 2022
| ML20073C963 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 12/31/1993 |
| From: | Natreon Jordan, Mckamy W, Thomas H SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION |
| To: | |
| Shared Package | |
| ML20073C960 | List: |
| References | |
| NUDOCS 9409260262 | |
| Download: ML20073C963 (585) | |
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h.spi E W!c mkamytr. Creative solutions are developed by creative people working together
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" ! '"-@ k. g SMEPA's long range goals of positioning for the future through established h.,.f$h.
s strategic planr.ing have allowed it to mature with a degree of stability in fj j- everv operating area throughout its organization. The stabilization of
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'ev. j operating costs, refinancing opportunities, and a dedicated work force i> 1 [ J continue to influence rate stability and services during a growth period f A of SMEPA's history.-
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xn I)uring a period of rapid change as a result of regulations. new philoso-L O/Ih$$n.
phies, and external forces which impact the industry, only the best will a
excel. South Mississippi Electric Power Association, through its employees.
I has positioned itself well to meet these cha!!enges with dedication and s
devotion to its goal of meeting members' needs with at-cost services. The 1993 Annual Report reflects this success.
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SMEPA's lioard of Directors suffered a loss with the death of long-time Director and t *g W >
officer Naif Jordan. Mr. Naif, as he was affectionately called was Singing River EPNs [ M {@g7 "
@i Yl representative to SMEPA's Board to which he was elected m 1981Ile held the office .8 k (( /
of vice president from 1986 until his death in february.
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- l Mr. Naif became a director of Singing River EPA in 1947 and president in 1973-a l" &(4 position also held until his death.
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With more than 46 years' association with Singing River EPA, Mr. Naif created , , ',-
an indisputable place in the history of rural electnfication. Jack Ware, Singing 3 Riser's General Manager, stated that Mr. Naif " believed rural people had just as much
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right to electricity as the cities. and he fought for it. lie was a man who followed gg >g l
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through on what he believed in, and Jackson County benefited from it." , 6 Mr. Naif lived in Ocean Springs and is survived by his wife of sixty years,Jessie, L5 s
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John K. Keyes concluded 26 years as general counsel for the Association at the .- 'y.g , , ; C 'ey w
j february 1993 meeting of the lloard of Directors. Mr. Keyes,71 very capably fulfilled jj i
his duties during his tenure as lloard attorney. Named as his replacement was James N Compton.
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[h 7~ , 1C, 7-Mr. Keyes graduated from the University of Mississippi School of 1.aw in 1948. In R n M 3 .c >ag addition to his private practice. Mr. Keyes is general counsel for the City of Collins.
In february, he was recognized by Colleagues for outstanding legal ability and 1^
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devotion to the public and the profession and was enrolled as a Fellow of the .
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Jim Compton has been affiliated with SMEPNs Board since 1985 lie is a 1976
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graduate of the University of Mississippi School of Law and practices with the firm ^'
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l of Compton.Crowell & llewitt in Biloxl. fP" ^ d; The Association is fortunate to have had its legal matters handled by very able p W -
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, 'l he ',3 Q* -y' Mr. Compton is thefourlb allarneyfor the Associatiord Ikarc ofIFrectors. Emn Ford l hecame Ibefirst allorney trith incorporation in lil, be remainal aclire until bis i resignation in 1957 From 195X to 1967 David ll"ekh uas hyal counsel , , cj, - Jim cuff 1p100 i i *' m i ll r 3 JD , ) 1
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* }j Reorganization resuhed in division of the former Engineering. Construction and Maintenance Department into the Engineering Department and the Transmission
.3 M Department. Veteran SMEPA employees were named as Managers.
s *J Terry Lee, forraer Director of Planning and Protection, was named Manager y q ' of Engineering. The Engineering Department encompasses design engineering y (transmission and substation design). communication applications, substation $y q maintenance, transmission system planning, and the application and maintenance
> of protective relaying and metering equipment
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. ; r - - 0 Jerry Pierce has been a SMEPA employee for 3 years. As Manager of Trans-7 W j mission, he will be responsible for coordination of transmission line construction-0 line routing, line surveying. right-of-way clearing, material procurement, and line
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.j, construction-using SMEPA and contract personnel. Transmission Department
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, j personnel also oversee maintenance of SMEPA s transmission lines (right-of-way flJ reclearing, aerial patrolling, danger tree removal. and structural inspections)
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h 1.431 mi. Ime; 6100 meters !; , F , H, h M E. . V ii '. Ittta EPA.Greenwml '~'\ f 5.214 mt hoe. 2L341 meters I p-V L i Twm County EPA. Hollandale [{p . ,p 2.I'? nu. Ime 11. 38 meters Yazoo Valle) EPA. YmsCityh 2.623 mi. hne: 8535 meters . " g > i t b T Southern Pme EPiTaylorsvlHi O
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/ Grand Gulf Huclear itation ,y SMIPR Headquarters Benndale Unit 1.ocation: Hattiesburg (Forrest Co.) (; ' Commercial Operationzl969 (p.. y p k (10% fndivided Interest in%l'Employees:112 Commercial Operation: 1985 nit 1) Location: George County Location: Port Gibson (Claiborne Co.) Capacity; 16MW SMEPA 13 fortunate to have both of its [
Capacity (In1): 15MW piwer plants hicated approximately Fuel: Natural Gas ; , fuel Nuclear fifteen miles from headquarters-Plant Employees 1 [ Morrow to the southwest and Plant The tw o combustion turbines, Paulding and { SMEPA counts one employee among Moselle to the northeast. Energy from Benndale, are nnmanned stations remotely ' Entergy's Lun0+ who work at the both stations is dispatched from SMEPNs operated by SMEPNs Contr,0! Center located ? ..,s nuclear site Joe Czaika is the Asso- Control Center in flattiesburg. at the headquarters facility. Personnel fromh Y N ciation's Nuclear Specialist. GGNS is Plant Moselle perform maihtenance on the? a3j hicated approximately 16 miles from two units. %- N SMEPNs headquarters. ./ Moselle Generating Station in MS both units w$re ruit to support , Commercial Operation 1970 load demand during.luly dnd August as a !' ' E Iocation: Jones County result of recordbreaking sdmmer load-
- 1) 11. D. Morrotu. Sr.. Generating Capacity: 177MW cond@ ins Otherwise. the imits \ vere plad , y Station fuel: Natural Gas / Fuel Oil in service for test purposed to assurd "
E Commercial Operation: 19~8 Employees. 28 availability and reliabihtyh ., Location: 1.amar Count y N
. Benndale production: 1.017 MWHJ Capacit y: 400MW .- Paulding Unit
') Pauldmg: 206 MWil [ ,
Fuel Bituminous Coal Commercial Operation: 1972 (Compare 172 and 94 respectively, for '92)} ' n Employees: 93 I Location. Jasper County fj Capacit y: 2nMW b > U Fuel Diesci Fucif Natural Gas { L.
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Generation The " normal" weather year that Mississippians did not experience j a j MF ' j in '91 and '92 finally occurred this year, resulting in new peak-hour demands l [ d that were established for SMEPA-generated loads. A new peak-hour load of 921 MW was established,0.8% above the historic peak set in 1990. Kilowatt-
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1 hour sales were also at an all-time high,7.8% ahead of 1992. a y lioth Morrow units were operated throughout the year except during 4 # l January, March, and April, when single-unit operation was observed. Annual
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net generation amounted to 2.176,638 MWlI-37% above 1992 production and I
- i 7.g the second highest annual output recorded for the station. j
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j Records for continuous operation were set on each Morrow umt, with m y Unit I reaching 209 days and linit 2 reaching 21i days. A new record for wN Y '- s nhm mMwe oph m & sd M M 4% (xceeding the m q > y /m . h . A m;6 7 fM prior record by 76 days.
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I . e Net Moselle generation was 374,324 MWil,2% less than 1992 production e ' and the lowest since 1988. The decline in output can be attributed to a number
- .- h ny N, sJp gg cft, ,,,g, ;>MM j: j ' ffW;gJ ; pyg 4l of factors, including high ava' lability of the Morrow and Grand Gulf units; an l ,
j rr n y "' increase in fuel price during much of the year; and the availability of energy
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from the grid at economically attractive price levels. Only during the latter W,,y.7,y [ = . half of July and the entire month of August were <til three Moselle units
.. . wi iTlanas Ezelle.Ma hanic in operated simultaneously to meet demand,
! T Plam Morrow's Raik ar Z Maintenants Shop, nvets an
!," 0 automatic kiemification tag 1 , onto one e sMEPA s too Plant Moselle Natural gas pricing was erratic for much of the year, with wide ~b . Lenal2 carrying raficars. The l' tags keep track of kach car'.s swings that seemed to match changes in demand. liigher fuel costs adversely I lk $t impacted the economics of operating the Moselle units.
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I)uring a spring outage, a scheduled five-year inspection of the Unit 2 turbine-generator was completed. No significant problems were identified as ncs s
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, #c -py a the preventive maintenance procedures were implemented. The disassembly M.p-mm and reassembly work was performed by Mo3elle personnel, while some of the component repairs were performed in outside repair facilities. ~I, y
The No. 4 high-pressure boiler feedwater heater was replaced on Unit 2 + - as a result of experiencing repeated tube failures-after 23 years of service g; $ The new heater has improved reliability and performance and has reduced q maintenance demand on the unit. - wp Many other projects and preventive maintenance measures continued [ throughout the year. g n
,, y X M Plant Honow Plant Morrow was recognized as the Industry of the Year by g- k, o the I.amar County Board of Economic Development for contributions to .
p excellence in the community. The recognition was a deserved tribute to the 5 l g group of dedicated professionals who operate and maintain the facility and b h!
.ec,mh who are responsible for the ultimate success of the operation. *: ,, ,
t.s . The retaining rings were replaced in the Unit I generator at the g.,,. . MM p i manufacturer's recommendation as a result of an industry-wide problem with ( ( g e$ 'L the material used in the original components. A higher grade material is being F -- w 1 Top Jimnty Tisdate, Planti ' used in the manufacture of replacement rings to avoid the possible initiation Moselle Mechanic' grinds a.3 door from;the Pautdhg n - s of stress corrosion cracking and a potential catastrophic failure of the genera- combustion turbine unitf - before repainng11.5 - tor. Similar modifications will be made on Unit 2 in 1994. Employceifthm Plantf Moselle are respomlble fori s A boiler reliability study was conducted on the superheat section of both maintaimag the Paulding f
. and Benndale gas turNnea Riley boilers. The objective was to provide modifications and repair guideh.neS units t p ,
V which will allow these boilers to have extended life and improved reliability, R . . . nottom: sam short is an : , The study resulted in recommendations for modifications which will be operator f at Plant Morrow." At work iA Morrow's s incorporated in both Morrow units during 1991 control Nm. sam m'ust f , A total of six stainless steel expansion joints were replaced on Unit 1. The ["IiN)'hp$n $ - joints connect the air ducts which deliver combustion air to the furnace and "P""""N N *""'"
- i permit the large ducts to move with boiler expansion. h.
Replacement of the "2 and "3 coal feeders, located in the coalyard. was """""k , . ._.f Natural Na l'sedi4,587,605 MMBtu a essential due to the deterioration of the existing components. SMEPA personnel g,jggg t replaced each feeder without interruption of coal delivery to the boilers. These - rneina iisp33 casonb g , and other repairs have decreased maintenance and established a more reliable F p < w,e conve[knf sysleIn. -
' Coal Siapped 7E594 TansL coal Ised 941333 Tom 3 ,
Fuel od I fd 13$148 GaNond b y
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k a g g; ^ L m3 d ~ Of s . A ( g;' f J G 1 Grand Gulf flas Another Successful Year overall.1993 was another successful 4 ,,, ,
] year for Grand Gulf Nuclear Station. The plant operated continuously from c , .m j before January 1993 until an automatic scram occurred on September 13. The j shutdown terminated the unit's world record run for BWRes at 403 days of
) continuous operation. During the record run, the plant operated at full power except for short duration downpower maneuvers.
Grand Gulf earned its third consecutive rating of T from the Institute of p Nuclear Power Operations, the highest available rating. The achievement is unprecedented for Entergy nuclear plants.
}.[ 7 p.
,y y l(entucky [0al Property Activity continued throughout 1993 on the og Association's eastern Kentucky coal property. Clean coal production amounted
'j to approximately 328.2M tons. As the year ended. Andalex was in the process g
[N9E 4 f u b} of assigning the Lease Agreement to Ikerd-liandy, an east Kentucky coal-mining firm.
%1 -
Y ; Merger Intervention The Entergy/ Gulf States Utility merger,in which SMEPA
, intervened, was approved by all the necessary regulatory agencies in Decem-s- ?
"f y -
7 s ber. Although SMEPA did not prevail in its intervention, SMEPA was able to g negotiate a settlement that will help mitigate the impact of the merger on its m
, -- j operations.
iTopiPlant Morron gg remploytxs Winfortl Cole, M Helper,and Jerry Nebon, power [0ntracts Improve inergy fasts A modified reserve capacity contract Mechaulc, repair a imnd p^ f' spump hom the dewatering with Cajun Electric Power Cooperative went into effect on January 1,1993,
- buttdinglThis is one of
' many ongoing maintenance and a unit power contract went into effect on September 1.1993-hoth with c projects at the Plant.
_ i M improved energy costs. This will result in more energy purchases from Cajun iBottont in the s mer of at competitive prices. These purcnases helped offset higher energy prices in
% records for generation.
fuel usage, and peak the general market brought about by the hot summer weather.
- demand were estaNished on iseveral different occasions.
' s Here. System Dispatcher .
Enaries Evans wrdks from load I0 recasting In-house 1. . .rainmg was received on PROMOD (a production model), and it was used to evaluate options in the mid-term and long-range k i r> 1 al s to him g gte1jwgwrs '",, power markets. SMEPA performed load forecasting in-house, something that (economical sources of previously had been done by a consultant. 7 generation during periods J of highest demand and to M make sure in routal I through SMEPNs transmis- llemate [mergency Backup During the year, a PC-based backup control center sion system.1 4 and necessary communications were installed at Plant Morrow for remote j cmergency backup. g ma /0
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@ 'yw ^ . Heat Pump Program Has Continued Success SMEPNs heat pump program 4 M '* ,
enjoyed continued 3rccess during the year, with an increase of 830 qualified [m @y v.y ,,
. w [
units, thirteen of which were ground-source units. The energy-efficient home px f W. j ' 'nm h,. &g"<.' t . programs of the member cooperatives continued to gain momentum and name ,
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recognition, especially along the Nississippi Gulf Coast. These programs, along l?7y,g 7 with successful promotion of industrial loads, contributed to an improved load T;
- n i;m Rt W :2 my,s A
factor in the area where SMEPA purchases power for its members from ,
% mow p$a,auanw.g# My Mississippi Power Company (MPCo). Ilased on peak-hour load figures, ihe v ..-
annual load factor for the MPCo area customers was 53% up from 49&o in C 9 f 1992. %-
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Demand-side Management SMEPA worked with a member system to convert %
;b-one of the system's petroleum pumping customers to a time-of-use rate in i . "ii january 1994 at two of its large pumping stations. l.oading during peak hours e,gg5 b tr A f was reduced, as was the Association's generation requirements. This and other demand-side management programs will enhance operations and should tend f e 4 b., _%
to control wholesale power costs in the future. nuring c4namston;of thev , ni KV R4fuge tap, m; . j r L vibratorf driver was used J to set thdcaisons for twoT J. Ildvisory Participation South Mississippi Electric Power has participated on the self-suipreing meet).J , u structurep--a 13 Moot-tall t cp technical advisory committee and the advisory hoard of directors for Energy GoAB structure ansi n N ' P foot steependend Rated llomes of Mississippi. The program is mandated by the Energy Policy of rhe enimmin d,J
. . IrrfectlQstraight befored ' %
1992 and m.i .tiated by the State of M. . .ississippi Department of Economic and being driven into thef: ' ' NF < Community Development. ground psinns af dew + l GoAB struchtre the foreground, surrounded.arelyingin[h %y ,E by cuttort plants ready to bM A i*ked ( Ongoing Hetering Projects More remotely accessible meters were installed L7 , ggwy , M - on SMEPNs system, with an anticipated project completion date in 1994, and $ _E wm . now total 143 at 135 sites throughout the Association's system. SMEPNs Meter f[ Technicians built all of the new electronic meter boxes, as well as installed & '
~ ;' s those in the field at 40 sites. I- N'~
Installation of off-system telemetering at four sites in the Mississippi N N {: Power & l.ight Company (MP&L) transmission area was completed. This D k<,. 4
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O!m?,.. additional telemetering will allow hetter estimates of SMEPA's hourly L p W ,1J - 3 ,
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generation requirements in the MP&L area by SMEPA's Contro! Center. y ' N [,> l[ llarris Remote Terminal l' nits were installed at ten locations to v.
<fw; successfully complete the replacement project begun three years ago. p e,.
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M. . 3p ^ , d Second Transmission he tuith AIC (Benndale, MS to McIntosh All A second
, 1 interconnection with Alabama Electric Cooperative ( AEC)lus been accom-a plished with the construction of 52 miles of a 230 KV transmission line, f, " , , $'3 officially known as Line 231. Approximately 26 miles were constructed in 4[4 WE ,' i; Mississippi by SMEPA, with AEC completing the remainder of the line in 4- 4 J Alabama.
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y :Q3j Necessary communications were put into service at the lienndale 230 KV station to accommodate the second transmission tie with AEC. This tie allows g ag SMEPA to begin wheeling an additional 150 MW for AEC effective January 1, Q - d i 1994 44 j A highlight of system protection activity was the determination of settings
, j for new relays and the modification of settings for other area relays.
p [ , SMEPA~s Relay Technicians were responsible for all inter-panel wiring in 4 e" > ( the new 230 KV control building and installation of all wiring modifications v l l l +, D4 ,
! <e in the existing 161 KV control building. A total of 52 relays were calibrated at i n
, I; g fienndale 230 KY.
ONh,'dd Substation Maintenance crews terminated wiring for the new power b ( / h, transformers, gas circuit breakers, and pts. They also completed testing and p .L .
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- checkout of the transformers. pts, and gas circuit breakers.
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SMEPA's Transmission Department was responsible for the material
, "" { { procurement and construction management of the project.
f.)
! N N' Transmission System Planning and Protection The Planning and Protection I Section prepared an addendum to the 1992-1996 Five-year Construction Work 4.
? Mike llammett, Tat hnician.
Plan. This document identifies SMEPA's orojected transmission improvements '
' 7 tests voltages arid;rurrents for five years based on the latest Power Requirements Study. A new transmis-on one otthc new relay pancidocated at the sion loan application was submitted to REA late in the year. The total amount L Denndale Substation For the 1 entire project, more than 11 requested was approximately $21 million.
(mikshf3 ires and cables Nere installed thrtiughout Mt lu!$ngs hensmission lines Designed The Design Engineering Section completed designs of 115 KV transmission lines for Refuge (Twin County EPA), Progress (Magnolia j, s
}
] EPA), and Whitfield to South Iltandon (Southern Pine EPA 1 The Refuge line m u 9 q included the first 115 KV GOAll installed by SMEPA in the MP&I. area. j M y, c
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T . h ' S fransmission lines Constructed and llpgraded During 1993,8.8 miles of 11ew p ' 4'" } , , ~
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5' 115 KV transmission lines were completed and energized: 0.6 miles to serve v Singing River EPA's Fort llayou Substation;1.2 miles to serve Twin County i EPA's Refuge Substation near Greenville, and 7.0 miles to serve Southwest - Mississippi EPA's new substation near Alcorn liniversity. Approximately one mile of the West llattiesburg 69 KV trans- .[ ' mission line was relocated to accommodate the new Turtle Creek Mall. _p Reconductoring of 10.5 miles of the 69 KV transmission line between &*A - T C + llomewood and Morton was accomplished. SMEPA crews began con- 'PW'*WF"E struction of a 5.5-mile project which calls for a 115 KV transmission line to serve Southern Pine EPA's lirandon Substation. # h m f._ d MU y' El k , y* 't ~;W lietu Microtuave link in communications, system design of the new micro-W 1 g %sgStr
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R wave link from the Control Center at headquarters in llattiesburg to South fI g q;e, . [ .[ h , Collins to Magee was completed. This new microwave link will allow retire- i '"".k p ment of obsolete power line carrier links from Moselle to Magee and Moselle un A
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d to South Collins. ;
'J : $' $" -
(k, , Top: In nfor ttAUrst ? jf; time, PMEPA used a onnente J ' / Substation Maintenance The Substation Maintenance crew completed mainte- pote as a replacement on :x ,
- nance on fifty-one 69 KV oil circuit breakers (OCils) at ten substations. One one site, $e ofits pole hadlines.Once swung around to where He to bei ,
P 230 KV OCB and three 161 KV OCIls were also maintained. Maintenance on wouy he M @ the left of 0 _ one 161 KV OCll followed an interrupter failure. The crew also completed load ((r$a a d tap changer inspection and maintenance on the West Waynesboro 230/161 H"3 Mong to ogwate the 1 f KV interconnection transformer. 3 cranci(The pows bottord b ~ 3 ' 4 Infrared surveys were completed on substation facilities belonging to piece weigtimgpas16A00 5Lfe longa'the poundi, . t SMEPA and to Dixie, Pearl River Valley, Twin County, Magnolia, Delta, and top sdction 48-feet,7dm 4 Imunds.)D Southern Pine EPAs. Based on new load projections from member co-ops, t I.. .. .x - the Meter Technicians increased current transformer capabilities at five Panom:This is the a. _rondt , autotransformer.to go in at l member delivery points. They also t librated meters at all 168 SMEPA the henndale 30 Kv! . h Substition. Its shipping i . + wholesale meter points. In addition to the relays calibrated at llenndale weight was appmximately ; 175.00p potmds; thisi as previousiy noted, Relay Technicians calibrated another 734 relays. equirrnent h capable'ofi handling 300 million wattsc? or 75 $ of the total s ; c j Transmission System Maintenance The Association's transmission network [rr "b contains 1.415 miles of transmission lines which are maintained by SMEPA's '""hai in late mote L line crews and/or contract personnel throughout the year. f g.. . b e lN n
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3 - 1 Climbing inspections were performed on 3,M structures by the Association's line crews. SMEPA's crews also completed 767 line maintenance l i work orders, which included replacing or repairing broken crossarms, braces, insulators. guys, damaged conductors, and poles. [Eg :; To hnprme system grounding, SMEPA crews installed gtound rods on
"' " ,[~ ~"g -
633 structures on the system's 69 KV transmission lines. i
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,~ rwa A s w The annual reclearing of 3"o of the transmission system's right-of-way M
- g consisted of reclearing 4,300 line acres. A total of 3.036 danger trees were bl j removed from critical transmission line sections. Some of these danger trees g were identified and compensation made in the previous year.
Ih ' Seasonal vegetation control was performed at 84 line switch locations and stations. Aerial patrol inspections of the entire transmission system l g
,. were performed every three montlis and on an "as-needed' basis. Po!e i 4 1 fjg .. .
treatment and groundline inspections were performed on 1067 poles. j u j 1 4 s Top: jerry Qirpemei.U f Storekeeper, and Roy Ib)lis. [0mputer Information Systems Personnel Offer Solutions The Computer j
, fo o ore luformation Systems (ClS) section responded to more than 3001tequests for Service' from employees and departments in 1993. Section personnel ro ss r rnaintenance invent responded with solutions that ranged from generating minor listings to (Bottomi Training in . designing major updates of on-line systems. A Preventive Maintenance System that computerized all maintenance records and schedules for I r k rr
. j Mosdle persogmd over a equipment at Plant Morrow was installed. and modifications to the general 4: threeday penod. In thh y.phim SMEPA employcis ledger and payroll systems reduced run time on those programs by more
, CarlRSwain and Mark '
, ( Phillips(foreground) slowly than half.
let out the ropes that tower their *vicunf tphe ground
' uhile Terry Clark andj M4ch Cochran (backy (Ontainment Of fringe Benefit [0sts (Onlinues Ccntinuing cost management 1
' gro6nd) prepared Georg Aktgan for his' rescue; initiatives and employee support during 1993 allowed the Association to (A complete its fourth consecutive year without a funding increase in its self- I qg , insured medical plan. Employees played an important role in the program's )
g' j success by carefully purchasing medical services while additional savings were realized from the negotiation of new discounts and mcentives with j
, preferred medical care providers. A computerized claims tracking program 1
, , ft was also implemented to help summarize and analyze the nearly 7.000
- w. 'j claims payments handled by SMEPA staff each year.
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.. s gg 7 %, .. "+lsh c,'w linother Safety Record Reached SMEPA achieved its best safety record ever in F , %..
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terms of accident prevention. Through the combined efforts and commitment of the Association and its employees, the overall number of accidents reached > its lowest level in the last twenty years. Several sections added another twelve months during the year to their already impressive streaks of working without , I. a lost-time accident. These include Corporate Planning and Operations Depart- T # y Y O-ment's Electronics section at 79 months Plant Moselle,77 months; Engineering 3 J* f % Department. 61 months; and Transmission Department,55 months. Nh e aS p_ M3 kk3 pj%
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e- ,,, [nuironmental Issue Addressed SMEPA employees worked closely with the . O' w nMA Association's member-owners and with other state power providers in y addressing the issue of electric and magnetic fields (EMF). EMF task force f C - members conducted in-home readings for consumers and developed presenta- - g ye _ gb 0 tions to share information with employees and the general public. SMEPA also /cp o
. h participated in a series of EMF training sessions which were well-attended by t
r . ,g]M % employees from cooperatites around the state. h . k P' cgs
, w,, 74 c Community Affairs Activities Continue Employees participated throughout Top h5 ant' tours cStinue allj the year in community-oriented activities ranging from Adopt-A-School to the year lround. flere, Kurt a ,
Brautigam,informations , American lleart Association's lleartWalk. Two employee teams competed in the speaalist, points out : .. featute$ of olie Of MorroVS L annual United Way Corporate Challenge; and, as always. there was consider- Tc units'tojapaneset J , businessmenxnd woment !.o able employee response to the Adopt-A-Family campaign conducted during the w ho are students st the-. I' t'nnErsity of Southern ? holiday season. .\hn$ppfs EnglisO t.anguage Institutes < "!
- n. 9 information Services The luformation Services section continued to produce nounhYredd ouN employee newsletters for four member systems. The section also developed an Adoji-a-SSoolers sony Forrest Elememary from > ?
informational video for Coast EPA: generated other member-related brochures [*,jr d e and publications; initiated all SMEPA public and member relations activities; $$g q a a produced internal and external information publications; and successfully iga [ar; hosted a National GMT Communicators' meeting. h;ne Wloyed many yet y assmlation with the f ,_ ~ w a; teachets and students from > M our allopted ghool.7 ( -- ! [ 1 D f v m? v p - 8 t 1 e A f' F $ <
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- 4. S1.8If MillIQ f@ At the end of 1991 SMEPA closed the books upon a year which marked solid financial
. . . e ;.. '
q achievements for the Association as SMEPA booked record sales of more than $293 ; 4
$.gfp} ' 7' , million and net margins of $8.841.370. Total net margins were almost double net margins
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1] of 54.467,904 recorded in 1992. spM.
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TC OMPRR RilDf ? SUMM R Rt. M i m . IIIE R G C$ 001(11/980 ; g Operating margins continued to be positive and contributed $7,604.620 toward total net ,r_ D E USAli5 '
,J N g' t margins in 1993 compared to $1,629,775 for the previous year. !
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Mi , , da The improvement in net margins was largely the result of higher-than-expected l y
, , p4 , temperatures experienced system wide in July and August, coupled with colder-than-l w IIR hl10Rb' HEP'O'Ril uy normal weather in the month of December. Also contributing to the increase in margins W Pg. .f
', ,, h was a reduction in interest expense of more than $1.900.000 compared to the year 1992.
j C 6i q, SMEPA took advantage of the lower interest rate markets and reduced the average cost
'I, ' p]3 of outstanding debt to below eight percent for the first t:me in more than a decade.
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rggtggtr g y Margins would have been even higher but for the adoption of the accrual basis account-sj ing method to account for post-retirement benefits other than pensions. This change li%m . h[h .
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y from the cash basis method occurred w hen SMEPA, in accordance with the provisions of Q'N8 ]$i81iMiRISylffy i@ . M j Financial Accounting Standard No.106 (SFAS 106), adopted the provisions of SFAS 106 L,o ' ( 9 effective January 1,1991 As explained in more detail in the notes to the accompanying l Q e NiihMRRClll$ RR0 N! a , financial statements, SMEPA elected to recognize in 1993 its cumulative accrued obliga- l e P ' y ' Q ,Ril018E!1tRPilRin' g gd tion of $1,561500 for post-retirement benefits other than pensions as permitted by SFAS 'd *
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j No,106. A ,' s t nm g~ ' a. y W ," . f$iliUllil5(DfL , ' ff Energy sales to members in 1993 totaled 5,830,971 megawatt hours. an increase of 6.4% M over energy sales to members in 1992. Gross revenues from such sales totaled $274,175,822 N8 p c, W/ j and represented an increase of approximately $25.767,000 or 10.4% over 1992 sales.
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W gQ "] Sales under SMEPA's long-term contract with non-members decreased slightly to 841908 ['%w s m , i[C . _ ,. i..w., s , j$ megawatt hours from 871955 megawatt hours in 1992. As a result, revenues from such 4tli!5?la ' {lIR NCI Ali sales declined 1.2% to S19.261876. W~ sSililM m,j , lWi$ ? , 3
=
, ; y g',' 4o 'i', {lj Key financial ratios increa. sed substantially. A Times interest Earned Ratio (TIER) of M - 7 E muddaGawadh.4 4 1.15 was achieved in 1993 compared to a 107 ratio the previous year. The debt service of 1993 of W compared with a 1.17 ratio achieved in 1992.
As a result of the higher margins for P)H equities and patronage capital increased significantly to 5.62% of total assets at December 31,1991 compared to the 457% level l of equities and patronage capital at the end of 14)2. 1 l 16'
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s a p 9; y > - 4 Despite a decrease in SMEPA's rate structure effective January L 1993 (SMEPA's sixth consecu- [ Og' ' {y tive annual rate decrease), the average cost of power to SMEPA members increased 1.70 mills u- ~ per kilowatt hour from 45.32 mills in 1992 to 47.02 mills in 1993. Most of the increase in cost E n < - resulted from higher fuel costs. Natural gas prices increased more than 25% for spot purchases; {}l gaC .~uw ,M ' there was a shght increase in the cost of coal; and, as a result of weather-driven high peak 8k888k i demands. SMEPA was forced to utilize higher cost fuels in order to meet system demands. A f TapMah ' significant drop in the cost of nuclear fuel from approximately 7.5 mills per kilowatt hour in '"' ' ' f 1992 to slightly less than 60 mills per kilowatt hour in 1993 helped to mitigate the increased f ;1.000: ; Ms 3e} cost of other fuels. i f ] h Bellars kk rn (g1 ~;m g 'gn; n On October 1,1991 SMEPA repriced $54,814.279 of Federal Financing liank (FFil) advances at {y .f" an aserage rate of 5A3% compared to a previous rate of approximately 10.7%.SMEPA utilized N 4 l f
- internally generated funds to pay the repricing penalty of approximately $4.6510m. This [
- repricing, combined with a repricing effected in 1992. resulted in total repriced FFli note [ (
balances at December 3L 1991 of $97,3S8,392 at an average interest rate of 632%, a reducuan [ i3~ 'i of 5.15% from the rates previously in effect. A further FFil repricing in early January 1994 (see [ ,h ], y'f[.Q' notes to the accompanying financial statements) and other FFB repricing opportunities w hich h [ W[30, are anticipated to take place in the first quarter of 1994 should dramatically lower the cost of lit Generat;on - i - O SMEPA s long-term debt and result in significant savings to SMEPA's members. J , g m .> y , I in October 1991 on behalf of SMEPA, Lamar County, Mississippi issued $27.245,000 of Pollution b E*? l l Control Revenue lionds guaranteed by National Rural Utilities Cooperatit e Finance Corpora- !
' 8It
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] tion (CFC)in order to refund $28.010.000 of 1977 Series Lamar County Pollution Control I i Revenue lionds which were called at par. As a result of the refunding, nominalinterest rates h, s E ~" 7 @ l on the tax exempt bonds were reduced approximately 17% to average 4 37% at December 31, [ 1995 in February 1991 a CFC concurrent loan balance of $801.0n0 was converted from a fixed- [ < rate of 9.75% to a variable rate loan which bore a 4.50% rate at December 3L 1995 s *' i [ e fff i SMEPA received only $2.842.000 in long-term loan advances in 1995 $1,3810n0 was drawn b,
- g ,
! under an REA insured loan while FL454,000 was advanced under a concurrent loan from { L Sales ? '5.3 g l CFC. In December 1991 SMEPA submitted to REA and CFC a loan request in the amount of b Kje e49J
$20.115,000 to prmide financing for capital projects under a three-year work plan. Long- [ Osmbers; term debt (including current maturities) at December 3L 1991 was $691387,554, a decrease f ...
of $10.032.122 from similar balances at the close of 1992. The as erage cost of long-term debt [ decreased from 8.41"o at the end of 1992 to 7.96% at the close of 1991 With additional {y g,
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repricings in 14% SMEPA's average cost of long-term debt will be further reduced. f .g i :n : :e2 ~m sn :n : Total cash and investments inct eased to approximately Sil,42L000 at the close of 1993 Debt F service payments of approximat 'ly $15,6110n0, normally due on December 31, a holiday, were
' N h
made on the first business day of 1991Ilad the hohday fallen on a different date. therefore, b , l cash and investments would have been approximately $35.808.000 which compares to [ F2L990.000 at the end of 1992. SMEPA maintained a strong cash position throughout 1993 and { ;p Jg g ; entered 1994 well positioned to take advantage of further debt repricings and other opportu- [x , , nities requiring cash (h , , klDholesale . . . . . - 47 8P " Amortization of abandonment costs of the Grand Gulf Nuclear Station Unit 11 totaled 6 L 881818 i 1 Us i e ;, l approximately $2.%0,000 in 1995 The unamortized balance of such costs at December 31.1991 145 H E amounted to $80.789.000 Amortization of abandonment costs will continue through the year [p Members" '
~-
2016 in accordance with a predetermined schedule under which the annual write-off will O e 5 Millsi increase approximately 26% per year, p '.lgg$ I !: 'n, 'uc fu ; cu t . n i. ' ( (; -
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s 4 i 1 g
+
ELEHEHTS DE COST I OTAI. SYST131 - Nill.i.S/KWil OF S AI.ES 1993 1992 1991 1990 1989 Production Costs. Purchased Pov er, and Interchanged Power 27.90 26.24 26.14 27.72 28.14 l Transinession O&N1 1.62 1 60 1.70 1.81 1.79 AAG thpense .79 .76 .79 .83 .85 Depreciation and Ainorti/ation 3.57 3.72 3.81 4.10 3 83 Interest t Net) 8 66 9.37 10.34 11.56 12.43 Tases and Other .50 .21 .14 .16 2.10 TOTAI,- MIEl.S/KWil OF S \l.ES 43.04 41.90 42.92 46.1H 49.14 COMP AR AllUE B AL ANCE SHEETS AHD SELECTED ElH AHCI AL H ATIOS [1.000 Dollars) 1993 1992 1991 1990 1989 UTII.lTY PEANT In Scrsice $ 737,175 5 733.882 5 731.832 5 726J)48 5 713.897 Construction Wor k in Piocess 20.213 16.987 7.605 10.468 13.937 757,388 750.869 739.437 736.517 727,834 Depreciation 218.934 199.257 182.675 169.891 147.406 NI:T UTil.lTY Pl. ANT $ 538,454 $ 551,612 $ 556,762 $ 566,625 $ 5N0418 OTilER ASSE'IS Unrecovered Plant Cost 80.789 83.489 86.096 87,984 91,180 Cash and Temporary insestments 51.421 21.990 25.571 38.184 41,755 Insentories 21.604 32.568 28.234 22,349 22,159 Deferred Charges 12.809 7,696 1.932 1.549 1,581 Other 67.555 59.253 60.432 47.255 42.167 TOTAI. O lllER 234,178 204,996 202,265 197,321 19N,842 TOTA 1. ASSETS $ 772,632 5 756,60N $ 759,027 5 763,946 $ 779,270 EQl'ITIES AND 1.lA11l1.111ES lijuities and Patronage Capital 5 43,397 5 34.556 5 30.OS8 $ 27,050 $ 18.348 1.ong-term Debt 674.597 686 045 693,319 705,964 715.338 Other 1.iabilities 54.638 36.007 35.620 30.932 45.584 TOTA:. EQL illLS AND I.l Allli.lTIES $ 772.632 $ 756.60N $ 759,027 $ 763,946 5 779,270 RA'llOS Til R I.15 1.07 1.05 1.13 0.94 DSC 1.24 1.17 1.17 1.25 1.02 1 quity as 9 of Assets 5.62% 4.579 3.969 3.544 2.359 DEllT Eong.terin Debt 5 674.597 5 686.045 $ 693.319 5 705,964 5 715.338 l Current N1aturities 16.791 15.374 14.274 13.312 12.119 Total Debt 5 691.38N $ 701,420 $ 707,593 5 719,277 $ 727,457 Ascrapc Rate 7.964 8419 8859 8.97M 8.984
% llOI.ES Al.E R \TE TO Nil 3111ERS
%Ils/kWil 47.02 45.32 46.12 48.74 48.85
/N
1 C0HP AR ATIVE ! DPER ATlHG STATEMENTS i l 1993 1992 1991 1990 1989 REVENUE Sales of Energy $ 293,439,698 $ 267,897.826 $ 261,907,622 $ 264325,407 $ 251,362,947 Other (107,580) 22.272 231,995 (209.843) (474,686)
'l OTAl, REVENUE $ 293,332,118 $ 267,920,098 $ 262,139,617 $ 264.115,564 $ 250,888,261 EXPENSE Operation Expense:
Pnsluction-Fuel Cost 64,673,847 52.148.821 55.049,192 60,782,368 62,868,651 Other Pnsluction Expenses 15.337,958 13.999.532 12,278.297 13,201,932 12,241,178 Purchased Power 99,571.210 93,881,478 86,613,715 74,296,846 66,361,893 Transmission 9.243,124 H,587.069 8,763,606 8,458,919 7,721,419 Consumer Accounts 65,471 54,931 51,942 40,185 41,798 Sales Expense 131,905 121.332 93,023 83,529 95,612 Administratise & General 4,483,986 4,085,883 4,055,849 3,980,047 3,850,741 Total Operation Expense 193,507,501 172,879,046 166,905,624 160,843.826 153,181.292 , Maintenance Expense: Pmduction 6,635,899 6.723,742 6,079,990 7,268,466 6.641,474 Transmission 1,546,075 1.593.121 1,629,329 1,696,906 1.721,705 General Plant 593,522 568,713 637,168 561,611 470,433 Total Maintenance Expense 8,775,496 8,885,576 8,346,487 9,526,983 8,833,012 Depreciation and Amortization 23.822,453 23,614,585 23,329,781 22,984,653 19,782,095 Taxes 1,120.726 1,031,531 791,058 836,436 765,595 Interest Expense tNet)and Other Deductions 58,501,322 59,879,585 63.603,175 65,182.661 65,801,841 TOTAI, EXPENSE 285,727,498 266,290,323 262,976,125 259,374,559 248,364,435 r OPERATING MARGINS 7,604,620 1,629,775 (836,508) 4,741,005 2,523,826 NON OPERATING MARGINS AND NON-RECURRING ITEMS 1,236,770 2,838,129 3,874,208 3,961.238 (6,729,139) NET MARGINS $ 8,841,390 $ 4,467,904 $ 3,037,700 $ 8,702,243 ($ 4,205Jl3) i
C0HP AR AllVE SUMM ABY 'EHERGY SOURCES RHD S ALES 1993 1992 1991 1990 1989 ENERGY SOURCES - AlWII Generated: Steam 3340,964 2,891.783 3,070,210 3,168,406 3,218,046 ' Other Generation 1,223 266 1,643 3,584 348 3.342,187 2.892,049 3,071,853 3.171,990 3,218,394 Purchased: Direct Purchase 1,768,526 1,854,658 I,629,558 982,926 726,824 florderline -(SEPA) 102,100 103,570 96,148 106,648 87,190 1,870,626 1,958,228 1,725,706 1,089,574 814.014 Interchanged Power - (Net) 1,579,136 1,597,162 1,434,367 1,457,712 1,345,741 TOTAL, ENERGY AVAll.Alli.E FOR SALE- 51WII 6,791,949 6,447,439 6.231,926 5,719,276 5,378,149 l ENERGY sal.FS- hlWil hiemte Coahoma EPA 100,573 89.130 90,591- 88,763 86,583 Coast EPA 863,922 823,751 743,020 731,342 701,440 Delta EPA 399,880 367,242 366,018 367,305 332,986 Dixie EPA 505,394 491,085 - 462.245 436,878 425,274 h1agnolia EPA 420.146 380,878 375,319 378,111 369,027 Pearl River Valley EPA 475,793 440,102 445,467 440,644 427,557 Singing River EPA 880,723 847,965 808,434 786,146 758,895 Southern Pine EPA 1,374,206 1,267,927 1,215,764 1,183.249 1,128,945 Southwest Alississippi EPA 378,546 348,734 336,997 337,582 329,528 Twin County EPA 217,716 204,507 217,231 215,478 184,609 Yamo W! ley EPA 214.072 219,443 232,134 201,657 201,468 TOTAL sal,ES TO AlEhtilERS 5,830,971 5,480,764 5,293,220 5,167,155 4,946,312 Nmunembm 843,908 873,955 828,500 444,355 316,902 TOTAL SALES 6,674,879 6,354,719 6,121,720 5.611,510 5,263,214 TOTAL SYSTEh! DEhlAND - kW (Ililling Demand-Non-concurrent) 1,475,070 1,380,688 1,332,901 1,448,259 1,290,464 2}()
l
]
RUDlIDHS' HEP 0HT i l INDEPENDENT AUDITORS' REPORT Hoard of Directors South Mississippi Electric Power Association llattiesburg, Mississippi We have audited the accompanying balance sheets of South Mississippi Electric Power Association as of December 31,1993 and 1992, and the related state- j ments of net margins and patronage capital and cash flows for the years then ' ended. These financial statements are the responsibility of the Association's management, Our responsibility is to express an opinion on these financial statements based on our audits. We con. seted our audits in accordance with generally accepted auditing standards and the standards for financial audits contained in Government + Auditing Standards, issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain reasonable I assurance about w hether the financial statements are free of material misstate-ment. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial stalement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, i the financial position of South Mississippi Electric Power Association as of December 31,1993 and 1992, and the results of its operations and its cash flows for the y ears then ended in conformity with generally accepted accounting principles. As discussed in Note I i to the financial statements, the Association changed its method of accounting for postretirement benefits other than pensions in 1993. b , 4 February 4,1994 i
't 2/
.. n, .
DALRHCE SHEETS ASSETS I' l j I)ecember 31 1993 1992 El.ECTRIC UTil.ITY Pl. ANT (Notes la, lh, le,2, and 3) in sers ice -- at cost $ 737,174,874 $ 733,881,617 Constiuction work in pmcess 20,212,836 16,987,654 757.387,710 750,869,271 1.ess allow ance for depreciation 218,933,930 199,257,160 538,453,7N0 551,612,11I OTilER ASSElS AND INVESTMENTS Unrecosered plant cost - at cost (Notes Ib and 3) 80.788,773 83,488.841 Insestments in associated organi/ations (Notes 4 and 10) 10,686,369 I I,258.543 Debt service reserse (Note 10) 9,284,377 9,108,431 Deconunissioning trust -at cost (Notes 3 and 10) 2,797,881 2,229,632 Other noncurr,'nt assets 3.670 3,670 103,561,070 106,089,117 CURRENT ASSETS General fund cash and temporary cash equivalent insestments (Notes lj and 10) 51,421.064 21,990,248 Other invested funds (Note 10) 18,002.135 14,038,072 Accounts receivable (including receisables from members of approximately 523,7b9.000 (19931 and $19,631,(NN)l1992l)(no allowance for doubtful accounts deemed necessary) 25,474,229 21,480,255 Insentories (Note id): Coal 7,996,565 18,602.647 Other fuel 769,636 893,199 Materials and supplies 12,837,496 13.072,129 2I.603,697 32,567.975 1 Other 1,307,215 1,134,298 117,80N,340 91.210,848 1 DEITRREI) Cil ARGES tNotes 1c,5, and 8) 12,H08,885 7,695,615 TOTAL. ASSETS $ 772,632,075 $ 756,607,691 See " Notes to l'inancial Statements" 22
B R L A H E E S H E E T S - continued ; I EQUITIES AND I.lAllll.lTIES l l I December 31 1993 1992 EQUITIES (Notes If and 6) Memberships 5 55 $ 55 Donated capital 535,436 535,436 Patronage capital 42,861,587 34.020,217 43.397,078 34,555,708 I ONG-TERM DEllT. excluding current maturities (Notes 8 and 10) 674,596,573 686,045,406 ACCRUED DECOMMISSIONING Ollt.lGATION (Notes th and 3) 2,797,881 2.229,632 DEFERRED CREDITS AND OTIIER I.ONG-TERM 1.lAllII.ITIES (Note 11) 3,890,585 629,322 CURRENT l.lAllli.ITIES Accounts payable 16.002,895 15,823.664 Accrued interest 13,267,011 644.494 Other accrued expenses 1,889,071 1,305,195 Current maturities of long-term debt 16.790,981 15,374,270 47,949,958 33,147,623 COMMITMENTS AND CONTINGENCIES (Notes 3 and 12) t TOTAI. EQUITIES AND 1.lAIllLITIES $ 772,632,075 $ 756,607.691 S1
I l l
.c -
STRIEHEHTS Of HET HRHGlHS RHO PRTH0HRGE C APIT AL
... i 1
Years Ended December 31 1993 1992 OPERATING REVENUE Electric energy revenue $ 293,439,698 $ 267,897,826 Other - net (107.580) 22,272 293.332,118 267,920,098 OPERATING ENPENSES Operation expenses: Fuel 64,673,847 52,148,821 Pnxtuction 15,337,958 13,999,532 Purchased power 99,571,210 93,881,478 Transmission 9,243,124 8,587,069 Administrative and general 4.681362 4,262,146 193,507,501 172,879,(M6 Maintenance ey>enses. Production 6,635,899 6,723,742 Transmission 1,546.075 1.593,121 General 593,522 568,713 8,775,496 8,885,576 ' ikpreciation and amortiration (Notes la and Ib) 23,822,453 23,614,585 Taxes 1,120,726 1,031,531 227,226,176 206,410,738 OPERATING MARGINS ILEFORE INTEREST AND OTIIER DEDUCTIONS 66,105,942 61,509,360 INTEREST AND OTIIER DEDUCTIONS Interest 58,034,571 59,956,732 ) Allowance for funds used during construction (Note tc) (217,591) (385.140) l Other deductions 684,342 307,993 I 58,501,322 59,879,585 OPER STING M ARGINS 7,604,620 1,629,775 . l NON. OPERATING M ARGINS - PRINCIPALI,Y INTEREST INCO\lE 2,799,250 2,838,129 NET M ARGINS IIEFORE CUMFl.ATIVE EFI'ECT OF CilANGE IN ACCOUNTING PRINCIPLE 10,403.870 4,467,904 CUMUI.ATIVE EFFECT OF CilANGE IN ACCOUNTING PRINCIPLE INote 1I) 1,562,500 NET MARGINS 8,841,370 4,867,904 PATRONAGE CAPITAL AT llEGINNING OF YEAR 34,020,217 29,552,313 PATRONAGE CAPITAL AT END OF YEAR $ 42,861,587 $ 34.020,217 See " Notes to Financial Statements" 2/
4 SIRTEMEHIS OF CASH FL0lDS ieurs Ended December 31 1993 1992 CASil l't.OWS l'RONI OPERATING ACTIVI' LIES Net mergins - $ 8,841,370 $ 4,467,9N Adjustments necewary to reconcile net margins to net cash prosided by operating actisities: Cumulatise ef fect of change in accounting principle 1,562,5(x) Depreciation, amortization, and depletion 26,585.612 25,746,149 increase in accounts receivable (3,993.974) (712.593) (increase) decrease in inventories 10.964,278 (4,334,124) Increase in other assets (7,419,534) (7.086.619) Increase (decrease) in accounts payable and other liabilities 2,461,870 (I,162,704) Increase hicercase > in accrued interest payable 12.622.517 (128,881) Increase in accrued deconunissioning payable 568.249 577,429 Net Cash Prosided h,5 Operating Actisities 52,192,888 17J66,561 CASil Fl.0% S l'RO%I INVESTING ACTIVITIES Construction and acquisitions of electric utihty plant ( 8,6M,873 ) (17,142,053) Cost of retirements of electric utility plant (net) 73.650 628,386 Increase in dcbt sers ice reserve (178,589) (4,643,361) Irwrease in decommissioning trust (568,249) (577,232) (lnercase) decrease in other invested funds (3,964,063) 6.953,481 Proceeds from redemption of investment in associated organizations 2,000,000 Purchase of investment in associated organi/ations (I,362,250) Other (65.576) 6.565 Net Cash Used in Insesting Artisitics (12,729,950) (14,774,214) CASil Fl.OWS FRONIl'INANCING ACTIVIIIES Payment of debt: Principal reductions ($ 12,213,810) ($ 14,850,532) Repricing (82,824.270; (45,932,722) iheeds from debt: New indebtedneu 2,842 J0O 8,677,0(X) Repricing 82,I6.',967 45,932,722 i. Net Cash Used in Financing Actisities (10,032,122) (6,173,532) NET INCREASE (DECRI?ASE)IN CASil AND CASil EQUlVALENTS 29,430,816 (3,581,1NS) CASil AND CASil EQUIVALENTS ATllEGINNING Ol'VEAR 21,990,248 25,571,433 CASil AND CASil EQUIVAI.ENTS AT END OF VEAR $ 51,421.064 $ 21,990,248 CASil AND CASil EQUIVALENTS AT END OF VEAR: Cash $ 462,064 $ 140,248 Commercial paper _50.959,1X)0 21,850,(XX)
$ $1,421,064 $ 21,990,248 See " Notes to Financial Statements" SI
4 r HDTES TO FIHRHCIRL ST ATEMEH!S f or the Years Ended December 1993 and 1992 NOTE I-SUNI%IARY 01 SIGNIFICANT ACCOUNTING POI.lCIES South Mississip;
- Ilectric Power Association (SMEPA)is a rural electric cooperathe established under the laws of the State of Mississippi. SMEPA is a generation and transmission cooperatise wSich prosides electric power to elesen owner-members uhich are rucal electric distribution cooperatis es prosiding electric pow er to consumers in certain areas of Mississippi. Financing awistance is prosided by the Uni :d States Department of Agriculture, Rural Electrification Administration (REA). In addition to being subject to regulation b) its ou n gos erning board of directon. SMEPA is subject to certain rules andWulations promulgated for rural electric borrowers by REA. SMEPA maintains its accounting records in accordance with the Federal Energy Regulatory Commission's Chart of Accounts as modified and adopted by REA. As a regulated utility, the methods of alkicating costs and resenue to time periods may ddfer from those principles generally applied by nonregulated companies. The more significant accounting policies are generally described as follows:
- a. Electrie Utility Plant and Depntiation Electric utility plant is stated at cost, w hich includes contract u ork. materiah and direct labor, allow ance for funds used during construction and alhicable userhe.d costs. The cost of electric generating stations and related facilities also includes costs of training and prmluction incurred. less res enue earned, prior to the date of commercial operation.
Depreciation is provided by the straight-line method for utility plant at the following annual composite rates: Nuclear generation plant 2.85 4 Non-nuclear Feneration plant 3.00% to 3.109 Transmiwion plant 2.759 General plant and transportation equipment 2AK)% to 25.00% At the time units of electric utility plant are retired, their original cost and cost of removal, less net sah age value, are charged to the allowance for depreciation. Replacements of electric utility piant intohing less than a designated unit value of property are charged to maintenance enpense. Coal resenes are stated at cost. Depletion is prosided by the units mined method.
- h. Cost of Decommissioning Nuclear Plant and Amortiration of Unrecosered Plant Costs SMEPA's portion of the estimated decommissioning cost of Grand Gulf Nuclear Station iGGNS) Unit I is charged to operating expenses oser the service life of Unit I of approximately 35 > cars.
SMEPA's portion of the unrecovered plant costs of GGNS Unit 11 which has been abandoned, of approximately '80.789,000 and SS3A89.000 at December 31.1993 and 1992. respecthely, is being amortized os er the remaining life of the related debt of approximately 27 years, and approximated $2.678.(XX) and 52.605AXX)in 1993 and 1992. respectisely.
- c. Allow ance for i unds Used During Construction Allow ance for funds used during construction represents the cost of directly related borrowed funds used for construction of the electric pl.mt, w here applicable and an allowance based on the aserage cost of appropriate borrowings when general funds are used to fund construction. The allowance is capitalized as a component of the cost of the electric plant w hile it is under construc-tion.
Capitalization ceases u hen the electric plant is placed in senice, or in the case of electric generating stations anJ rdated facilitie.s at the date of commercial operation. d.'insentorns insentories are statec at average costs.
- c. Deferred Charges Cost of preliminary suncys fo- deselopment of possible methmh to obtain and deliver energy to f ulfill members' future require-ments, including feasibility studies leading to financing necessary plant expenditures, are recorded as deferred charFes If congruction of a project results from such survey s. the deferred charges are transferred to the cost of the facilities. If a preliminary kuncy is abandoned the costs incurred are written off.
Bond issue costs are being amortired by the straight-line method, which does not differ materially from the interest method, over the term of the related debt. The amortitation during the perial of construction is capitalized. 1 2b' - l
Deferred decontamination and decommissioning of past uranium enrichment operations represents SMEPNs ten percent portion of the GGNS assessment pursuant to prosisions of the Energy Pohey Act of 1992 Ithe Actk Tne Act assesses domestic nuclear utilities fees w hich w ill be used to establish a fund into w hich pay ments f rom utilities and the federal govemment uill be placed. The Act requires that regulators treat these assessments as costs of fuel u hen paid. S\lEPA plans to expense these amounts as they are paid os er fifteen years. l f. Patronage Capital The bylaws of SMEPA proside that any excess of resenue os er expenses and accumulated prior year deficits shall tie treated as ads ances of capital by the member patrons and credited to them on the basis of their patronage.
- g. Interchange Power SMEPA records the electrical pow er receis ed or pros ided on an interchange basis at its cost as determined under s arious contractual arrangements.
j h. Employec lienefits Substantially all of SMEPNs employees participate in the National Rural Electric Cooperatise Association (NRECA) retirement programs, which include both a defined benefit pension plan and a defined contribution pension plan. Both plans are quahfied under Section 401 and are tax-exempt under Section 501(a) of the Internal Resenue Code. SMEPA makes annual contributions to the defined benefit pension plan equal to the amounts paid to NRECA for pension expense except for the period since July 1,1987, w hen a moratorium, on contributions, was placed in effect due to reaching full funding limitation. In this multiemployer plan, w hich is as ailable to all member cooperatises of NRECA, the accumulated benefits and plan assets are not determined or alh>cated separately by indisidual employcr. SMEPA had no pension expense for the defined benefit pension plan in 1993 or 1992. SMEPA makes monthly pay ments to NRECA for the benefit of those employees u ho voluntarily participate in the defined contribution pension plan. SMLIPA expenses the payments as they are accrued and such expense amounted to approximately 5505JWN) and 5514JX0 for 1993 and 1992. respectisely. SMEPA also prosides certain health benefits to retired employces and their cligible dependents if the employee meets specified age and senice requirements. Generally, the medical plans pay a stated percentage of medical expenses reduced by deductitles and other cos erages. SMEPA also pros ides life insurance benefits to a closed group of ses en employees w ho retired prior to January 1.1990 (see Note 1 I).
- i. Income Taxes SMEPA is exempt from United States income taxes pursuant to Section 501(cH 12) of the Internal Revenue Code, w hich requires that at least 859 of SMEPA's gross income be deris ed from its members.
J. Cash and Cash Equisalents For purposes of reporting cash nows, all temporary insestments with maturities of three months or less when purchased are deemed to be cash equivalents. s NOTE 2- ELI CTRIC OTil.lTY Pl. ANT Electric utility plant consisted of the following: 1993 1992 Nuclear generation plant 5 395.182,648 5 394.139.724 Non-nuclear generation plant 212,281.628 211.631,114 Transmission plant 78,365,562 76,710.747 Coal properties and preparation plant 24,092.913 24.603.321 Land and land rights 12,723,73 l 12,591,949 I General plant an I transportation equipn tent 14.528.392 !4.204.762 , Electric plant in sen ice 737.174,874 733.881,617 Construction work in process 20.212.836 16.987,654 5 757.387,710 5 750.869.27i NOl E 3-COMMITMENTS Hl:G ARDING GRAND GOLF M' CLEAR STATION SMEPA ow ns a 104 undisided interest in a nuclear generating station know n as " Grand Gulf Nuclear Station"(GGNS L w hich consisted of two 1250-megawatt generating units. Commercial operation for Unit I began on July 1.1985. In September 1985, the construction of Unit 11 was suspended by regulatory authorities. In September 1989, the majority ou ner elected to abandon Unit 11. SMEPNs accumulated cost in Unit 11 w as approximately
$104JWOJH10, including allowance for funds used during construction of approximately 5423NLJX0. After transfers to GGNS G
l i
Unit I ofinventories of apprmimately 52.085,(XX) and property accounts of approximately $605.0(X), apprmimately $91,180.(MK) was transferred to unrecoscred plant cost on the balance sheet during 1989; and approximately $10.130,(X10 was included as a loss in the statement of net margins and patronage capital for 1989. This accounting for Unit 11 has been res iewed and approved by ) REA (see Note ib). l In 1990, SMEPA submitted a fonnat plan to the Nuclear Regulatory Commission (NRC) that demonstrated assurance that sufGeient financial resources would be available at the time it becomes necessary to decommission Unit 1. In addition, SMEPA receised approval from the Internal Resenue Senice to establish a " tax-free" grantor trust as a vehicle to fund the estimated decommissioning costs. SMEPA has contributed to the trust amounts sufficient to fund the estimated accrued decommissioning obligation that eged at December 31,1993 and 1992. SMiiPA estimates that the funding requirement will apprmimate $439 (KX) annually through 2022, the expected date of decommissioning. De estimated funding requirement will be recalculated and adjusted periodically. l NOTE 4 -INVESTMENTS IN ASSOCI ATED ORL ANIZATIONS l Investments in associated organizations are stated at cost and consisted of the following: 1993 1992 National Rural Utilities Cooperatise Finance Corporation ICFC): CFC membership subscription certificates S 6.223.283 5 8.223.283 Cl C loan and guarantee certificates 4.088.7(N) 2,726.450 Other 374.386 308.810
$ 10,686.369 5 11.258.543 Cl C Membership Subscription Certineates bear interest at 5.07c and mature in 2070 through 2080. The Loan and Guarantee Ceriincates bear interest at between 3 09 and 9.8739 and mature in 2007 through 2015.
NOTE 5 - DEFERRED Cil ARGES The following is a summary of amounts recorded as deferred charges as of December 31.1993 and 1992: ; 1993 1992 Unamortiicd premiums on repriced debt S 8,995.646 5 4.619.682 Unamortized debt discount and issuance cost 1,380,919 1,118.060 Past sersice retirement benefit cost 489,471 559.395 Nuclear fuel costs 63.328 30.208 Deterred purchased pow er cost - nes of amortization 1,368.270 l Deferred decontamination and decommissioning of past uranium enrichment operations 1.870.884 Other 8.637
$ 12.808.885 5 7.695.615 j l
Deferred purchased power cost (1992) is the result of a change in the billing cycle of a power supplier. The accelerated charges j were prorated and were being billed to cooperative members in 1993 and 1992 based on megawatt hour usage. NOTE 6 - PATRONAG E CAPITAI, At December 31,1993 and 1992, patronage capital consisted of: , 1993 1992 Assignable S 8.841,370 5 4.467,904 i Assigned to date 39.873.975 35,406.071 48,715.345 39.873.975 less: Retirements to date 5.853.758 5.853.758 5 42.861.587-5 34.020.217 Under the prosisions of the Mortgage Agreement, until the equities and margins equal or exceed forty percent of the total assets of SMEPA, the return to patrons of contributed capital is generally limited to twenty-five percent of the patronage capital or margins received by SMEPA in the prior calendar year. The equities and margins of SMEPA represent 5.629 and 4.579 of the total assets at December 31.1993 and 1992, respectisely. M
NOT E 7 - Sid)RT-TERN! DORROWINGS SMt.PA has a 525JXX)JHW) short-term kne of credit as ailable with Cl C w hich espires September 1994. At December 31,1993 and 1992, SMEPA had no borrow mps again t this line of credit. Interest rates on short-term borrowings with Cl-C as craped approximately J 589 and 5.40'4 for 1993 and 1992, respectis ely. CI C loan and guarantee certificates, w hich are included in other assets and invest-ments. cannot be redeemed so long as the line of credit is in place. NOT E M-II)NG 'IERM delit 1.ong-term debt consisted of the following: 1993 1992 Mortgage notes payable to Federal I inancing Bank (ITih at interest r ites s arying from 4.035'4 to 11.7949, due in quanerly installments through 2020 5 557.087.491 5 565,218,610 t . ~ 2% REA mortgage notes pay able, due in quarterly installments through 2(H)9 23.076.279 24,914,389 59 REA mortgage notes payable, due in quarterly installments through 2015 18,707.872 19.372.703 59 REA mortgage notes payable, due in monthly installments through 2019 10.903.035 9.654,530 Notes pay able to National Bank for Cooperatises at interest rates s arying from 4.859 to 5.58% due in quarterly installments through 2014 2,924.104 3.038.444 Lamar County . Mississippi. Pollution Control Honds: 1977 Series. 5.55910 6.1259. due semi-annually through 2007 28.615JX K) 1978 A Series 5.809 to 6125% due semi-annually through 2008 1,975J N K) 2.060.(KN) 1978 A-1 Series,6.259 due semi-annually through 2008 715JKX) 745JXK) 1993 S Series. 4.159 to 5 AN)E due annually through 2007 27.245JKX) Claiborne County, Missiwippi. Pollution Control Bonds: 1985 G Scr:es. s ariable interest rates (2.409 to 2.759 at December 31,1993). due annually through 2015 46.400JX K) 47JKX).000 Note payable to CI C bearing interest at a s ariable rate. 4.259 at December 31,1993, due in quarterly installments through 2022 2.249.085 801.000 Unamortired net premium on 1993 S Series bonds IN.6X8 691.387.554 701,419,676 1.ess current maturities 16.790.981 15.374.270
$ 674.596.573 5 6s6 045,406 Substantially all assets of SMI:PA wcre pledged as collateral on long-term debt.
Approximate annual maturities (scheduled periodie principal pay ments) of long-term debt for the next fise years are as follows: 1994 516.79 l JX K) 1995 518,375JXX) 1996 519.426JNN) j 1997 520.4703k N) i 1998 522.154.(M N) The unamorti/cd net premium on bonds iwued is being amortired over the remaining lif e of the affected bonds using a method w hich j approximates the interest method. l l At December 31.1993. SMEPA had unadsanced loan commitments from REA of 52.259JXX). SMEPA paid approximately 545.390.01X) and $N).086JKK)in 1993 and 1992, respectis ely, in interest on long-term debt. The reduction in interest paid w as caused primarily by a timing difference in pa3 ment.
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SMEPA is required by mortgage cosenants to maintain certain as erage lesels of interest coserage and annual debt service cmerage. SMEPA was in compliance with such requirements at December 31.1993. 3 in October 1993. SMEPA issued 527.245JNN) of 1993 S Series pollution control bonds. The net proceeds, together with other available f unds. were used to ref und the 528.OlOJKX) outstanding principal of the 1977 Series pollution control bonds in order to permanently lix the interest rate at more famrable rates. SMEPA has agreed with CFC. FFH. and REA to amend certain FH1 promissory notes accomplishing a repricing of approximately 554.814JHN)(1993) and 545.933JXK)(1992). Penalties of approximately $4.653JXX)(1993) and 54,845JXX)(1992) were paid upon execution and will be deferred and amorti/ed oser the remaining hfe of the loans using a method w hich approximates the interest method. Amorti/aiion of the penalties approximated $329JMN)in 1993 and $225JNX)in 1992. In January 1994, SMEPA repticed approximately $120,462JXX) of long-term IFH debt to obtain reduced interest rates ranging from 6.1659 to 6.2484 per annum. The repricing did not alter the original maturity dates which ranged from December 31,2013 to Decem-ber 31. 2015. SMEPA paid a penalty of approsimately 512.569fMN) w hich will be deferred and amorti/ed over the remaining hfe of the loans using a method w hich approximates the interest method NOTE 9 - DEFl:RRI:D CREDITS AND OTilER LONG-TERM LI ABILITIES The following is a summary of deferred credits and other long-term habilities as of December 31,1993 and 1992: 1993 1992 Postretirement benefit obligation 5 1.770.400 Delerred decontamination and decommissioning of past uranium enrichment operations L603.615 Prior service pension benefit cost 516.570 5 629.322 5 3.890.585 5 629.322 NOTE 10- FAIR val UES Of FINANCI AL INSTRUMENTS The following methods and awumptions were used l') SMLPA in estimating its fair ulue disclosures for financial instruments: Cash and cash equivalents: The carrying amount reported in the balance sheet for cash and cash equivalents approximates fair value. Invrarment 3cantire The fair values for marketable debt and equity securities are based on quoted marke: prices and the present value of f-mre cash Dows discounted at a commensurate market rate. long.tenn debr: The fair values of SMEPAilong-term debt are estimated using discounted cash flow analyses based on SMEPNs current incremental borrow ing rates for similar ty pes of borrowing arrangements and rates w hich would be charged by the applicable iwuer w here appropriate. I eYO l
The carrying amounts und apprmimate fair salues of SMEPA's financial instruments at December 31,1993 are as hilowr Carryir.g Drimated Amount Fair Value } Cash and cash equivalents $ 51,421.064 S 51.421JXX) Investments: In associated orFanizations S 10.686.369 $ 6,757,(XN) Debt sersice reserve 9.284.377 10,0203XN) Decommissioning trust 2,797,881 2.976JXX) Other insested funds 18.002,135 18.027JKK)
$ 40.770.762 5 37.780.tKN)
P Carrying Estimated Amotml Fair Value long-term debt, including current maturities: FH1 $ 557,087.49I 5 620,428,(XX) l RiiA 52.687.186 49.6I 6.0(K) Pollution Control llonds 76,439.688 76,323JXX) Other 5.173.189 5.173JXX) S 691,387.554 5 751,540JXX) . The carrying amounts and apprmimate fair values of SMEPA's financial instruments at December 31,1992, are as follows: Carrsing Estimated Amount fair Value Cash and cash equis alents 5 21.990.248 5 21.990.0(X) , i Ins estmente j in associated organizations 5 11.258.543 S 7.890JXX) ! Debt sersice reserve 9,108.431 9.391JXX) i Decommissioning trust 2.229.632 2,301.OlN) Other invested funds 14.038.072 14.254J XX) ! 5 36.634,678 5 33.836.0(X) ! Carrving brimated Ament. Fair Value long-term debt, including current maturities: ITil 5 565.218,610 S 607,530JKX) REA 53.941,622 50,207JXX) Pollution Control llonds 78.420JXK) 79.254JXX) Other 3.839.444 3.834JXX) , 5 701,419.676 5 8(X).825JXK) s There was no material difference between the contract or notional amount and the estimated fair s alue ofloan commitments. The aggregate estimated fair value amounts presented do not represent the underlying value of SMEPA and may not be indicatise of amounts that might ultimate y be realized upon dispmition or settlement of these assets and liabilities. l NOTE II - EM PEOYEE IlWEFITS SMEPA adopted the provisions of Statement of Financial Accounting Standards (SFAS) No.106 " Employers' Accounting for Postretirement Ilenefits Other Than Pensions " changing to the accrual method of accounting for these benefits effective , January 1,1993. This statement requires that the costs of these benefits be recognized in the financial statements throughout the employees' service period. Prior to 1993, postretirement benefit expenses were recognized on a pay-as-you-Fo basis and were not material. As permitted by SFAS 106. SMEPA elected to immediately recognize the cumulative effect of the chanye in accounting for postretirement benefits of apprmimately Si,563JXK) w hich represents the accumulated postretirement benefit obligation ( API 30) existing at January 1.1993. M
SMEPA prosides certain health benefits to retired emplo)ees and their eligible dependents and also provides life insurance benefits to a closed group of sesen emplo)ces uho retired prior to.lanuary 1,1990. The approximate periodic espense for postretirement benefits included the following components: Sersice cost of benefits earned $ 85,(XX) Interest cost on accumulated benefit obligation 123JXX) Total current year expense $ 208JNX) The APilO as of December 31,1993, none of w hich has been funded, comprises the following: Retirees and dependents $ 283JKK) Fully eligible active plan participants 167.200 , Actise participants not yet eligible 1,320.200 ) 51,770A00 Management m; ends to create a separate trust account to fund this obligation beginning in 1994. The weighted aserage discount rate used in determining the APilO was eight percent. The assumed health care cost trend rate of I increase used in measuring the APilO was 12 percent in 1993. declining to six percent by the ) car 2005. The health care cost trend rate of increase assumption has a significant effect on the APilO and periodic expense. A one percent increase in the trend rate for health care costs would hate increased the AP110 by approximately 239 and sersice and interest costs by approximately 259. During 1992, the Financial Accounting Standards lloard issued SFAS No. I12. "Emplo)ers' Accounting for Postemployment flenefits" which is generally effectise for fiscal years beginning after December 15,1993. Management does not believe that the adoption of this pronouncement will materially affect the financial position or results of operations of SMEPA. NOIE 12-COMMITMENTS AND CONTINGENCIES In March 1988, SMEPA began receising its coal supply under an agreement with a new supplier. This agreement provides that certain conditions be met including among other things, minimum annual purchase requirements, and does not require the coal pnxluced for SMEPA's consumption be taken from SMEPA's coal rescrs es, so long as the coal meets the quality requirements of the agree ment. SMEPA has construction commitments for sarious non-nuclear utility projects totaling approximately $5,024,OtX) at December 31,1993, i SMEPA is a defendant in certain litigation incurred in the nc anal course of business. Management, based on adsice of legal counsel is of the opinion that the ultimate resolution of the litigation will not hase a material adverse effect on SMEf A's financial condition. - A eu =rM South Mississippi F Electric Power Association "The Cooperative's Cooperative" Post Office Box 15849 Hattiesburg, Mississippl 39404-5849 601*268 2083 M
I l 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) (El ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCIIANGE ACT OF 1934 [FEEREGUIRED] For the Fiscal Year Ended December 31,1993 i O TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCIIANGE ACT OF 1934 [NO FEEREQUIRED) - For the transition period from to Comunission Registramt, State of lacorporation. I.R.S. Emiployer File Number Address and Telcohone Number Identification No. 1-11299 ENTERGY CORPORATION 13-5550175 (a Delaware corporation) 225 Baronne Street New Orleans, Louisiana 70112 4 Telephone (504) 529-5262 1-10764 ARKANSAS POWER & LIGHT COMPANY 71-0005900 (an Arkansas corporation) 425 West Capitol Avenue,40th Floor ; Little Rock, Arkansas 72201 ; Telephone (501) 377-4000 1-2703 GULF STATES UTILITIES COMPANY 74-0662730 (a Texas corporation) 350 Pine Street Beaumont, Texas 77701 Telephone (409) 838-6631 1-8474 LOUISIANA POWER & LIGHT COMPANY 72-0245590 I v (a Louisiana corporation) 639 Loyola Avenue New Orleans, Louisiana 70112 Telephone (504) 569-4000 , 0-320 MISSISSIPPI POWER & LIGHT COMPANY 64-0205830 i (a Mississippi corporation) 308 East Pearl Street Jackson, Mississippi 39201 , Telephone (601) 969-2311 0-5807 NEW ORLEANS PUBLIC SERVICE INC. 72-0273040 (a Louisiana corporation) j 639 Loyola Avenue . New Orleans, Louisiana 70112 i
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Telephone (504) 569-4000 1-9067 SYSTEM ENERGY RESOURCES,INC. 72-0752777 (an Arkansas corporation) , Echelon One 1340 Echelon Parkway , Jackson, Mississippi 39213 L Telephone (601) 984-9000 - < 1
Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange Registrant Title of Class on Which Resistered Entergy Corporation Common Stock, $0.01 Par Value - 230,310,494 New York Stock Exchange,Inc. Shares outstanding at February 28,1994 Midwest Stock Exchange Incorporated Pacific Stock Exchange Incorporated Arkansas Power & Light Company $2.40 Preferred Stock, Cumulative, $0.01 Par Value New York Stock Exchange,Inc. ($25 Involuntary Liquidation Value) Gulf States Utilities Company Preferred Stock, Cumulative, $100 Par Value:
$4.40 Dividend Series New York Stock Exchange,Inc.
$4.52 Dividend Series New York Stock Exchange,Inc.
$5.08 Dividend Series New York Stock Exchange,Inc.
$8.80 Dividend Series New York Stock Exchange,Inc.
Adjustab!c Rate Series B (Depositary Receipts) New York Stock Exchange,Inc. l Preference Stock, Cumulative, without Par Value New York Stock Exchange,Inc.
$1.75 Dividend Series l Louisiana Power & Light Company 9.68% Preferred Stock, Cumulative, $25 Par Value New York Stock Exchange,Inc.
12.64% Preferred Stock, Cumulative, $25 Par Value New York Stock Exchange,Inc. Securities registered pursuant to Section 12(g) of the Act: l Registrant Title of Class Arkansas Power & Light Company Preferred Stock, Cumulative, $100 Par Value Preferred Stock, Cumulative, S25 Par Value Preferred Stock, Cumulative,50.01 Par Value Louisiana Power & Light Company Preferred Stock, Cumulative, $100 Par Value Preferred Stock, Cumulative, $25 Par Value Mississippi Power & Light Preferred Stock, Cumulative, $100 Par Value Company New Orleans Public Service Inc. Preferred Stock, Cumulative, $100 Par Value 4 3/4% Preferred Stock, Cumulative, $100 Par Value _ _ _ _ _ _ - _ _ _ _ ._ a
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 ; or 15(d) of the Securities Exchange Act of 1934 during the precedmg 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yesi No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Rqrd=+ian S-K is not contained herein, and will not be contamed, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Foan 10-K or any amende to this Form 10-K. [ ] The aggregate market value of Entergy Corporation C-- Stock, 50.01 Par Value, held by , non-affiliates, was $7.7 billion based on the reported last sale price of such stock on the New York Stock Exchange ' on February 28,1994. Entergy Corporation is the sole holder of the common stock of Arkansas Power & Light . Company, Gulf States Utilities Connany, louisiana Power & Light Company, Mississippi Power & Light- . Company, New Orleans Public Service, Inc., and Sym Energy Resources, Inc. DK"0MENTS INCORPORATED BY REFERENCE Portions of the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meetmg of Stockholders, to be held May 6,1994, are incorporated by reference into Part III hereof. l 1 1
TABLE OF CONTENTS Page Number Definitions i Part I Item 1. Business 1 Item 2. Properties 52 Item 3. Legal Proceedmgs 53 Item 4. Submission of Matters to a Vote of Security Holders 53 Pan II Item 5. Market for Registrants' Common Equity and Related Stockholder Matters 54 Item 6. Selected Financial Data 55 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation 55 Item 8. Financial Statements and Supplementary Data 57 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 310 Part lil Item 10. Directors and Executive Officers of the Registrants 310 Item 11. Executive Compensation 324 Item 12. Security Ownership of Cenain Beneficial Owners and Management 338 Item 13. Cenain Relationships and Related Transactions 343 Part IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 345 Experts 346 Signatures 347 Consents of Experts 354 Independent Auditors' Report on Financial Statement Schedulcs 361 Index to Financial Statement Schedules S-1 Exhibit Index E-1 This combined Form 10-K is separately filed by Entergy Corporation, Arkansas Power & Light Company, Gulf States Utilities Company, Louisiana Power & Light Company, Mississippi Power & Light Company, - New Orleans Public Service Inc., and System Energy Resources,Inc. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies. This report (including the material incorporated herein by reference) rnust be rerd in its entirety. No one section of the report deals with all aspects of the subject matter.
DEFINITIONS Certain abbreviations or acronyms used in the text and notes are defined below: Abbreviation or Acronym Term AFUDC Allowance for Funds Used During Construction Algiers 15th Ward of the City of New Orleans, Louisiana ALJ Administrative Law Judge Alliance The Alliance for Affordable Energy,Inc. ANO Arkansas Nuclear One Steam Electric Generating Station (nuclear) ANO2 Unit No. 2 of ANO AP&L Arkansas Power & Light Company APSC Arkansas Public Service Commission Arkansas Datrict Court United States District Court for the Western District of Arkansas Availability Agreement Agreement, dated as of June 21,1974, as amended, among System Energy and AP&L, LP&L, MP&L, and NOPSI, and the assignments thereof Cajun Cajun Electric Power Cooperative, Inc. CapitalFunds Agreement Agreement, dated as of June 21,1974, as amended, between System Energy and Entergy Corporatiot., and the assignments thereof CCLM Customer-Controlled Load Management (a DSM activity utilizing residential time-of-use rates) City of New Orleans or City New Orleans, Louisiana Council Council of the City of New Orleans, Louisiana D.C. Circuit United States Court of Appeals for the District of Columbia Circuit DOE United States Department of Energy DSM Demand-Side Management (Least Cost Plan activities that influence electricity usage by consumers) Eighth Circuit United States Court of Appeals for the Eighth Circuit Energy Act Energy Policy Act of 1992 Entergy or System Entergy Corporation and its various direct and indirect subsidiaries i
DEFINITIONS (Continued) Abbreviation or Acronym Term Entergy Corporation Entergy Corporation, a Delaware corporation, successor to Entergy Corporation, a Florida corporation Entergy Enterprises Entergy Enterprises, Inc. (formerly Electec, Inc.) Entergy Operations Entergy Operations, Inc. Entergy Power Entergy Power, Inc. Entergy Senices Entergy Senices, Inc. EPA Emironmental Protection Agency EWG Exempt Wholesale Generator February 4 Resolution The Resolution (including the Determinations and Order referred to therein) adopted by the Council on February 4,1988, disallowing the recovery by NOPSI of S135 million of previously deferred Grand Gulf I related costs FERC Federal Energy Regulatory Commission Grand Gulf Station Grand Gulf Steam Electric Generating Station (nuclear) Grand Gulf 1 Unit No. I of the Grand Gulf Station Grand Gulf 2 Unit No. 2 of the Grand Gulf Station GSU Gulf States Utilities Company (including wholly owned subsidiaries - Varibus Corporation, GSG&T, Inc, Prudential Oil & Gas, Inc., and Southem Gulf Railway Company) Holding Company Act Public Utility Holding Company Act of 1935, as amended Independence Station Independence Steam Electric Generating Station (coal) Independence 2 Unit No. 2 of the Independence Station IRS Internal Revenue Senice KV Kilovolts KWH Kilowatt-Hour (s) Least Cost Plan Least Cost Integrated Resource Plan (combination of demand- and supply-side resources to be used by Entergy to satisfy electricity demand) ii
i DEFINITIONS (Continued) l Abbrevintion or Acronym Term i LP&L Louisiana Power & Light Company I l LPSC Louisiana Public Service Commission MCF 1,000 cubic feet of gas Merger The combination transaction, consummated on December 31,1993, by which GSU became a subsidiary of Entergy Corporation and Entergy Corporation became a Delaware corporation MP&L Mississippi Power & Light Company MPSC Mississippi Public Service Commission MW Megawatt (s) Nelson Unit 6 Unit No. 6 (coal) of the Nelson Steam Electric Generating Station NISCO Nelson Industrial Steam Company 1986 NOPSI Settlement Settlement, effective March 25,1986, between NOPSI and tne Council regarding NOPSI's Grand Gulf-related rate issues 1991 NOPSI Settlement Settlement, retroactive to October 4,1991, among NOPSI, the Council, and the Alliance that settled certain Grand GulfI prudence issues and certain litigation related to the February 4 Resolution NOPSI New Orleans Public Service Inc. NRC e Nuclear Regulatory Commission PRP Potentially Responsble Party (a person or entity that may be responsible for remediation of emironmental contammation) i PUCT Public Utility Commission of Texas PURPA Public Utility Regulatory Policies Act ; 1 REA Rural Electrification Administration Reallocation Agreement 1981 Agreement, superseded in part by a June 13,1985 decision of FERC, among AP&L, LP&L, MP&L, NOPSI, and System Energy relating to the sale of capacity and energy from the Grand Gulf Station i Ritchie 2 Unit No. 2 of the R. E. Ritchie Steam Electric Generating Station (gas /cil) i iii
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DEFINITIONS (Concluded) ; i Abbreviation or Acronym Itta River Bend River Bend Steam Electric Generstmg Station (nuclear), owned 70% by GSU. ; SEC Securities and Exchange Commission i SFAS Statement of Financial Accounting Standards, promulgated by the Financial ' Accounting Standards Board i SRG&T Sam Rayburn GAT, Inc. l SRMPA Sam Raybum Municipal Power Agency , System Agreement Agreement, effective January 1,1983, as modified, among the System operating ! companies relating to the sharmg of gcroning capacity and other power resources - ! System Energy System Energy Resources, Inc. System Fuels System Fuels,Inc. l System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively ! Unit Power Sales Agreement Agiwn. cat, dated as of June 10,1982, as amended and approved by' FERC,. .; among AP&L, LP&L, MP&L, NOPSI, and System Energy, relatmg to the sale of - ! capacity and energy from System Energy's share of Grand Gulf 1 l Waterford3 Unit No. 3 (nuclear) of the Waterford Steam Electric Generating Station . t i 4 I i
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iv i 5 e ,-, - - + -, , ,,a ,
PARTI Item 1. Business l BUSINESS OF ENTERGY General l Entergy Corporation was originally acorporated under the laws of the State of Florida on May 27,1949. On December 31,1993, in connection with the Merger (see "Enterav Corooration-GSU Merger " below), Entergy Corporation merged with and into Entergy-GSU Holdings, Inc., a Delaware corporation (Holdings), and Holdings was renamed Entergy Corporation. Entergy Corporation is a holding company registered under the Holding Company Act and does not own or operate any physical properties. Entergy Corporation owns all of the outstanding common stock of five retail operating electric utility subsidiaries, AP&L, GSU, LP&L, MP&L, and NOPSI. AP&L was incorporated under the laws of the State of Arkansas in 1926; GSU was incorporated under the laws of the State of Texas in 1925; LP&L and NOPSI were incorporated under the laws of the State of Louisiana in 1974 and 1926, respectively; and MP&L was incorporated under the laws of the State of Mississippi in 1963. As of December 31,1993, these operating companies provided electric service to approximately 2.3 million customers in the States of Arkansas, Louisiana, Mississippi, Missouri, and Texas. In addition, GSU fumished gas senice in the Baton Rouge, Louisiana area, and NOPSI furnished gas senice in the City of New Orleans. GSU's steam products department produces and sells, on an unregulated basis, process steam and by-product electricity supplied from its steam electric extraction plant to a large industrial customer. The business of the System is subject to seasonal fluctuations with the peak period occurring during the third quarter. During 1993, the System's (excluding GSU) electricity sales as a percentage of total System energy sales were: residential - 28.1%; commercial - 19.9%; and industrial - 36.9%. Electric revenues from these sectors as a percentage of total System electric revenues were: 36.3% - residential; 24.4% - commercial; and 27.3% - industrial. Sales to governmental and municipal sectors and to nonaffiliated utilities accounted for the balance of energy sales. During 1993, GSU's electric depanment sales as a percentage of total GSU energy sales were: residential - 25.5%; commercial - 20.3%; and industrial - 50.8%. Electric revenues from these sectors as a percentage of total GSU electric revenues were: 33.5% - residential: 23.8% - commercial; and 37.2% - industrial. Sales to govemmental and municipal sectors and to nonaffiliated utilities accounted for the balance of GSU's energy sales. The System's major industrial customers are in the chemical processing, petroleum refining, paper products, and food products industries. Entergy Corporation also owns all of the outstanding common stock of System Energy, Entergy Senices, Entergy Operations, Entergy Power, and Entergy Enterprises. System Energy is a nuclear generating company that was incorporated under the laws of the State of Arkansas in 1974. System Energy sells the capacity and energy at wholesale from its 90% interest in Grand Gulf I to its only customers, AP&L, LP&L, MP&L, and NOPSI (see " Capital Requirements and Future Financing - Certain System Financial and Suoport Aereements - Unit Power Sales Agreement " below). System Energy has approximately a 78.5% ownership interest and an 11.5% leasehold interest in Grand Gulf 1. Entergy Senices provides general executive and advisory senices, and accounting, I engineering, and other technical senices to certain of the System companies, generally at cost. Entergy Operations is a nuclear management company that operates ANO, River Bend, Waterford 3, and Grand Gulf 1, subject to the owner oversight of AP&L, GSU, LP&L, and System Energy, respectively. Entergy Power, an independent power producer, owns 809 MW of generating capacity and markets its capacity and energy in the wholesale market outside . Arkansas and Missouri and in markets not otherwise presently served by the System. (For further information on regulatory proccedings related to Entergy Power, see " Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters - Entergy Power." below). Entergy Enterprises is a nonutility company that invests in businesses whose produc'.s and activities are of benefit to the System's utility business (see "Coroorate Develcoment." below). Entergy Enterprises also inarkets technical expertise developed by the System companies when it is not required in the System's operatic Entergy Enterprises has received SEC approval to proside senices to certain nonutility companies in the System. In 1992 and 1993, several new Entergy Corporation
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subsidiaries were formed to participate in utility projects located outside the System's retail senice territory, both domestically and in foreign countries (see " Corporate Development." below). AP&L, LP&L, MP&L, and NOPSI own, in ownership percentages of 35%, 33%,19%, and 13%, respectively, all of the common stock of System Fuels, a non-profit subsidiary, that implements and/or maintains certain programs to procure, deliver, and store fuel supplies for the System. I GSU has four wholly-owned subsidiaries: Varibus Corporation, GSG&T, Inc., Southern Gulf Railway Company, and Prudential Oil & Gas, Inc. Varibus Corporation operates intrastate gas pipelines in Louisiana, which a:e used primarily to transport fuel to two of GSU's generating stations, and has marketed computer-aided engineering and drafting technologies and related computer equipment and senices. GSG&T, Inc. owns the Lewis Creek Station, a 532 MW (as of December 31,1993) gas-fired generating plant, which is leased and operated by GSU. Southern Gulf Railway Company will own and operate several miles of rail track being constructed in Louisiana for the purpose of transporting coal for use as a boiler fuel at Nelson Unit 6. Prudential Oil & Gas, Inc., ' which was formerly in the business of exploring, developing, and operating oil and gas properties in Texas and Louisiana, is presently inactive. Enterey Corporation-GSU Mercer On December 31,1993, Entergy Corporation consummated its acquisition of GSU. Entergy Corporation merged with and into Holdings, and Holdings was renamed Entergy Corporation. GSU became a wholly-owned subsidiary of Entergy Corporation and continues to operate as a public utility under the regulation of the PUCT and the LPSC. As consideration to GSU's shareholders, Entergy Corporation paid $250 million in cash and issued 56,667,726 shares ofits common stock at a price of $35.8417 per share, in exchange for outstanding shares of GSU common stock. In addition, $33.5 million of transaction costs were capitalized in connection with the Merger. See " Rate Matters and Regulation - Regulation _Qther Regulation and Litigation." for, information on requests for rehearing and appeals of certain regulatory approvals of the Merger. The information contained in this Form 10-K is filed on behalf of all the registrants of Entergy, including i GSU. Unless otherwise noted, consolidated financial and statistical information contained in this report that is stated as of December 31,1993 (such as assets, liabilities, and property), includes the associated GSU amounts, and consolidated financial and statistical information for periods ending before January 1,1994 (such as revenues, sales, and expenses), does not include GSU amounts; those amounts are presented separately for GSU herein. Certain Industry and System Challences he System's business is affected by various challenges and issues including those that confront the electric utility industry in general. Rese issues and challenges include: an increasingly competitive environment (see "Comoetition." below); 1 i
- compliance with regulatory requirements with respect to nuclear operations (see " Rate Matters and Regulation - Regulation - Regulation of the Nuclear Power Industry." below) and en ironmental ,
matters (see " Rate Matters and Regulation - Regulation - En ironmental Regulation." below); adaptation to structural changes in the electric utility industry, including increased emphasis on least ; cost planning and changes in the regulation of generation and transmission of electricity (see
" Competition - General" and *Comoetitior) - Least Cost Planning," below); ;
i continued cost management (particularly in the area of operation and maintenance costs at nuclear units) to improve financial results and to delay or to mmmuze the need fer rate increase requests in l l l 1
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light of currcnt rate freezes and rate caps at the System operating companies (see " Rate Matters and Regulation - Rate Matters - Retail Rate Matten," below), 1
- integrating GSU into the System's operations and achieving cost savings (see "Enterav Cornoration- l GSU Meraer " above);
- achieving enhanced cammgs in light oflower returns and slow growth in the domestic utility business (see "Comorate Develooment," below); and resolving GSU's major contingencies, including potential wTite-offs and refunds related to River Bend l (see " Rate Matters and Regulation - Rate Matters - Retail Rate Matters - GSU," below) and ;
litigation with Cajun relating to its ownership interest in River Bend (see " Rate Matters and Regulation - Regulation - Other Reculation and Litigation - GSU," below). _qgroorate Development Entergy continues to consider new opportunities to expand its regulated electric utility business, as well as to expand into utility and utility-related businesses that are not regulated by state and local regulatory authorities (nonregulated businesses). Investments in nonregulated businesses are likely to draw upon the System's skills in power generation and customer senice as well as its strengths in the fuels area. Entergy Corporation's investment strategy with respect to nonregulated businesses is to invest in nonregulated business opportunities wherein Entergy Corporation has the potential to earn a greater rate of return compared to its regulated utility operations. Entergy Corporation's nonregulated businesses fall into two broad categories: overseas pwer development and new electro-technologies. Entergy Corporation has made investments in Argentina's electric e.3rgy infrastructure, as described below, and is pursuing additional projects in Central America, South America, South Africa, and Asia. Entergy Corporation will also open offices in Buenos Aires, Argentina and Hong Kong in 1994. In addition, Entergy Corporation is seeking to provide telecommunications senices based upon its experience with interactive conununications systems that allow customers to control energy usage. Entergy Corporation expects to invest approximately $150 million per year in nonregulated businesses. Current investments in nonregulated businesses include the following: (1) Entergy Corporation's subsidiary, Entergy Power Development Corporation (an EWG under the provisions of the Energy Act), through its subsidiary (which is also an EWG) Entergy Richmond Power Corporation, owns a 50% interest in an independent power plant in Richmond, Virginia. He power plant is jointly-owned and operated by the Enron Power Corporation, a developer of independent power projects. The plant owners have a 25-year contract to sell electricity to Virginia Electric & Power Company. Entergy Corporation's investment in the project totals approximately $12.5 million. (2) Entergy Enterprises has a 9.95% equity interest in First Pacific Networks, Inc. (FPN), a communications company, and a license from FPN in connection with utility applications, being jointly developed by Entergy Enterprises and FPN, for FPN's patented communications technology. Entergy En'terprises' investment in FPN is approximately $20.1 million, of which $9.7 million is equity investment. (3) Entergy Enterprises' subsidiary, Entergy Systems and Senice, Inc. (Entergy SASI), holds a 9.95% equity interest in Systems and Senice International, Inc. (SASI), a manufacturer of efficient lighting products. His subsidiary also made a loan to SASI, acquired the business and assets of SASI's ! distribution subsidiary, and entered into an agreement to distribute SASI's products. Entergy Enterprises' initial investment in this business was approximately $11 million (of which $2.3 million is invested in SASI common stock). Entergy Carporation has provided to Entergy SASI $6.0 million in loans, as of j December 31,1993, to fand Entergy SA51's installment sale agreements with its customers. l I i I
I (4) Entergy Ccrporation's subsidiary, Entergy, S.A., panicip:.ted in a consonium with other nonaffiliated companies that acquired a 60% interest in Argentina's Costanera steam electric generating l facility consisting of seven natural gas- and oil-fired generating units, with a total installed capacity of l 1,260 MW. Entergy Corporation's initial investment to acquire its 10% interest in the consortium was l approximately $11 million and its maximum financial obligation currently authorized by the SEC in j connection with this investment is $22.5 million. ! (5) In January 1993, Entergy Corporation, through a new subsidiary, Entergy Argentina, S.A., ; participated in a consortium with other nonaffiliated companies that acquired a 51% interest in a foreign electric distribution company providing senice to Buenos Aires, Argentina. Entergy Corporation's initial investment to acquire its 10% interest in the consortium was approximately $58 million and its maximum ! financial obligation currently authorized by the SEC in connection with this investment is $77.5 million. I 1 (6) In July 1993, Entergy Corporation, through a new subsidiary, Entergy Transener, S.A., participated in a consortium with other nonaffiliated companies that acquired a 65% interest in a foreign transmission system prmiding senice in the country of Argentina. Entergy Corporation's initial inves: ment to acquire its 15% interest in the consortium was $18.5 million. l l In the near term, these investments are likely to have a minimal effect on earmngs; but the possibility exists that they could contribute to future camings growth. However, due to the absence of an allowed rate of return, these investments involve a higher degree of risk. International operations are subject to certain risks that are inherent in conducting business abroad, including possible nationalization or expropriation, price and exchange controls, limitations on foreign l participation in local govemmental entegrises, and other restrictive actions. Changes in the relative value I of currencies take place from time to time and their effects may be favorable or unfavorable on results of ( operations. In addition, there are exchange control restrictions in certain countries relating to repatriation ofeamings. l 4
Selected Data Selected customer and sales data for 1993 are summarized in the following tables: 1993 - Selected Customer Data Customers as of December 31.1993 Area Served Electric Eng a AP&L Portions of State of Arkansas 590,862 - GSU Pottions of the States of Texas and Louisiana 593,975 85,040 LP&L Portions of State of Louisiana 599,991 - MP&L Portions of State of Mississippi 361,692 - NOPSI City of New Orleans, except Algiers, is provided electric service by LP&L 190.613 154.251 System 2.337.133 239.291 1993 - Selected Electric Energy Sales Data System System Excluding AP&L LP&L MP&L NOPSI Energv GSU GSU (Millions of KWH) Sales to retail 15,667 28,115 10,034 5,326 - 59,142 27,493 customers Sales for resale:
- AfIlliates 8,002 112 758 90 7,113 - -
5,948 1,213 670 261 - 8,291 666
- Others
- Sales to steam
- - - - 1.597 products customer - -
29.617 29.440 11.462 5.677 7.113 67.433 29.756 Total Average use per residential 11.206 13.949 12,903 , 11.145 - 12.501 13.905 customer (KWH) NOPSI sold 17,437,292 MCF of natural gas to retail customers in 1993. Revenues from natural gas operations for each of the three years in the period ended December 31,1993, were material for NOPSI, but not material for the System (see " Industry Segments," below, for a description of NOPSI's business segments). GSU sold 6,786,794 MCF of natural gas to retail customers in 1993. Revenues from natural gas operations for each of the three years in the period ended December 31,1993, were not material for GSU. See "Entergy Corporation and Subsidiaries Selected Financial Data - Five-Year Comparison," "AP&L Selected Financial Data - Five-Year Comparison," "GSU Selected Financial Data - Five-Year Comparison,"
"LP&L Selected Financial Data - Five-Year Comparison," "MP&L Selected Financial Data - Five-Year Comparb," "NOPSI Selected Financial Data - Five-Year Comparison," and " System Energy Selected Financial Data - Five-Year Comparison," (which follow each company's notes to financial statements herein) incorporated herein by reference, for funher information with respect to operating statistics of the System and ot AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy, respectively.
5
J l Employees l l As of December 31,1993, Entergy had 16,679 cmployees as follows: Full-time: Entergy Corporation 6 AP&L 2,557 GSU (1) 4,765 LP&L 1,727 MP&L 1,236 NOPSI 716 System Energy - Entergy Operations 3,508 j Entergy Senices (2) 1,986 i Other Subsidiaries 24 Total Full-time 16,525 Part-time 154 j l Total Entergy System 16.679 \ l (1) As of December 31,1993, GSU had not been functionally aligned into Entergy. In December 1993, GSU recorded $17 million for an announced early retirement program in connection with the Merger. Of the 503 employees eligible,369 employees elected to participate in the program. (2) As a result of System realignment of operations along functional lines, certain employees of AP&L, LP&L, MP&L, and NOPSI transferred to Entergy Services during 1993. Competition General. Entergy and the electric utility industry are experiencing increased competitive pressures both in the retail and wholesale markets. He economic, social, and political forces behind these competitive pressures are i numerous and complex. They include legislative and regulatory changes, technolcgical advances, consumer l demands, greater availability of natural gas, environmental needs, and others. Entergy looks at these competitive l pressures both as opportunities to compete for new customers and as risks for loss of customers. On October 24,1992, Congress passed the Energy Act. The Energy Act addresses a wide range of energy l issues and alters the way Entergy and the rest of the electric utility industry will operate in the future. The Energy Act creates exemptions from regulation under the Holding Company Act and creates a class of EWG's consisting of utility affiliates and nonutilities that are owners and operators of facilities for the generation and transmission of power for sales at wholesale. These exemptions offer an incentive for Entergy to pasticipate in the development of wholesale power generation. In addition, the Holding Company Act has been amended to allow utilities to compete on a global scale with foreign entities to own and operate generation, transmission, and distribution facilities. The Energy Act also gives FERC the authority to order investor-owned utilities, including the System operating companies, to transmit power and energy to or for wholesale purchasers and sellers. He law creates the potential for electric utilitics and other power producers to gain increased access to the transmission systems of other entities , to facilitate whalesrJe sales. FERC may also require electric utilities to increase their transmission capacity to provide these senices. The impact of this provision on the System operating companies should be lessened by their joint filing of open access transmission senice tariffs with FERC in 1991 (see " Rate Matters and Regulation - Rate Matters - hiesale Rate Matters," below). The Energy Act also amends PURPA by requiring states to consider (1) new regulatory standards that would require electric utilities to undertake integrated resource planning, and (2) I i
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allowing energy efficiency programs to be at least as profitable as new energy supply options. Entergy is unable to predict the ultimate impact the Energy Act will have on its operations. Wholesale Competition. Entergy has, like other utility systems, generating capacity (most of which is owned by Entergy Power) and energy available for a period of time for sale to other utility systems. The System is in competition with neighboring systems, as well as EWG's, to sell such capacity and energy. Given this competition, the ability of the System to sell this capacity and energy is limited. However, in 1993, the System sold 8,291 million KWH of energy (compared to 7,979 million KWH in 1992) to nonaffiliated utilities. The System also sold 1,234 MW oflong-term capacity (compared to 1,048 MW in 1992) to nonaffiliated utilities outside of the System's senice area. These capacity sales represent 8% of the System's net capability (excluding GSU) at year-end 1993. Under AP&L's and LP&L's Grand Gulf I rate orders, and under GSU's River Bend rate order in Louisiana, a portion of the capacity of Grand Gulf I and River Bend represents capacity that is available for sale, subject to regulatory approval, to nonaffiliated parties. In some cases, profits from such sales must be shared between ratepayers and shareholders. As discussed in " Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters - Open Access Transmission," below, Entergy Power and the System operating companies will be permitted by FERC to make wholesale capacity sales in bulk power markets at rates based primarily upon negotiation and market conditions rather than cost of senice. In order to receive authorization to make such sales, AP&L, LP&L, MP&L, and NOPSI also filed with FERC open access transmission senice tariffs. FERC has approved this filing, subject to certain modifications. Revisions to the tariffs were filed in December 1993 to recognize GSU's inclusion in the Entergy System. When the modified tariffs are made effective, Entergy Power and the System operating companies may engage in sales at market prices. It is anticipated that these tariffs will enable any electric utility (as defined in such tariffs) to use Entergy 's integrated transmission system for the transmission of capacity and energy produced and sold by such electric utility or by third parties. Other similar open access transmission tariffs have also been filed with FERC for several large utility companies or systems and more open access transmission tariffs are anticipated. Concurrently, capacity resources are being developed and used to make wholesale sales from a range of non-traditional sources, including nonutility generators as well as cogenerators and small power producers qualifying under PURPA. These developmcats simultaneously produce increased marketing opportunities for utility systems such as Entergy and expose the System to loss of load or reduced sales revenues due to displacement of System sales by alteniative suppliers with access to the System's prunary areas of senice. Entergy Power, which owns 809 MW of capacity, was formed to compete with other utilities and independent power producers in the bulk power market. As of December 31,1993, Entergy Power has accumulated total losses from operations of $52.5 million. Entergy Power has entered into several long-term contracts for the sale of capacity and associated energy from its resources and has also made short-term capacity and energy sales. Entergy Power continues to actively market its capacity and energy in the bulk power market. (See "Coroorate Develooment." above, for information with respect to a wholly-owned subsidiary of Entergy, Entergy Power Development Corporation, organized as an EWG to compete in the wholesale power market.) Retail Competition. Scheduled increases in the price of power sold by the System pursurt to the operation of phase-in plans (see " Rate Matters and Regulation - Pate matters - Mail Rate Mattm," below) wdl affect the competitiveness of certain classes ofindustrial customers whose costs of prcduction are energy-sensitive. Entergy is constantly working with these customers to address their concerns. It is tie practice of the System operatmg companies to negotiate the renewal of contracts with large industrial customers prior to their expiration. In certain cases (particularly for GSU), contracts or special tariffs that use incentive pricing below total cost have been negotiated with industrial customers to keep these customers on the System. These contracts and tariffs have generally resulted in increased KWH sales at lov/er margins over incremental cost. While the System operating companies anticipate they will be successful in renegotiating such contracts, they cannot assure that they will be successful or that future revenues will not be lost to other forms of generation. To date, through these efforts, Entergy has been largely successful in retaining its industrial load. This competitive challenge could increase. 1 l Cogeneration is generally defmed as the combined production of electricity and steam. Cogenerated power i may be either sold by its produccr to the local utility at its avoided cost under PURPA, or utilized by the cogenerator to displace purchases from the utility. To the extent that cogeneration is used by industrial customers to meet their own power requirements, the System may suffer loss ofindustrial load. Cogenerated power delivered to the System would be purchased at avoided cost, which for a number of years is expected to be equivalent to avoided energy cost, and as such, the cost of these purchases would not impact earnings. To date, only a few cogeneration facilities have been installed in areas served by the System, excluding GSU. The pnmary purpose of , these facilities is to displace power that was purchased from the System. He economic advantage to the customer l is generally due to the customer having waste products that can be used as fuel. Presently, the loss of load to
)
cogeneration and the amount of cogenerated power delivered under PURPA to the System (excluding GSU) is not l significant. He System is prepared to panicipate (subject to regulatory approval) in various phases of the design, l construction, procurement, and ownership of cogeneration facilities. He System has entered into several cogeneration deferral agreements with certain ofits retail customers, which give the System the right of first refusal to participate in any of such customers' cogeneration activities. Such participation could occur in the event there are individual customers whose long-term interests, along with Entergy's, can best be served by installing cogeneration facilities. No such participation has occurred to date, except by GSU. 1 Existing qualifying facilities in the GSU senice territory are estunated to total approximately 2,400 MW's or over 10% of Entergy's total owned and leased generating capability as of December 31,1993. GSU currently believes that no significant load will be lost to cogeneration projects during the next sevem! years; however, GSU is currently negotiating a contract with a large industrial customer, which is scheduled to expire in 1996. If the i contract is not renewed, GSU would lose approximately $40 million in base revenues. l 1 Although GSU has competed in the past for various retail and wholesale customers, the System (excluidng GSU) generally is not in direct competition with privately-owned or municipally-owned electric utilities for retail l sales. However, a few municipalities distribute electricity within their corporate limits and some of these generate all or a portion of their requirements. A number of electric cooperative associations or corporations sen'e a substantial number of retail customers in or adjacent to areas served by the System . Sales of energy by the System to privately- or municipally-owned utilities amounted to approximately 4.6% of total System energy sales in 1993 (excluding GSU). J i Legishtures and regulatory commissions in several states have considered, or are considering, retail wheeling, which is the transmission by an electric utility of energy produced by another entity over the utility's transmission and distribution system to a retail customer in the electric utility's senice territory. Retail wheeling would permit retail customers to elect to purchase electric capacity and/or energy from the electric utility in whose senice area they are located or from any other electric utility or independent power producer. Retad wheeling is i not currently required within the Entergy System service area. See " Rate Matters and Regulation - Regulation - Other Regulation and Litigation." below for information on proceedmgs brought by Cajun seeking transmission I access to certain of GSU's industrial customers. Least Cost Planning. The System continues to pursue least cost planning, also known as integrated I resource planning, in order to compete more effectively in both retail and wholesale markets. Least cost planning is the development of strategies to add resources to meet future electricity demands reliably and at the lowest possible cost. The least cost planning process includes the study of electric supply- and demand-side options. He resultant plan uses demand-side options, such as changing customer consumption patterns, to limit electncity usage during times of peak demand, thus delaying the need for new capacity resources. Least cost planning offers the potential for the System to minimize customer costs, while providing an opportunity to earn a return. On December 1,1992, AP&L, LP&L, MP&L, and NOPSI each filed a Least Cost Plan with its respective regulator, and on July 1,1993, each company filed a near-term revision to such plan. Each Least Cost Plan details the resources that the System intends to use to provide reasonably priced, reliable electric senice to its customers over the next 20 years. Such plan includes 925 MW of DSM resources, such as programs for efficient air
.g.
i conditiorung and heanng, high em% lighting, and CCLM. CCLM is the subject of recent Entergy proposals (filed, or to be filed, by AP&L, LP&L, MPAL, and NOPSI with their respective regulators) requesung the CCLM pilot be withdrawn from consideration in the existmg Imst Cost Plan dockets on the basis of a new proposal by Entergy to undertake t'ae imual pilot development of CCLM at Entergy MaNAa- expense. To date, the Council and the LPSC are the only regulators that have addressed the pinposal. The System expects to spend a total of approxunately $800 nulhon for DSM resources over the next 20 years. Such plan also includes significant resource additions, but does not contemplate construction of any generating facdsnes at new sites. All incremental supply-side resources will come from either delayed reurements or repowerms of existag generatmg units. De System esumates that, over the next 20 years, least cost plannmg, if implemented in accords.r.cc with the tenns of each filed Least Cost Plan, will reduce revenue requirements by appe==?y $2.3 billion ($600 nulhon on a not present value basis), thereby avoiding the need for related rate increase requests Each Imst Cost Plan includes specific actions that the System will undertake pursuant to regulatory approval, includmg the acovery of costs associated with DSM (for further information, see " Rate Matters and Regulaten - Rate Matters - Retad Rate Matters." below). i
)
f l l
j CAPITAL REQUIREMENTS AND FUTU~RE FINANCING l I Construction expenditures for the System are estunated to aggregate S586 million, $560 million, and
$550 million for the years 1994,1995, and 1996, respectively. No significant costs are expected in connection with the System's generating facilities. Actual construction costs may vary from thesc ad=ta beamse of a number factors, including changes in load growth estunates, changes in environmental regulations, modtfications to nucle units to meet regulatory requirements, increasing costs oflabor, equipment and materials, and cost of capital.
Construction expenditures by company (including immaterial environmental expenditures and AFUDC, but 1994-1996 excluding nuctur fuel and the impact of the ice storm that occurred in February 1994) for the period are estimated as follows: 1994 1995 1996 19131 (In Millions) S181 S172 $175 S 528 AP&L 134 128 119 381 GSU 156 143 142 441 LP&L 61 63 63 187 MP&L 26 26 26 78 NOPSI 26 22 23 71 System Energy 2 6 2 10 Entergy Power
$586 $560 S550 $1.696 System In addition to construction expenditure requirements, the estimated amounts required durmg 1994-1996 to meet scheduled long-term debt and preferred stock maturities and cash sinking fund rquirements are: AP&L -
$83 million; GSU - $214 million; LP&L - $158 million; MP&L - $212 million; NOPSI - $80 million; and System Energy - S615 million. A substantial portion of the above capital and refinancing requirements is expected to be satisfied from intemally generated funds and cash on hand supplemented by the issuance of debt and preferred stock. Certain System companies may also continue with the acquisition or refinancing of all, or a portion of, certain outstanding series of preferred stock and long-term debt.
In early February 1994, an ice storm left more than 221,000 Entergy customers without electric power across the System's four-state service area. The storm was the most severe natural disaster ever to affect the Symm, causing damage to transmission and distribution lines, equipment, poles, and facilities in certain areas, particularly in Mississippi. A substantial portion of the related costs, which are estimated to be S110 million -
$140 million, are expected to be capitalized. 'Ihe MPSC acknowledged that there is precedent in Mississippi for recovery of certain costs associated with storms and natural disasters and the restoration of service resulting fro such events. MP&L plans to immediately file for rate recovery of the costs related to the ice storm (see " Rate Matters and Regulation - Rate Matters - Retail Rate Matters -MP&L," below).
Entergy Corporation's current pnmary capital requirements are to periodically invest in, or make loans to, its subsidiaries. Entergy Corporation has SEC authorization to make additional imestments in Entergy Power, Entergy S.A., Entergy Argentina, S.A., Entergy Transener, S.A., Entergy SASI, and FPN. Entergy Corporatio expects to meet these requirements in 1994-1996 with intemally generated funds and cash on hand. Entergy receives fimds through dividend payments from its subsidiaries. Certain restrictions may limit the amount of these distributions. See Entergy Corporation and Subsidiaries' Notes to Consohdated Financial Statements, Note 2,
" Rate and Regulatory Matters" and Note 8, " Commitments and Contingencies," incorporated herein by reference regarding River Bend rate appeals and pending litigation with Cajun. Substantial write-offs or charges result from adverse rulings in these matters could adversely affect GSU's ability to continue to pay dividends.
- to -
Entergy Corporation continues to consider new opportunities to expand its electric energy business, including expansion into related nonregulated businesses. Entergy Corporation expects to invest up to approxunately $150 million per year over the next three years in nonregulated business opportunities. Entergy Corporation may fmance any such expansion with cash on hand. Further, shareholder and/or regulatory approvals may be required for such acquisitions to take place. Also, Entergy Co poration has SEC authorization to repurchase shares of its outstanding common stock. Market conditions and board authorization detemune the amount of repurchases. Entergy Corporation has requested SEC authorization for a $300 million bank line of l credit, the proceeds of which are expected to be used for common stock repurchases and other optional activities. j (For further information on the capital and refmancing requirements, capital resources, and short-term borrowing arrangements of AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy, respectively, refer in each case to AP&L's, GSUs, LP&L's, MP&L's, NOPSI's, and System Energy's " Management's Financial Discussion and Analysis - Liquidity and Capital Resources," Note 4 of AP&L's, GSUs, LP&L's, MP&L's, NOPSPs, and System Energy's Notes to Financial Statements, " Lines of Credit and Related Borrowings," Note 5 of AP&L's and NOPSI's Notes to Financial Statements, " Preferred Stock", Note 5 of GSUs Notes to Financial Statements,
" Preferred, Preference and Common Stock", Note 5 of LP&L's and MP&L's Notes to Financial Statements, " Preferred and Common Stock," Note 6 of AP&L's, GSUs, LP&L's, MP&L's, and NOPSI's and Note 5 of System Energy's Notes to Financial Statements, "Long-Term Debt," and Note 8 of AP&L's, GSUs, LP&L's, MP&L's, and NOPSPs and Note 7 of System Energy's Notes to Financial Statements, " Commitments and Contingencies - Capital Reauirements and Financina." each incorporated herein by reference. For further infonnation concermng Entergy '
Corporation's capital requirements and resources, refer to Entergy Corporation and Subsidiaries' " Management's Financial Discussion and Analysis - Liquidity and Capital Resources," and Note 4 of Entergy Corporation and Subsidiaries' Notes to Consolidated Financial Statements, " Lines of Credit and Related Bo:Towings," incorporated herein by reference. For further information on the subsequent event, see Note 12 of AP&L's and Note 11 of MP&L's Notes to Financial Statements, " Subsequent Event (Unaudited)," incorporated herem by reference.) Certain System Financici and Suonort Agreements Unit Power Sales Agreement. nc Unit Power Sales Agreement allocates capacity and energy from System Energy's 90% ownership and leasehold interest in Grand Gulf 1 (and the costs related thereto) to AP&L (36%), LP&L (14%), MP&L (33%), and NOPSI (17%). AP&L, LP&L, MP&L, and NOPSI pay rates to System Energy for their respective entitlements of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered, so long as Grand Gulf I remams in commercial operation. Payments under the Unit Power Sales Agreement are System Energy's only source of operating revenues. He financial condition of System Energy depends upon the continued commercial operation of Grand Gulf I and upon the receipt of payments from AP&L, LP&L, MP&L, and NOPSL (See " Rate Matters and Regulation - Rate Matters - Wholesale Rate Matters
- System Energy" below for further information with respect to proceedmgs relating to the Unit Power Sales Agreement.)
Availability Agreement. The Availability Agreement was entered into among System Energy and AP&L, LP&L, MP&L, and NOPSI in 1974 in connection with the financing by System Energy of the Grand Gulf Station. He agreement provided that System Energy would join in the agreement among AP&L, LP&L, MP&L, and NOPSI for the sharing of generating capacity and other capacity and energy resources on or before the date on which Grand Gulf I was placed in commer:ial operation. It also provided that System Energy would make available to AP&L, LP&L, MP&L, and NOPSI all capacity and energy available from System Energy's share of the Grand Gulf Station. System Energy and AP&L, LP&L, MP&L, and NOPSI further agreed that if the agreement were termmated, or if any of the parties thereto withdrew from it, then System Energy would enter into a separate agreement with all of such parties or the withdrawing party, as the case may be, with respect to the purchase of capacity and energy on the same terms as if this agreement were still controlling. J
I' AP&L, LP&L, MP&L, and NOPSI also agreed severally to p2y System Energy monthly for the right to receive capacity and energy available from the Grand Gulf Station in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement, or otherwise) would be at least equal to System j Energy's total operstmg expenses for the Grand Gulf Station (including depreciation at a specified rate) and interest charges. l As amended to date, the Availability Agreement provides that: l 1 the obligation of AP&L, LP&L, MP&L, and NOPSI for payments for Grand Gulf I became effective upon commercial operation of Grand Gulf I on July 1,1985; O the sale of capacity and energy generated by the Grand Gulf Station may be governed by a separate power purchase agreement among System Energy and AP&L, LP&L, MP&L, and NOPSI; the September 1989 write-off of System Energy's investment in Grand Gulf 2, amounting to approxunately S900 million, will be amortized for Avadability Agisst purposes over 27 years , rather than in the month the write-off was rWW on System Energy's books; and the allocation percentages under the Availability Aywest are fixed as follows: AP&L - 17.1%; LP&L - 26.9%; MP&L - 31.3%; and NOPSI - 24.7% As noted above, the Unit Power Sales Aywist provides for different allocation percentages for sales of capacity and energy from Grand Gulf 1. However, the allocation percentages under the Avadability Agreement , remain in effect and would govern payments made thereunder in the event of a shortfall of funds avadable to System Energy from other sources, including payments by AP&L, LP&L, MP&L, and NOPSI to System Energy . under the Unit Power Sales Agreement. System Energy has assigned its rights to payments and advances from AP&L, LP&L, MP&L, and NOPSI ; under the Avadability Agisist as security for its first mortgage bonds and reimbursement obligations to certain banks providing the letters of credit in connection with the equity fundmg of the sale and leaseback transactions described under " Sale and T-M Arranaements - System Energy," below. In these assignments, AP&L, , LP&L, MP&L, and NOPSI further agreed that in the event they were prohibited by governmental action from-making payments under the Availability Agrsement (if, for example, FERC reduced or disaliowed such payments , as constituting excessive rates; see the second succ=-% paragraph), they would then make subordmatad advances , to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordmated advances so long as it remained in default under the related indebtedness or in other similar circumstances. Each of the assignment mywi ih relatmg to the Availability Agreement provides that AP&L, LP&L, MP&L, and NOPSI shall make payments directly to System Energy. However, if there is an event.of default, ; AP&L, LP&L, MP&L, and NOPSI shall make those payments directly to the holders of indebtedness secured by , such assignment agreements. The payments shall be made pro rata according to the amount of the respective i obligations secured. ! The obligations of AP&L, LP&L, MP&L, and NOPSI to make payments under the Availability Agreement are subject to receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity mui . energy under the Availability Agreement would require that the Availability Agreement be subnutted to FERC lor approval with respect to the terms of such sale. No filing with FERC has been required because sales of capacity and energy from the Grand Gulf Station are being made under the Unit Power Sales Ayw. ;. Other aspects of D the Availability Agreement, including the obligations of AP&L, LP&L, MP&L, and NOPSI to make subordmated advances, are subject to the jurisdiction of the SEC under the Holding Company Act, which approval has been , obtained. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability j
. . _ - . - .-. - . -= .- -. _ - - -
1 l Agreement, the jurisdictional portions of the Availability Agreemew would be submitted to FERC for approval. (Refer to the second precedmg paragraph.) Amounts that have been received by System Energy under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Consequently, no payments under the Availability l Agreement by AP&L, LP&L, MP&L, and NOPSI have ever been required. If AP&L, LPAL, MPAL, or NOPSI became unable in whole or in part to continue makmg payments to System Energy under the Unit Power Sales Agreement, and System Energy were unable to procure funds from other sources sufHeient to cover any potential j i shortfall between the amount owing under the Availability Agreement and the amount of continuing payments under
.the Unit Power Sales Agreement plus other funds then available to System Energy, LP&L and NOPSI could become subject to claims or demands by System Energy or its creditors for payments or advances under the 4 Availability Agreement or the assignments thereof for the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments. The amount, if any, which these companies would become liable to pay or advance, over and above amounts they would be paying under the Unit Power Sales Agreement for capacity and energy from Grand Gulf 1, would depend on a variety of factors -
(especially the degree of any such shortfall and System Energy's access to other funds). It annnt be predicted j whether any such claims or demands, if made and upheld, could be satisfied. In NOPSI's case, if any such claims ) or demands were upheld, the holders of certain of NOPSfs ouwaAng general and refundmg mortgage bonds could require redemption of their bonds at par. The ability of AP&L, LP&L, MP&L, and NOPSI to sustain payments under the Availability Agreement and the assignments thereofin matenal amounts without substantially equivalent recovery from their customers would be limited by their respective available cash resources and fmancing capabilities at the time. The ability of AP&L, LP&L, MP&L, and NOPSI to recover from their customers payments made under the Availability Agreement, or under the assignments thereof, would depend upon the outcome of regulatory proceedmgs before the state and local regulatory authorities having jurisdiction. In view of the controversies that , arose over the allocation of capacity and energy from Grand Gulf 1 pursuant to the Unit Power Sales Agreement, opposition to recovery would be likely and the outcome of such prMage, should they occur, is not predictable. Reallocation Agreement. On November 18,1981, the SEC authorized LP&L, MP&L, and NOPSI to indemnify AP&L agamst principally its responsibWties ad obligations with respect to the Grand Gulf Station contamed in the Availability Agreement and the assignments thereof. The revised percentages of allocated capacity of System Energy's share of Grand Gulf 1 and Grand Gulf 2 were, respectively: LP&L - 38.57% and 26.23%; i MP&L - 31.63% and 43.97%; and NOPSI - 29.80% and 29.80%. FERC's decision allocating the capacity and l energy of Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI supersedes the Reallocation A>.sst insofar as it ! relates to Grand Gulf 1. However, responsibility for any Grand Gulf 2 amortization amounts (see " Availability Agreement," above) has been allocated to LP&L - 26.23%, MP&L - 43.97%, and NOPSI - 29.80% under the terms of the Reallocation Agreement, The Reallocation Apww. cst does not affect the obligation of AP&L to l System Energy's lenders under the assignae referred to in the fifth precedmg paragraph, and AP&L would be l liable for its share of such amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual obligations. , No payments of any amortization amounts will be required as long as amounts paid to System Energy under the l Unit Power Sales Agreement, together with other funds available to System Energy, exceed amounts required under I the Availability Ayw.ncat, which is expected to be the case for the foreseeable future. l CapitalFundr Agreement. System Energy and Entergy Corporation have entered into the Capital Funds Agreement whereby Entergy Corporation has agreed to supply to System Energy sufHeient capital to (1) mamtain l System Energy's equity capital at an amount equal to a minimum of 35% ofits total capitalization (excluding short- l term debt), and (2) permit the continuation of commercial operation of Grand Gulf I and to pay in full all indebtedness for borrowed money of System Energy when due under any circumstances. l Entergy Corporation has entered into various supplements to the Capital Funds Agreement, cad System Energy has assigned its rights thereunder as security for its first mortgage bonds and reimbursement ob'dgations to i 1 l l i
certain banks providing lertes of credit in connection with the equity fundmg of the sale and leaseback transactions described under " Sale and Leaseback Arrangements - System Encry,"below. Each such supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of the Grand Gulf S;ation may be secured by System Energy's rights under the Capital Funds A, ..;s: on a pro rata basis (except for the Specific Payments, as hereinafter de6ned). In addition, in the particular supplements to the ' Capital Funds Ayw. cst relating to the specific indebtedness being secured, Entergy Corporataan has agreed to
' make cash capital contributions to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). ,
i Except with respect to the Specific Payments, which have been approved by the SEC under the Holding Company Act, the performance by both Entergy Corporation and System Energy of their obligations under the ' Capital Funds A,s.cs:, as supplemented, is subject to the receipt and e-*6H effectivmess of all governmental authorizations necessary to permit such performance, including approval by the SEC under the Holdmg Company ; Act. Each of the supplemental a,s.cs:s provides that Entergy Co.pvidks shall make its payments duectly to System Energy However, if there is an event of default, Entergy Corporation shall make those payments directly to the holders of inwbtedness secured by the supplemental agreements The payments (other than the Specific ! Payments) shall be made pro rata according to the amount of the respective obligations secured by the supplemental l agreements. ; Safe and Leaseback Arrannements LP&L On September 28,1989, LP&L entered into a.. , . a. for the sale and hachack of an ' approximate aggregate 9.3% ownership interest in Waterford 3. LP&L has op6ans to termmate the leases and to repurchase the sold interests in Waterford 3 at certam mtervals dunng the basic terms of the leases. Further, at the end of the terms of the leases, LP&L has options to renev ue leases or to repurchase the interests in Waterford 3. If LP&L does not exercise its options to repurchase the interests in Watertwd 3 on the fifth anmversary , (September 28,1994) of the closing date of the sale and laneehark tracancrman, LP&L will be required to provide , collateral to the owner participants for the equity portion of certam amounts payabic by LPAL under the lease. The required collateral is either a bank letter or letters of credit or the pledgms of new senes of first mortgage bonds issued by LP&L under its first mortgage bond indenture (For further mformation on LP&L's sale and leaseback arrangements, includmg the required mamtenance by LP&L of =raMM capitalization and fixed charge -! coverage ratios, see Note 9 of LP&L's Notes to Financial Statements, " Leases - Waterford 3 Lease Obhgations." incorporated herein by reference.) i System Enerp. On December 28,1988, System Energy etered into arrangements for the sale and .[' leaseback of an 11.5% ownership interest in Grand Gulf 1. System Energy has optmos to termaste the leases and to repurchase the undivided interest in Grand Gulf ; at certam intervals durmg the basic lease term. Further, System Energy has an option at the cod of the basic lease term to renew the leases or to repurchase the undivided : interest in Grand Gulf 1. In connection with the equity fundmg of the sale and haahark arrangenents, letters of - credit are required to be maintamed by System Energy under the leases to secure cernin amounts payable for the - benefit of the equity investors 'Ihe letters of credit currently mamtamed are efEfve until January 15, 1997. . Under the provisions of a reimbursement agreement, dated December 1,1988, as arrded, entered into by System l Energy and various banks in connection with the sale and le==ahack arrangements related to the letters o' credit, i- System Energy has agreed to a nurrber of covenants relatmg to, among other thmgs, the maintenanne of certam capitalization and fixed charge ratios In ecanection with an audit of System Energy by FERC, if a decision of FERC issued on August 4,1992 (August 4 Order) is ultimately s==tamM and imp 1- *% System Energy would need to obtain the consent of certam banks to waive the capitahrmtma and fixed charge coverage covenants for a limited period of time in order to avoid violation of such covenants Systen Energy has obtained the consent. of the : i banks to waive these covenants for the twelve-month period t-d= 5 with the carher of the wnto-off or the first ~ refund, if the August 4 Order is implemented prior to December 31,1994. Absent a waiver, failuit by System ) Energy to perform these covenants could give rise to a draw under the letters of credit and/or an early temunation of the letters of credit, and, if such letters of credit were r.ot replaced in a timely manner, could result in a default
)
l ! I
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; under, or other early termmation of, System Energy's leases. (For further informatma on the potential effects of the August 4 Order on System Energy's financial ew% see Note 2 of System Energy's Notes to Financial Statements, " Rate and Regulatory Matters - FERC Audit." hpo .i.d herem by reference, and for a funher discussion of the provisions of Systan Energy's Reimbursement Agreement, see System Energy's Notes to Financial Statements, Note 6, " Dividend Restrictions" and Note 7, "O_-- . Je--:- and Contagencies - Reunbursement
.W" incorporated herein by reference.) j
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i p 9 b l l I t I l l l
RATE h1ATTERS AND REGULATION RATE MATTERS
'Ihe System operating companies' retail rates are regulated by their respective state and/or local regulatory authorities, as described below, and their rates for wholesale sales (including intrasystem sales pursuant to the System Agreemcat) and interstate transmission of electricity are regulated by FERC. Rates for System Energy's sales of capacity and energy from Grand Gulf I to AP&L, LP&L, MP&L, and NOPSI pursuant to the Unit Power Sales Agreement are also regulated by FERC.
Wholesale Rate Matters GSU. For information, see " Retail Rate Macters - GSU." below and " Regulation - Other Reculation anf, Litization - GSU," below. System Energy. As described above under "Certain System Financial and Sueoort Aarxisnts " System Energy recovers costs related to its interest in Grand Gulf 1 through rates charged to AP&L, LP&L, MP&L, and NOPSI for Grand Gulf I capacity and energy under the Unit Power Sales Agreement. Several proceedings currently pending or recently concluded at FERC affect these rates. In connection with an audit report covering a review of System Energy's books and records for the years ; 1986-1988, on August 4,1992, FERC issued an opinion and order (1) findmg that System Energy overstated its l Grand Gulf I utility plant by approximately 595 million for costs included in utility plant that are related to the l System's income tax allocation procedures, and (2) requiring System Energy to make adjusting accounting entries and refunds, with interest, to AP&L, LP&L, MP&L, and NOPSI within 90 days from the date of the order. System Energy requested a rehearmg of the order, and on October 5,1992, FERC issued an order allowing additional time for its consideration of such request and deferring System Energy's refund obligation until 30 days following issuance of FERC's order on reheanng (For further information on FERC's order and its pamel effect on System Energy's and Entergy's consolidated financial position, see Note 2 of Systent Energy's Notes to Financial Statements and Note 2 of Entergy Corporation and Subsidiaries' Notes to Consolidated Financial Statements, " Rate and Regulatory Matters - FERC Audit." incorporated herein by reference.) In a separate proceeding, on August 24, 1992, FERC instituted an investigation of the justness and reasonableness of certain of Entergy's formula wholesale rates, including System Energy's rates under the Unit Power Sales Agreement. Various regulatory authorities intervened in the proceedmg. On August 2,1993, Entergy and the intervenors settled the proceedmg and agreed that System Energy's rate of return on equity would be reduced from 13% to 11%, and such rate would remam in effect until at least August 1995. Refunds were payable by System Energy with respect to the period from November 2,1992, through the effective date of the settlement. FERC approved the settlement on October 25,1993, and System Energy credited AP&L, LP&L, MP&L, and NOPSI with an agggic of $29.6 million on their October 1993 bills. This matter is now fmal. (See Note 2 of System Energy's Notes to Financial Statements, " Rate and Regulatory Matters - FERC Return on Ecuity Cm," incorporated herein by reference.) Entergy Power. In 1990, authorizations were obtamed from the SEC, FERC, the APSC, and the Public Service Commission of Missouri for Entergy Power to purchase AP&L's interests in Indepmdmm 2 and Ritchie 2, and to begin marketing the capacity and energy from the units in certain wholesale markets. The SEC order approving various aspects of the transaction was appealed by various intervenors in the proceedmg to the D.C. Circuit, which reversed a portion of the order and remanded the case to the SEC for consideration of the effect of the transfers on the System's future costs of replacement generating capacity and fuel. In response to a June 24,1993 SEC order setting a procedural schedule for the filing of further pleadings in the prMng. in July 1993, the Entergy parties filed a post-effective amendment to their application addressing the issues specified in the SEC order. On September 9,1993, the City of New Orleans and the LPSC cach requested a hearing. However, on January 5,1994, the City of New Orleans withdrew from the proceedmg, as agreed in its settlement with NOPSI of various issues related to the Merger. System Agreement. AP&L, LP&L, MP&L, and NOPSI engage in the coordinated planmng, construction, and operation of generation and transmission facilities pursuant to the terms of the System Agreement (described under " Property - Generatinn Stations." below). GSU became a party to the System Agreement upon consummation of the merger of Entergy's and GSUs electric systems, and GSU now participates in this System-wide coordination. For further information, see Note 2 of GSU's Notes to Financial Statements and Note 2 of Entergy Corporation and Subsidiaries' Notes to Consolidated Financial Statements, " Rate and Regulatory Matters - Merzer-Related Rate Agreements." In connection with the Merger, FERC approved certain rate schedule changes to integrate GSU into the System Agreement. Certain commitments were adopted to provide reasonable assurance that the ratepayers of the existing Entergy operating companies will not be allocated higher costs, including, among other things: (1)a tracking mechanism to protect operating companies from certain i-W increases in fuel costs; (2) excluding GSU from the distribution of profits from power sales contracts entered into prior to the Merger; (3) a methodology to estimate the cost of capital in future FERC proceedmgs; and (4) a stipulation that the operatmg companies will be insulated from certain direct effects on capacity equalization payments should GSU, due to a fmdmg of impmdent GSU management prior to the Merger, be required to purchase Cajun's 30% share in River Bend. See
" Regulation - Other Regulation and Litigation," for information on requests for reheanng of FERC's approval.
On August 20, 1990, the City of New Orleans filed a complaint ag-t Entergy Corporation, AP&L, LP&L, MP&L, NOPSI, and System Energy requesting that FERC investigate AP&L's transfer of its interest in Independence 2 and Ritchie 2 to Entergy Power (see "Entergy Power," above) and the effect of the transfer on AP&L, LP&L, MP&L, and NOPSI and their ratepayers. Various parties, including certain of the System's state regulators, intervened in the proceedmg. FERC issued an order on March 19,1991, setting for investigation (!) the question of whether overall billings under the System Agreement will increase as a result of the transfer to Entergy Power, and (2) if so, whether such increased billings reflect prudently incurred costs that may reasonably be charged under the System Agreement. In two separate decisions with respect to these issues, the FERC ALI assigned to the matter ruled on May 14,1992 and October 30,1992, respectively, that there was sufficient evidence to show that overall billings would increase as a result of the transfer, but that the transfer was prudent. On December 15, 1993, FERC issued an opinion declining to address the prudence issue until a future time when replacement capacity has been added or planned aui fmding that, until such time, billings under the System Agreement as affected by the transfer of the two units are reasonable. The Entergy parties and the City of New Orleans each filed a request for rehearing of this order. If FERC's decision were reversed and any refunds were ordered, they would be retroactive to October 19,1990. Open Access Transmission. On August 2,1991, Entergy Services, as agent for AP&L, LP&L, MP&L, NOPSI, and Entergy Power, submitted to FERC (1) proposed tariffs that, subject to certain conditions, would provide to electric utilities "open access" to the System's integrated transmission system, and (2) rate schedules providing for sales of wholesale power at market-based rates. Under FERC policy, sales of power at market-based rates would be permitted only if FERC found, among other things, that Entergy did not have market power over transmission. Permitting "open access" to the System's transmission system helps support such a findmg Various parties, including the Council, the APSC, the MPSC, and the LPSC, intervened in the proceedmg. On March 3,1992, FERC approved the filing, with some modi 6 cations, and on August 7,1992, FERC denied rehearing ofits March 1992 order. On August 24,1992, various parties filed petitions with the D.C. Circuit for review of FERC's 1992 orders, and these petitions have been consolidated. The revised tariffs, submitted by Entergy Services in response to FERC's 1992 orders, were accepted for filing and made effective, subject to further modifications, by order dated April 5,1993. Entergy Services made a further compliance filing on May 5,1993, reflecting these modifications and requesting reconsideration of certain limited matters, which is subject to approval by FERC. On December 31,1993, Entergy Services filed revisions to the transmission service tanff to recognize GSUs inclusion in the Entergy System. These matters are pending.
Retail Rate Matters General. AP&L, LP&L, MP&L, and NOPSI currently have retail rate stmetures sufficient to recover their costs, including costs associated with their allocated shares of capacity and energy from Grand Gulf I under the Unit Power Sales Agreement, and a return on equity. Certain costs related to Grand Gulf 1 (and in LP&L's case, Waterford 3 are being phased-into retail rates over a period of time, in order to avoid the " rate shock" associated with increasing rates to reflect all of such costs at once. The deferral period in which costs are incurrrd but not currently recovered has expired for all of these programs, and AP&L, LP&L, MP&L, and NOPSI are row recovering those costs that were previously deferred. Also, AP&L and LP&L have retamed a portion of tbir shares of Grand Gulf I capacity and GSU is operating under a deregulated asset plan for a portion ofits share c.f River Bend. GSU is involved in several rate proceedmgs involving recovery, among other things, of costs associated with River Bend. Some rate relief has been received, but GSU has been unable to obtain recogrution in rates for a substantial portion ofits River Bend investment. Recovery of certam costs has been disallowed, while other costs are being deferred for future recovery, held in abeyance pendmg further regulatory action, or treated as investments in deregulated assets. There are ongoing rate proceedmgs and appeals relating to these issues (see "GSU," below). The System is committed to taking actions that will stabilize retail rates and avoid the need for future rate increases. In the short-term, this invokes contammg costs to the greatest degree practicable, thereby avoiding erosion of eammgs and delaying for as long as possible the need for general rate increases In accordance with this retail rate policy, the System operating companies have agreed to retail rate caps and/or rate freezes for speciSed periods of time. In the longer term, as discussed in " Business of Entergy - Comoetition - Least Cost Planning" above, and also as discussed specifically for each applicable company below, the System is pursuing implementation ofleast cost planning to mmmuze the cost of future sources of energy. Effective January 1,1993, the System adopted SFAS No.106 (SFAS 106), an accounting standard that requires accrual of the costs of postreturment benents other than pensions prior to the time these costs are actually incurred. In 1992, the System operating companies requested from their retail rate regulators authorization to recognize in rates the costs a.sociated with implementation of SFAS 106. For further information, see Note 10 of Entergy Corporation and Subsidiaries', Note 9 of MP&L's and NCPSI's, and Note 10 of AP&L's, GSU's, and LP&L's Notes to Financial Statements, "Postretirement and Postemployrnent Benefits," incorporated herein by reference. AP&L Rate Freeze. In connection with the settlement of various issues related to the Merger, AP&L agreed that it will not request any general retail rate increase that would take effect before November 3,1998, except, among other things, for increases associated with the Least Cost Plan (discussed below); recovery ef certain Grand Gulf 1-related costs, excess capacity costs, and costs related to the adoption of SFAS 106 that were previously deferred; recovery of certam taxes; fuel adjustment recoveries; recovery of nuclear decommissioning costs; and force majeure (defined to include, among other things, war, natural catastrophes, and high inflation). Recovery ofGrand Gulfl Costs. Under the settlement agreement entered inw with the APSC in 1985 and amended in 1988, AP&L agreed to retain a portion ofits Grand GulfI-related costs, recover a portion of such costs currently, and defer a portion of such costs for future recovery. In 1994 and subsequent years, AP&L will retain 7.92% of such costs (stated as a percentage of System Energy's 90% share of the unit) and will recover 28.08% currently. Deferrals ceased in 1990, and AP&L is recovering a portion of the previously deferred costs each year through 1998. As of December 31,1993, the balance of deferred uncollected costs was $568.0 million. AP&L is permitted to recover on a current basis the incremental costs of financing the unrecovered deferrals. l AP&L has the right to sell capacity and energy from its retamed share of Grand Gulf 1 to third parties and to sell such energy to its retail customers at a price equal to AP&L's avoided energy cost. Proceeds of sales to third parties of AP&L's retained share of Grand GulfI capacity and energy generally accrue to the benent of AP&L's stockholder; however, half of the proceeds of such sales to third parties prior to January 1,1996, are used to reduce the balance of uncollected deferrals and thus accrue to the benefit of retail ratepayers. If AP&L makes sales to third parties prior to that date in excess of the retained share, the proceeds of such excess are also split between the stockholder and the ratepayers, except that the portion of the sale that accrues to the stockholder's benefit cannot exceed the retained share. Least Cost Planning. On December 1,1992 and July 1,1993, AP&L filed with the APSC the Least Cost Plan described in " Business of Entergy - Comnetition - Least Cost Planmng," above. AP&L also requested authorization to recover developoent and implementation costs and costs and incentives related to the DSM aspects of the plan. On October 13,1991, the APSC found AP&L's plan to be complete and directed the APSC staff to conduct a series of public fomms in late 1993, including focus groups, town meetings, and collaborative workshops, before it would establish a procedural schedule that would include evidentiary hearmgs and the issuance of a Least Cost Plan order. Several of these meetings were delayed into 1994, but are expected to be completed by March 1994. At or before that time, AP&L expects the APSC to issue a procedural schedule that will allow the APSC to issue an order before the end of 1994. On January 19,1994, AP&L filed a request with the APSC for permission to withdraw the CCLM portion of the Sling and to continue such programs on a pilot basis at shareholder expense. He APSC has not yet ruled on AP&L's request. Fuel Adjustment Clause. AP&L's retail rate schedules have a fuel adjustment clause that prosides for recovery of the excess cost of fuel and purchased power incurred in the second precedmg month. he fuel adjustment clause also contains a nuclear reserve fund designed to cover the cost of replacement energy during scheduled maintenance and refueling outages at ANO, and an incentive provision that permits over- or under-recovery of the excess cost of replacement energy when ANO is operating or down for reasons other than refueling. GSU Rate Cap and Other Merger-Related Rate Agreements. he LPSC and the PUCT approved separate regulatory proposals that include the following elements: (1) a five-year rate cap on GSU's retail electric base rates in the respective states, except for force majeure (defined to include, among other things, war, natural catastrophes, and high inflation); (2) a provision for passing through to retail customers in the respective states the jurisdictional portion of the fuel savings created by the Merger; and (3) a mechanism for tracking nonfuel operation and maintenance savings created by the Merger. He LPSC regulatory plan provides that such nonfuel savings will be shared 60% by the shareholder and 40% by ratepayers during the eight years following the Merger. The LPSC i plan requires regulatory filings each year by the end of May through 2001. Le PUCT regulatory plan pro 5 ides that such savings will be shared equally by the shareholder and ratepayers, except that the shareholdets portion will be reduced by $2.6 million per year on a total company basis in years four through eight. He FUCT plan also requires a series of regulatory filings, currently anticipated to be in June 1994, and Feir"y 1996,1998, and 2001, to ensure that the ratepayers' share of such savings be reflected in rates on a timely basis and requires Entergy Corporation to hold GSU's Texas retail customers harmless from the effects of the removal by FERC of a 40% cap , on the amount of fuel savings GSU may be required to transfer to other Entergy operating companies under the FERC tracking mechanism (see " Rate Matters - Wholesale Rate Matters - System Agreernent," above). On January 14, 1994, Entergy Corporation filed a request for rehearing of FERC's December 15,1993 order approving the Merger, requesting that FERC restore the 40% cap provision in the fuel cost protection mechanism l (see " Regulation - Other Litication and Reculation." below). He matter is pending. Recovery ofRiver Bend Costs. GSU deferred approximately $369 million of River Bend operating costs, purchased power costs, and accrued carrying charges pursuant to a 1986 PUCT accounting order. Approximately
$182 million of these costs are being amortized over a 20-year period, and the remauung $187 million are not being amortized pending the ultimate outcome of the Rate Appeal (see " Texas Jurisdiction - River Bend," below). As of j
l
. -. - - . -. . - - =~ .=. . ..
December 31, 1993, the unamortized balance of these costs was $330.3 million. Further, GSU deferred'- approumately $400.4 million of similar costs pursuant to a 1986 LPSC accounting order. These costs, of which l approumately $160.4 million are unamortized as of Dw...is 31, 1993, are being amoruzed over a 10-year l period. In accordance with a phase-in plan approved by the LPSC, GSU deferred $324.7 nulhon ofits River Bend - , o costs related to the period December 1987 through February 1991. GSU has amortized $86.6 million through : [ December 31,1993, and the remainAar of $238.1 million will be recovered over approumately 3.8 years. [ l Texas Jurisdiction - River Band. In May 1988, the PUCT granted GSU a pen,wea increase in annual ! revenues of $59.9 million resulting from the inclusion in rate base of appr=i===*aly $1.6 billion of company-wide ! River Bend plant investment and approumately $182 million of related Texas retail jurisdiction deferred River - ! Bend costs (Allowed Deferrals). In addition, the PUCT disallowed as imprudent S63.5 million of company-wide : River Bend plant costs and placed in abeyance, with no findag of prudency, appro L=My $1.4 billion of j company-wide River Bend plant investment and apprommately $157 mihn of Texas retail junsdiction deferred River Bend operatmg and carrymg costs. De PUCT affinned that the ultimate rate treatmut of such amounts i would be subject to future h =-wion of the prudency of such costs. GSU and L - .g parnes appealed this ; order (Rate Appeal) and GSU filed a separate rate case askmg that the abeyed River Bend plant costs be found ; prudent (Separate Rate Case). Intervemng parties filed suit in distnct court to prohibit the Separate Rate Case. ! He district court's decision was ultimately appealed to the Texas Supreme Court which ruled in 1990 that the - prudence of the purported abeyed costs could not be relitigated in a separate rate pr-~=dit Further, the Texas ; Supreme Court's decision stated that all issues relatmg to the ments of the original order of the PUCT, includag the prudence of all River Bend-related costs, should be addressed in the Rate Appeal, In October 1991, the district court in the Rate Appeal issued an order holdmg that, while it was clear the ' PUCT made an error in assummg it could set aside $1.4 billion of the total costs of River Bend and consider them in a later preadie, the PUCT, nevertheless, fou:ui that GSU had not met its burden of proof related to the - _ ; amounts placed in abeyance. He court also ruled that the Allowed Deferrals should not be included in rate base under a 1991 decision regarding El Paso Electric Company's smular deferred costs (El Paso Case). De court , further stated that the PUCT erred in reducing GSU's deferred costs by $1.50 for each $1.00 of revenue collected under the interim rate increases authorized in 1987 and 1988. De court remandad the case to the PUCT with instructions as to the proper handling of the Allowed Deferrals GSU's motion for scheanng was denied, and in , December 1991, GSU filed an appeal of the October 1991 distnct court order. De PUCT also appealed the October 1991 district court order, which served to supersede the district court's j=d.-===* rg.i.-g it unenforceable under Texas law. In Augun 1992, the court of appeals in the El Paso Case handed down its second opinion on reheanng modifying its previous opinion on deferred =~~=*ia= De court's second opinica concluded that the PUCT may lawfully defer operatmg and maintenance costs and suh=~==='ly include them in rate base, but that the Public Utility Regulatory Act prohibits such rate base treatment for deferred carrymg costs. He court stated, however, its opinion would not preclude the recovery of deferred carrymg costs. De August 1992 court of appeals opinion was appealed to the Texas Supreme Court where argu.. .;. were heard in b,r 'm 1993. De matter is still aaad% r In September 1993, the Texas T1urd District Court of Appeals (the Hird District Court) remandad the . October 1991 district court decision to the PUCT "to reexamine the record evidane to whatever extent necessary to render a final order supported by substantial esidence and not inconsistent with our opinion." De Hird District Court specifically addressed she PUCTs treatment of certam costs, statmg that the PUCTs order was not based on substantial evidence De Hird District Court also applied its most recent ruimg in the El Paso Case to the deferred costs associated with River Bend. However, the hard District Court caurumad the PUCT to confine its deliberations to the evidence addressed in the original rate case. Certam parues to the case have indicated their : position that, on remand, the' PUCT may change its original order only with respect to matters specifically . discussed by the nird District Court which, if allowed, would increase GSU's allowed River Bend investment, net . 20 - ' i
l i of accumulated depreciation and related taxes, by approximately $48 million as of December 31,1993. GSU believes that under the hird District Court's decision, the PUCT would be free to reconsider any aspect ofits order ! concerning the abeyed $1.4 billion River Bend investment. GSU has filed a motion for rehearing asking the nird District Coun to modify its order so as to permit the PUCT to take additional evidence on remand. He PUCT and other panies have also moved for rehearing on various grounds. ne nird District Coun has not yet ruled on any of these moth.ns. l As of December 31,1993, the River Bend plant costs disallowed for retail ratemakmg purposes in Texas, and the River Bend plant costs held in abeyance and the related cost deferrals totaled (net of taxes) approximately
$14 million, $300 million (both net of depreciation), and $171 million, respectively. Allowed Deferrals were approximately $95 million, net of taxes and amonization, as of December 31,1993. GSU estimates it has collected i approxunately $139 million of revenues as of December 31, 1993, as a result of the originally ordered rate l treatment of these deferred costs. However, if the PUCT adopts the most recent decision in the El Paso Case, the possible refunds approximate $28 million as a result of the inclusion of deferred carrying costs in rate base for the period July 1988 through December 1990. However, if the PUCT reverses its decision to reduce GSU's deferred I costs by $1.50 for each $1.00 of revenue collected under the interim rate increases authorized in 1987 and 1988, the l potential refund of amounts described above could be reduced by an amount ranging from $7 million to l $19 million. )
No assurance can be given as to the timing or outcome of the remands or appeals described above. Pending fiarther developments in these cases, GSU has made no write-offs for the River Bend related costs. Management believes, based on advice from Clark, Thomas & Winters, a Professional Corporation, legal counsel of record in the Rate Appeal, that it is reasonably possible that the case will be remandad to the PUCT, and the PUCT will be allowed to rule on the prudence of the abeyed River Bend plant costs. Rate caps imposed by the PUCTs regulatory approval of the Merger could result in GSU being unable to use the full amount of a favorable decision to immediately increase rates; however, a favorable decision could permit some increases and/or limit or prevent decreases during the perivJ the rate caps are in effect. At this time, management and legal counsel are unable to l predict the amount, if any, of the abeyed and previously disallowed River Bend plant costs that ultimately rnay be i disallowed by the PUCT. A net of tax write-off as of December 31,1993, of up to $314 million could be required based on the PUCTs ultimate ruling. In prior proceedmgs, the PUCT has held that the original cost of nuclear power plants will be included in rates to the extent those costs were prudently incurred. Based upon the PUCTs prior decisions, management believes that its River Bend construction costs were prudently incurred and that it is reasonably possible that it will recover in rate base, or otherwise through means such as a deregulated asset plan, all or substantially all of the abeyed River Bend plant costs. However, management also recogmzes that it is reasonably possible that not all of the abeyed River Bend plant costs may ultimately be recovered. As pan of its direct case in the Separate Rate Case, GSU filed a cost reconciliation study prepared by Sandlin Associates, management consultants with expertise in the cost analysis of nuclear power plants, which supports the reasonableness of the River Bend costs held in abeyance by the PUCT. This reconciliation study determined that approximately 82% of the River Bend cost increase above the amount included by the PUCT in rate base was a result of changes in federal nuclear safety requirements and provided other support for the remamder of the abeyed amounts. Here have been four other rate proceedings in Texas invohing nuclear power plants. Imestment in the plants ultimately disallowed ranged from 0% to 15% Each case was unique, and the disallowances in each were made on a case-by-case basis for different reasons. Appeals of most, if not all, of these PUCT decisions are currently pendmg. he following factors support management's position that a loss contingency requiring accrual has not occurred, and its belief that all, or substantially all, of the abeyed plant costs will ultimately be recovered:
- 1. He St.4 billion of abeyed River Bend plant costs have never been ruled imprudent and disallowed by the PUCT.
- 2. Sandlin Associates' analysis which supports the prudence of substantially all of the abeyed construction costs.
- 3. Historical inclusion by the PUCT of prudent constmetion costs in rate base.
- 4. The analysis of GSU's intemal legal staff, which has considerable experience in Texas rate case litigation.
Additionally, management believes, based on advice from Clark, Romas & Winters, a Professional CorporatiA legal counsel of record in the Rate Appeal, that it is probable that the deferred costs will be allowed. However, assuming the August 1992 court of appeals' opinion in the El Paso Case is upheld and applied to GSU and the deferred River Bend costs currently held in abeyance are not allowed to be recovered in rates as allowable costs, a net-of-tax write-off of up to S171 million could be required. In addition, future revenues based upon the deferred costs previously allowed in rate base could also be lost and no assurance can be given as to whether or not refunds (up to $28 million as of December 31,1993) of revenue received based upon such deferred costs previously recorded will be required. See Note 12 of GSUs Notes to Financial Statements, *Entergy Corporation-GSU Merger," for the accounting treatment of preacquisition contingencies, including a River Bend write down. Texas Jurisdiction - Fuel Reconciliation. In January 1992, GSU applied whh the PUCT for a new fixed fuel factor and requested a fmal reconciliation of fuel and purchased power costs incurred between December 1,1986 and September 30,1991. GSU proposed to recover net underrecoveries and interest (including underrecoveries related to NISCO, discussed below) over a twelve month period. In April 1993, the presiding PUCT AIJ issued a report which concluded that GSU incurred approximately $117 million of nonreimbursable fuel costs on a company-wide basis (approxunately $50 million on a Texas retail jurisdictional basis) during the reconciliation period. Included in the nonreimbursable fuel costs were payments above GSUs avoided cost rate for power purchased from NISCO. He PUCT ordered in 1986 that the purchased power costs from NISCO in excess of GSU's avoided costs be disallowed. The PUCT disallowance resulted in approxunately $12 million to $15 million of anrecovered purchased power costs on an annual basis, which GSU continued to expense as the costs were incarred. In April 1991, the Texas Supreme Court, in the appeal of such order, ordered the PUCT to allow GSU to recc ver purchased power payments in excess of its avoided cost in future proceedmgs, if GSU established to the PUCTs satisfaction that the payments were reasonable and necessary expenses. In June 1993, the PUCT, in the fhel reconciliation case, concluded that the purchased power pa>Tnents made to NISCO in excess of GSUs avoided cost were not reasonably incurred. As a result of the order, GSU recorded additional fuel expenses (including interest) of $2.8 million for non-NISCO related items. He PUCTs order resulted in no additional expenses related to the NISCO issue, or for overcollections related to the fixed fuel factor, as those charges were expensed by GSU as they were incurred. The PUCT concluded that GSU had over-collected its fuel costs in Texas and ordered GSU to refund approximately $33.8 million to its Texas retail customers, including approxunately $7.5 million ofinterest. The PUCT reduced GSU's fixed fuel factor in Texas from about 2.1 cents per KWH to approxanately 1.84 cents per KWH. GSU lad requested a new fixed fuel factor of aoout 2.02 cents per KWH. Based on current sales forecasts, adoption of the PUCTs recommended fixed fuel factor would reduce GSU's revenues by approximately $34 million annually. In October 1993, GSU appealed the PUCTs order to the Travis County District Court. No assurance can be given as to the timing or outcome of the appeal. Texas - Cities Rate Sefrlement. In June 1993, thirteen cities within GSUs Texas service area instituted an i investigation to deternune whether GSUs current rates were justified. In October 1993, the general counsel of the l PUCT instituted an inquiry into the reasonableness of GSUs rates. In November 1993, a settlementa a p~..ca was l filed with the PUCT which provides for an initial reduction in annual retail base revenues in Texas of i approxunately $22.5 million effective for electric usage on or after November 1,1993, and a second reduction of 520 million to be effective September 1994 Further, the settlement provided for GSU to reduce rates with a
$20 million one-time bill credit in December 1993, and to refund approximately $3 million to Texas retail cus-tomers on bills rendered in Damhar 1993. He cities rate inquiries had been settled earlier on the same terms.
In November 1993, in association with the settlement of the above<lescribed rate inqumes,' GSU entered into a settlement covering issues related to a March 1991 non-unarumous settlement in another pr-a~ iia: Under j this settlement, a $30 million rate increase approved by the PUCT in March 1991, became final and the PUCTs j treatment of GSUs federal tax expense was settled, eliminating the possibility of refunds associated with amounts j collected resulting from the disputed tax calculation. ! I In December 1993, a large industrial customer of GSU =====W its intention to oppose the settlement of the PUCT rate inquiry. De customer's opposition does not affect the cities' rate settlement. The w~ner's opposition requires the PUCT to conduct a hearmg conceming GSUs rates charged in areas outside the corporate I' limits of the cities in its Texas service territory to deternune whether the settlement's rates are just and rensanahle. A hearing has been set for July 8,1994. GSU believes that the PUCT will ultunately approve the settlement, but no assurance can be provided in this regard. Louisiana Jurisdiction - River Bend. Previous rate orders of the LPSC have boca =pp-M and pendmg i resolution of various appellate ps-#p, GSU has made no write off for the disallowance of $30.6 =dlu= of deferred revenue requirement that GSU recorded for the period December 16,1987 unrough February 18,1988. In January 1992, the LPSC ordered a deregulated asset plan for $1.4 billion of River Bend plant costs not allowed in rates. He plan allows GSU to sell the generation from the approximately 22% of River Bend to Louisiana customers at 4.6 cents per KWH, or off-system at higher prices. Incremental revenues from off-system sales above 4.6 cents per KWH will be shared 60% by shareholders and 40% by ratepayers (see GSUs
" Management's Financial Discussion and Analysis," incorporated herein by reference, for the effects of the plan on GSUs 1993 results of operations).
LPSC - Return on Equity Review. In the June 1993 open session, a prehmmary report was made comparing the authorized and actual earned rates of return for electric and gas utilities subject to the LPSC's jurisdiction. The prelimmary report indicated that several electric utilities, including GSU, may be over canung based on current estimated costs of equity, ne LPSC requested those utilities to file responses indicatmg whether they agreed with the prelimmary report, and to provide their reasons if they did not agree. GSU provided the LPSC ; with information that GSU believes supports the current rate level. Tk LPSC decided at its September 7,1993 open session to defer review of GSUs base rates until the first canungs analysis after the Merger, scheduled for mid-1994. LPSC Fuel Cost Review. In November 1993, the LPSC ordered a review of GSUs fuel costs. He LPSC stated that fuel costs for the period October 1988 through September 1991 would be reviewed based on the number of outages at River Bend and the fmdmgs in the June 1993 PUCT fuel reconciliation case. Heanngs are scheduled to begin in March 1994. Least Cost Planning. Currently, the PUCT does not have least cost planmng rules in place, and GSU has f not filed a Least Cost Plan with the PUCT. However, the PUCT staff has begun a rulemakmg process for such rules, and GSU is actively participating in this process. GSU has not yet filed a Imst Cost Plan with the LPSC. Fuel Recovery. In January 1993, the PUCT adopted e new rule for setting c fixed fuel factor that is intended to recover projected a!!owable fuel and purchased power costs not covered by base rates. To the extent actual costs vary from the fixed factor, the PUCT may require refunds of overcharges or permit recovery of undercharges. Under the new rule, fuel factors are to be revised every six months, and GSU is on a schedule providing for revision each March and September. The PUCT is required to act within 60 or 90 days, dependmg on whether or not a hearing is required, and refunds and surcharges will be required based upon a materiality threshold of 4% of Texas retail fuel revenues. Fuel charges will also be subject to reconciliation proceedmgs every three years, at which time additional adjustments may be required (see " Teras Jurisdiction - Fuel Reconciliotion," above). All of GSU's rate schedules in Louisiana include a fuel adjustment clause to recover the cost of fuel and purchased power energy costs. The fuel adjustment reflects the delivered cost of fuel for the second precedmg month. LP&L LPSC Jurisdiction. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, LP&L was granted rate relief with respect to costs associated with Waterford 3 and LP&L's share of capacity and en_ from Grand Gulf 1, subject to certain terms and conditions. With respect to Waterford 3, an increase aggregating $170.9 million over the period 1985-1988, and LP&L agreed to t LP&L was grar permanently absco, and not recover from retail ratepayers, $284 million ofits investment in the unit and to defer I $266 million ofits costs related to the years 1985-1988 to be recovered over approxunately 8.6 years beguunng in April 1988. As of December 31,1993, LP&L's unrecovered deferral balance was $82.5 million. With respect to Grand Gulf 1, LP&L agreed to absorb, and not recover from retail ratepayers,18% ofits 14% share (approxunately 2.52%) of the costs of Grand GulfI capacity and energy. LP&L is allowed to recover, through the fuel adjustment I clause, 4.6 cents per KWH (currently 2.55 cents per KWH through May 1994) for the energy related to the permanently absorbed percentage, with LP&L's permanently absorbed retained percentage to be avadable for sale l to non-affiliated parties, subject to LPSC approval. (See Note 2 of LP&L's Notes to Financial Statements, " Rate and Regulatory Matters - Waterford 3 and Grand Gulf 1." incorporated herein by reference, for further information on LP&L's Grand Gulf I and Waterford 3-related rates.) In a subsequent rate proceedmg, on March 1,1989, the LPSC issued an order providing that, in effect, LP&L was entitled to an approximately S45.9 million annual retail rate increase, but that, in lieu of a rate increase, LP&L would be permitted to retam $188.6 million of the proceeds of a 1988 settlement oflitigation with a gas supplier, and to amortize such proceeds into revenues over a period of approxunately 5.3 years. The amortization of the proceeds will expire in mid-1994 and this source of revenue will no longer be avadable to LP&L. LP&L believes that the amortization has resulted in approximately the same amount of additional net income as an annual rate increase of $45.9 million would have provided over the same period. In connection with this order, LP&L agreed to a five-year base rate freeze scheduled to expire in March 1994 at then current levels subject to certam conditions. (See Note 2 of LP&L's Notes to Financial Statements, " Rate and Regulatory Matters - March 1989 Order." incorporated herein by reference, for further information on the terms of this order.) By letter dated July 27,1993, the LPSC requested LP&L to explain its "relatively high cost of debt" compared to other electric utilities subject to LPSC jurisdiction. LP&L responded to the request on August 11,1993. On August 14,1993, the LPSC's consultants acknowledged LP&L's rationale for its cost of debt and suggested that certain aspects of LP&L's cost of debt could be taken up in rate proceedmgs after the expiration of LP&L's rate freeze. On October 7,1993, the LPSC approved a schedule to conduct a review of LP&L's rates and rate structure upon the expiration of the rate freeze in March 1994. CouncilJurisdiction. Under the Algiers rate settlement entered into with the Council in 1989, LP&L was granted rate relief with respect to its Grand Gulf I and Waterford 3-related costs, subject to certam terms and conditions. LP&L was granted an annual rate increase of $9.5 million that was phased-in over the two-year period begmnmg in Julf 1989, and was permitted to retain $4.2 million (the Council's jurisdictional portion) of the proceeds oflitigation with a gas supplier and to amortize such proceeds plus interest into revenues over the same two-year period. LP&L agreed to absorb and not recover from Algiers retail ratepayers $17 million of fixed costs associated with Grand Gulf I and Waterford 3 incurred prior to the date of the settlement, $5.9 million of its investment in Waterford 3, and 18% of the Algiers portion of LP&L's Grand Gulf 1-related costs incurred after the settlement. However, LP&L is allowed to recover 4.6 cents per KWH or the avoided cost, whichever is higher, for the energy related to the permanendy absorbed percentage through the fuel adjustment clause, with the permanently absorbed percentage to be available for sale to non-affiliated parties, subject to the Council's right of first refusal. LP&L also agreed to a rate freeze for Algiers customers m.il July 6,1994, except in the case of catastrophic events, changes in federal tax laws, or changes in LP&L's Grand GulfI costs resulting from FERC proceedmgs. Least Cost Planning. On December 1,1992, and July 1,1993, LP&L filed with the LPSC and the Council the Izast Cost Plan described under " Business of Entergy - Comoetition - Least Cost Planning " above. LP&L also requested authorization to recover development and implementation costs and costs and incentiws related to the DSM aspecu of the plan. Discovery in the LPSC review of LP&L's least Cost Plan filing is continuing, and the current procedural schedule (which maybe extended) contemplates that, after beanngs and briefings, a report of the LPSC special counsel will be issued on June 14, 1994. He LPSC could render a decision on the basis of this report. On January 19,1994, LP&L filed a motion with the LPSC to dismiss or withdraw without prejudice the CCLM and to proceed with a pilot CCLM at shareholder expense. The LPSC granted LP&L's motion on February 2,1994, subject to LP&L, among other things, keeping the LPSC timely informed as to LP&L's CCLM activities. (See "NOPSI - Least Cost Planning." below, for funher information on LP&L's and NOPSI's proceedmgs pending before the Council.) Fuel Adjustment Clause. LP&L's rate schedules include a fuel adjustment clause to reflect the delivered cost of fuel in the second precedmg month and purchased power energy costs. He fuel adjustment also reflects a surcharge for deferred fuel expense arising from the monthly reconciliation of r.etual fuel cost incurred with fuel cost revenues billed to customers. LP&L defers on its books fuel costs that will be reflected in customer billings in the future under the fuel adjustment clause. MP&L Rate Freeze. In a stipulation entered into by MP&L in connection with the settlement of various issues related to the Merger, MP&L agreed that (1) for a period of five years beginning on November 9,1993, retail base rates under the FRP (see " Incentive Rate Plan," below) would not be increased above the level of rates in effect on November 1,1993, and (2) MP&L would not request any general retail rate increase that would increase retail rates above the level of MP&L's rates in effect as of November 1,1993, and that would become effective in such five-year period except, among other things, for increases associated with the least Cost Plan (discussed below), ! recovery of deferred Grand Gulf 1-related costs, recovery under the fuel adju:tment clause, adjustments for certain taxes, and force majeure (defined to include, among other things, war, natural catastrophes, and high inflation). Recovery ofGrand Gulfl Costs. He MPSC's Final Order on Rehearing, issued in 1985, affirmed by the United States Supreme Court in 1988, and subsequently revised in 1988, granted MP&L an annual base rate i increase of approximately $326.5 million in connection with its allocated share of Grand Gulf I costs. He Final Order on Rehearing also provided for the deferral of a portion of such costs that were incurred each year through 1992, and recovery of these deferrals over a period of six years ending in 1998. As of December 31,1993, the uncollected balance of MP&L's deferred costs was approximately $601.4 million. MP&L is permitted to recover the carrying charges on all deferred amounts on a current basis. l Incentive Rate Plan. In July 1993, the MPSC ordered MP&L to Sie a formulary incentive rate plan designed to allow for periodic small adjustments in rates based upon a comparison of camed to benchmark retums and upon performance factors incorporated in the plan. Pursuant to this order, on November 1,1993, MP&L filed
- a proposed formula rate plan. MPSC was also expected to conduct a general review of MP&L's current rates in
! the course of approving an incentive rate plan. 25 - l 1
l l l On January 28, 1994, MP&L and the Mississippi Public Utilities Staff (MPUS) entered into a Joint Stipulation in this proceedmg. Under the Joint Stipulation, MP&L and the MPUS agreed on a number of accounting adjustments for the test year ending June 30,1993, (June 30 Test Year) inat resulted in a reduction to MP&L's base rate revenues in the June 30 Test Year of approximately 4.3%, or $28.1 million. This translates into approxunately a 3.7% decrease in overall revenues from sales to retail customers, which include revenues related to fuel, taxes, and Grand Gulf. MP&L and the MPUS agreed on a required retum on equity of 11% for the June 30 Test Year. MP&L and the MPUS also stipulated to a revised Formula Rate Plan (FRP). He stipulated FRP is essentially the same as the proposed plan Sled by MP&L on November 1,1993. Certain of the accounting changes agreed to by the MPUS and MP&L for the June 30 Test Year are incorporated into the stipulated FRP. Also, the formula in the stipulated FRP for detemunmg required retum on equity would have produced a required return on equity for MP&L of 11.07% for the June 30 Test Year, he stipulated retum on equity formula will be applied for the first time in the first Evaluation Report under the stipulated FRP. The first Evaluation Report will be filed in March 1995 for the Evaluation Period ending December 31,1994. On February 10,1994, MP&L, the Mississippi Industrial Energy Group (MIEG), and the MPUS entered into and filed with the MPUS, a Joint Stipulation (MIEG Joint Stipulation) resolving the issues raised by the MIEG in the docket. On February 16,1994, MP&L and the Mississippi Attorney General entered into a Joint Stipulation that resolved the issues raised by the Mississippi Attorney General in the docket. Other parties in the case, including two gas utility intervenors, were not parties to the Joint Stipulations. In late February 1994, the MPSC conducted a general review of MP&L's current rates and on March 1, 1994, issued a final order in which the MPSC approved each of the Joint Stipulations. He MPSC ordered MP&L to file rates designed to provide a reduction of $28.1 million in operatmg revenues for the June 30 Test Year on or before March 18,1994, to become effective for service rendered on and after March 25,1994. He FRP also was approved and will be effective on March 25,1994, with any initial adjustment to base rates, if any, in May 1995. Under the FRP, a formula will be established under which MP&L's camed rate of return will be calculated automatically every 12 months and compared to a benchmark rate of return calculated under a separate formula ' within the FRP. If MP&L's camed rate of retum falls within a bandwidth around the benchmark rate of return, there will be no adjustment in rates. If MP&L's earnmgs are above the bandwidth, the FRP will automatically reduce MP&L's base rates. Altematively, if MP&L's cammgs are below the' bandwidth, the FRP will automatically increase MP&L's base rates (see " Rate Freeze" above for information on a cap on base rates at November 1993 levels for a period of five years). He reduction or increase in base rates will be an amount representing 50% of the difference between the camed rate of retum and the nearest limit of the bandwidth. In no event will the annual adjustment in rates exceed the lesser of 2% of MP&L's aggregate annual retail revenues, or
$14.5 million. Under the FRP the benchmark rate of retum, and consequently the bandwidth, will be adjusted slightly upward or downward based upon MP&L's performance on three performance factors: customer reliability, customer satisfaction, and customer price.
In its Final Order, the MPSC also recognized that on February 9 and 10,1994, a severe ice storm simck northern Mississippi causing extensive and widespread damage to MP&L's transmission and distribution facilities in approxirnately 15 counties. Although the MPSC made no findings in the final order as to MP&L's costs asscciated with the ice storm and restcration of service, the MPSC acknowledged that there is precedent in Mississippi for recovery of certain costs associated with storms and natural disasters and restoration of service, ne MPSC stated the recovery of MP&L's ice storm costs should be addressed in a separate docket. MP&L~ plans to immediately file for rate recovery of the costs related to the ice storm. Least Cost Planning. On December 1,1992 and July 1,1993, MP&L filed with the MPSC the least Cost : Plan described in " Business of Entergy - Comoetition - Least Cost Planning," above. MP&L also requested a finding by the MPSC that the plan's cost recovery methodology is reasonable and appropriate. MP&L will request approval of cost recovery mechanisms after the plan has been approved by the MPSC. On October 6,1993, the I
i MPSC, on its own motion, stayed all proceedmgs in this docket. The MPSC stay order regarding MP&L's Least Cost Plan filing remams in effect even though MP&L and the MPUS have stipulated to an FRP (see " Incentive , l Rate Plan," above). Because the stay order remains in effect, MP&L has not yet filed a request that the CCLM portion of the filing be withdrawn and that a pilot CCLM program be implemented. i Fuel Adjustment Clause. MP&L's rate schedules include a fuel adjustment clause that permits recovery from customers of changes in the cost of fuel and purchased power. He monthly fuel adjustment rate is based on projected sales and costs for the month, adjusted for differences between actual and estimated costs for the second prior month. NOPSI Electric Retail Rate Reduction. On November 18,1993, in connection with the settlement of various issues related to the Merger, the Council adopted a resolution requiring NOPSI to reduce its annual electric base rates by $4.8 million on bills rendered on or after November 1,1993. Recovery of Grand Gulf 1 Costs. Under NOPSI's various Rate Settlements with the Council (which include the 1986 NOPSI Settlement, the February 4 Resolution relating to pmdence issues, and the 1991 NOPSI Settlement of the issues raised in the February 4 Resolution), NOPSI agreed to absorb and not recover from ratepayers a total of $186.2 million ofits Grand Gulf I costs. NOPSI was permitted to implement annual rate increases in decreasing amounts each year through 1995, and to defer certain costs, and related carrying charges, for recovery on a schedule extendmg from 1991 through 2001. As of December 9,1993, the uncollected balance of NOPSI's deferred costs was $228.8 million. NOPSI also agreed to a base rate freeze through October 31; 1996, excluding the scheduled increases, certain changes in tax rates, and increases related to catastrophic events. (See Note 2 of NOPSI's Notes to Financial Statements, " Rate and Regulatory Matters - Prudence Settlement and Finalized Phase-In Plan " incorporated herein by reference, for further information.) Gas Rates. Ic May 1992, NOPSI and the Council settled a pending application for gas rate increases. He settlement provided for annual rate increases of approximately $3.8 million in May 1992 and 1993, and the deferral of an additional S3 million for recovery in the years beginning in May 1993 through May 1996. NOPSI also agreed to a base rate freeze, except for the scheduled increases and certain other exceptions, through October 31,1996. Least Cost Planning. On December 1,1992, and July 1,1993, NOPSI filed with the Council th e Least Cost Plan described under " Business of Entergy - Comoetition - Least Cost Planning" above. NOP55 also requested authorization to recover development and implementation costs and costs and incentives related to DSM aspects of the plan. After hearings and briefmgs, the Council issued, on November 22, 1993, a resolution that requires NOPSI and LP&L to provide, within certain time frames, additional information, among other things, on how the seven full scale DSM programs approved by the Council in the resolution will be implemented. Such programs are estimated to cost approximately $13 million over the next three years. He Council provided in the resolution certain assurances regarding recovery of costs associated with these programs Discovery is proceedmg and testimony is being filed, with the second round of hearings to begin in Febmary 1994. After the hearings are conc!uded and briefs have been filed, the Council will address the second round issues in early April 1994. On Febmary 3,1994, the Council issued a resolution and order granting the motions of NOPSI and LP&L to dismiss without prejudice the CCLM portion of the filing, authorizing NOPSI and LP&L to proceed with a pilot CCLM (other than the construction of a fiber optics / coaxial cable network) in New Orleans at shareholder expense (subject to certain conditions). The Council also opened a new docket to expeditiously address issues related to the CCLM pilot, and directing NOPSI and LP&L to obtain Council authorization in the new docket before constructing such a fiber optics / coaxial cable network. I l
)
l
i l l In connection with the settlement of various issues related to the Merger, the Council adopted a resolution on November 18,1993, that provides that the Council will not disallow the first $3.5 million of costs incurred by NOPSI through October 31,1993, in connection with the Least Cost Plan. Fuel Adjustment Clause. NOPSI's electric rate schedules include a fuel adjustment clause to reflect the ; delivered cost of fuel in the second preceding month, adjusted by a surcharge for deferred fuel expense arising from ; the monthly reconciliation of actual fuel cost incurred with fuel cost revenues billed to customers. He adjustment clause, on a monthly basis, also reflects the difference between nonfuel Grand Gulf I costs paid by NOPSI and the estimate of such costs provided in NOPSI's Grand Gulf 1 Rate Settlements. NOPSI's gas rate schedules include a gas cost adjustment to reflect gas costs in excess of those collected in rates, adjusted by a surcharge similar to that included in the electric adjustment clause. NOPSI defers on its books fuel and purchased gas costs to be reflected in billings to customers in the future under the fuel adjustment clause. REGULATION Federal Regulation Holding Company Act. Entergy Corporation is a registered public utility holding company under the Holding Company Act. As such, Entergy Corporation and its various direct and indirect subsidiaries (with the exception of its independent power /EWG subsidiaries) are subject to the broad regulatory provisions of that Act. Except with respect to investments in certain EWG projects and foreign utility company projects (see " Business of Entergy - Comoetition - General," above for a discussion of the Energy Act), Section ll(b)(1) of the Holding Company Act limits the operations of a registered holding company system to a single, integrated public utility system, plus additional systems and businesses as provided by that section. Federal Power Act. He System operating companies, System Energy, and Entergy Power are subject to the Federal Power Act as admmistered by FERC and the DOE. He Federal Power Act provides for regulatory jurisdiction over the licensing of certain hydroelectric projects, the business of, arui facilities for, the transmission and sale at wholesale of electric energy in interstate commerce and certain other activities of the System operating companies, System Energy, and Entergy Power as interstate electric utilities, including accounting policies and practices. Such reNation includes jurisdiction over the rates charged by System Energy for capacity and energy provided to AP&L, '&L, MP&L, and NOPSI, or others, from Grand Gulf 1. AP&L hole a license for two hydroelectric projects (70 MW) that was renewed on July 2,1980. His license, granted by FERC, will expire in February 2003. Regulation of the Nuclear Power Industry General. Under the Atomic Energy Act of 1954 and Energy Reorgamzation Act of 1974, operation of nuclear plants is intensively regulated by the NRC, which has broad power to impose licensing and safety-related requirements. In the event of non-compliance, the NRC has the authority to impose fmes or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. AP&L, GSU, LP&L, and System Energy, as owners of all or a portion of ANO, River Bend, Waterford 3, and Grand Gulf 1, respectively, and Entergy Operations, as the operator of these units, are subject to the junsdiction of the NRC. Revised safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at System nuclear plants and additional such expenditures could be required in the future. He nuclear power industry faces uncertainties with respect to the cost and availability of long-term arrangements for disposal of spent nuclear fuel and other radioactive waste, nuclear plant operational issues, the technological and financial aspects of decommissioning plants at the end of their licensed lives, and the effect of certain requirements relating to nuclear insurance. These matters are briefly discussed below. l
Spent Fuel and Other High-Level Radioactive Waste. Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. The NRC, pursuant to this Act, also requires operators of nuclear power reactors to enter into spent fuel disposal contracts with the DOE, and the affected System companies have entered into such disposal contracts. However, the DOE has not yet identiSed a permanent storage repository and, as a result, future expenditures may be required to increase spent fuel storage capacity at the plant sites. (For further information concerning spent fuel disposal contracts with the DOE, schedules for initial shipments of spent nuclear fuel, current on-site storage capacity, and costs of prosiding additional on-site storage capacity, with respect to AP&L, GSU, LP&L, and System Energy, respectively, see Note 8 of AP&L's, GSU's, and LP&L's, and Note 7 of System Energy's, Notes to Financial Statements, " Commitments and Contingencies - Soent Nuclear Fuel and Decommissioning Costs." incorporated herein by l reference.) Low-Level Radioactive Waste. He availability and cost of disposal facilities for low-level radioactive waste resulting from normal operation of nuclear units are subject to a number of uncertainties. Under the low-Level Radioactive Waste Policy Act of 1980, as amended, each state is responsible for disposal of its own w2ste, and states may join in regional compacts to jointly fulfill their responsibilities. He States of Arkansas and Louisiana participate in the Central States Compact, and the State of Mississippi participates in the Southeast Compact. Two disposal sites are currently operating in the United States, and one of them, which is located in i Washington, is closed to out-of-region generators. He second site, the Barnwell Disposal Facility (Barnwell) I located in South Carolina, is operated by the Southeast Compact and the State of Mississippi is ap~*A to have l i access to this site through December 1995. Barnwell had been open to out of-region generators (including generators in Arkansas and 1 :iisiana) in the past; however, on April 14, 1993, the Southeast Compact voted to deny access to Barnwell to men. , of the Central States Compact. Such access was reinstated for the period from ! October 1993 through June 1994, which time legislative action by the State of South Carolina would be required to permit further access to out-of-regn generators. Beguuung in July 1994, low-level radioactive waste generators in the Central States Compact, including AP&L, GSU, and LP&L, will be required to store such waste on-site until a Central States Compact facility becomes operational or another site becomes accessible. Both the Central States Compact and the Southeast Compact are working to establish additional disposal sites. The System, along with other waste generators, funds the development costs for new disposal facilities. He System's expenditures to date are approximately $30 million; and future levels of expenditures cannot be predicted. Until such facilities are established, the System will continue to seek access to existing facilities, which may be available at costs that are higher than those incurred in the past, or which may be unavailable. If such access is unavailable, the System will store low-level waste on-site at the affected units. ANO has on-site storage that is estimated to be sufficient until 1999. Construction of on-site storage at the other nuclear units is being considered, along with other alternatives. A coordinated design concept that can be utilized at both Waterford 3 and Rive-Bend is being evaluated. Grand Gulf I will have continued disposal access through December 1995; therefore, no immediate plans for on-site storage are needed for Grand Gulf 1. The estimated construction costs for storage sufficient for approxunately five years at Ors =A Gulf 1, Waterford 3, and River Rend are in the range of
$2.0 million to $5.0 million for each site. As an alternative to on-site storage, Entergy is working with other industry groups to influence the continued operation of the Barnwell disposal facility for out-of-region generators.
Decommissioning. AP&L, GSU, LP&L, and System Energy are recovering portions of their estunated decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf 1, respectively. These amounts are being deposited in external trust funds that, together with the earnmgs thereon, can only be used for future decommissioning costs. Estimated decommissioning costs are regularly resiewed and updated to reflect inflation 4 and changes in regulatory requirements and technology, and applications w " be made to appropriate regulatory authorities to recover in rates any projected increase in decommissioning costs above that currently being recovered. (For additional information with respect to decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf 1, respectively, see Note 8 of AP&L's, GSU's, and LP&L's and Note 7 of System Energy's Notes to Finar.cial Statements, " Commitments and Contingencies . Soent Nuclear Fuel and Decommissioninn Costs." incorporated herein by reference.) Uranium Enrichment Decontamination and Decommissioning Fees. %e Energy Act requires all electric utilities (including AP&L, GSU, LP&L, and System Energy) that have purchased uranium enrichment senices from the DOE to contribute up to a total of $150 million annually, adjusted for inflation, up to a total of
$2.25 b;11 ion over approximately 15 years, for decommissioning and decontammation of enrichment facilities.
AP&L's, GSU's, LP&L's, and System Energy's estimated annual contributions to this fund are $3.3 million, $0.6 million, $1.2 million, and $1.3 million, respectively, in 1993 dollars over approximately 15 years. Contributions to this fund are to be recovered through rates in the same manner as other fuel costs. Nuclear Insurance. He Price-Anderson Act provides for a limit of public liability for a single nuclear incident. As of December 31, 1993, the limit of public liability for such type of incident was approximately 59 4 billion. AP&L, GSU, LP&L, and System Energy have protection with respect to this liability through a combination of private insurance and an industry assessment program, and also have insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units. (For a discussion of insurance applicable to nuclear programs of AP&L, GSU, LP&L, and System Energy, see Note 7 of System Energy's and Note 8 of AP&L's, GSU's, and LP&L's Notes to Financial Statements, and Note 8 of Entergy Corporation and Subsidiaries, Notes to Consolidated Financial Statements, " Commitments and Contingencies - Nuclear Insurance " incorporated herein by reference.) Nudear Ooerstions General. Entergy Operations operates ANO, River Bend, Waterford 3, and Grand Gulf 1, subject to the owner oversight of AP&L, GSU, LP&L, and System Energy, respectively. AP&L, GSU, LP&L, and System Energy, and the other Grand Gulf 1, Waterford 3, and River Bend co-owners, have retamed their ownership interests in their respective nuclear generating units. AP&L, GSU, LP&L, and System Energy have also retained their associated capacity and energy entitlements, and pay directly or reimburse Entergy Operations at cost for its
- operation of the units.
On June 24,1992, the NRC issued a bulletin requiring all utilities using a certain fire barrier material in a nuclear power plant to take certain actions related to the material. This material may have been used in as many as 87 nuclear plants in the United States, including ANO, River Bend, Waterford 3, and Grand Gulf 1 (see " River Bend," below for additional information). t ANO. In 1990, in response to a special diagnostic evaluation report by the NRC, AP&L implemented a comprehensive action plan for ANO designed to correct cenain management, orgamzational, and technical I problems, and to improve the long-term cperational effectiveness and safety of the units. His action plan was largely completed in 1993. Leaks in certain steam generator tubes at ANO 2 were discovered and repaired during an outage in March 1992; and during a refueling outage in September 1992, a comprehensive inspection of all steam generator tubing was conducted and necessary repairs were made. During a mid. cycle outage in May 1993, a scheduled special inspection of certain steam generator tubing was conducted by Entergy Operations and additional repairs were made. Entergy Operauons proposes to operate ANO 2 with r.o further steam generator inspections until the next refueling outage, which is scheduled for the spring of 1994, and the NRC has concurred with this proposal. The operations and power output of the unit have not been adverseiy affected to date by these repairs. River Bend. He Nuclear Information and Resource Senice petitioned the NRC to shut down the River Bend plant in July 1992 because of alleged defects in a fire barrict material. GSU bas used this material in its l River Bend plant and is in compliance with the requirements of the bulletin. On August 19,1992, the NRC denied l the petitioner's request. In a December 1993 letter, the NRC requested additional technical information on the use l 30 1
of the material in the plant, and requested GSU's plans and schedules for resohing technical issues associated with j the use of the material in certain configurations. GSU has provided the information requested in the NRC letter. On January 13,1993, in connection with the Merger, GSU filed two applications with the NRC to amend ] the River Bend operating license. The applications sought the NRC's consent to the Merger and to a change in the licensed operator of the facility from GSU to Entergy Operations. On August 6,1993, Cajun filed a petition to intervene and request for a hearing in the proceedings. On January 27,1994, the presiding NRC Atomic Safety and Licensirg Board (ASLB) issued an order granting Cajun's petition to intervene and ordered a hearing on one of Cajun's contentions. On Febmary 15,1994, GSU filed an appeal of the ASLB Order with the NRC. On December 16, 1993, prior to this ASLB ruling, the NRC Staff issued the two license amendments for River Bend, making them effective immediately upon consummation of the Merger. On February 16,1994, Cajun filed with the D.C. Circuit petitions for review of the two license amendments issued by the NRC. These two amendments are in full force and effect, but are subject to the outcome of the two proceedmgs. A hearing on the proceedmg before the ALSB is not expected to begin prior to the fall of 1994. In February 1993, GSU and the other affected utilities were served with a federal grand jury subpoena to produce documents and other information relating to the fire barrier material used in the plant. Nothing in the subpoena indicates that GSU or any employee is a target of the grand jury investigation. GSU is cooperatmg fully with the govemment in its investigation. The requested documentation and other information wem produced in March 1993, and no additional requests have been received. On October 25,1993, the NRC staff began an operational safety team inspection at River Bend that was concluded by mid-November 1993. The NRC held the inspection to verify that the plant is being operated safely and in conformance with regulatory requirements. The team's findings were discussed at a public meetmg in November 1993, and a written inspection report was issued in January 1994. The inspection team found apparent violations in two categories: (1) procedure adequacy, and (2) concerns with the corrective action program. Due to the nature of these apparent violations, an enforcement conference was not warranted and no fine was proposed. State Regulation General. Each of the System operating companies is subject to regulation by its respective state and/or local regulatory authorities with jurisdiction over the senice areas in which each company operates. Such regulation includes authority to set rates for electric and gas service provided at retail. (See " Rate Matters and Regulation - Rate Matters - Retail Rate Matters." above) AP&L is subject to regulation by the APSC and the Tennessee Public Senice Commission (TPSC). APSC regulation includes the authority to set rates, determine reasonable and adequate service, fix the value of property used and useful, require proper accounting, control leasing, control the acquisition or sale of any public utility plant or propeny constituting an operating unit or system, set rates of depreciation, issue certificates of convenience and necessity and certificates of environmental compatibility and public need, and control the issuance and sale of securities. Regulation by the TPSC includes the authority to set standards of service and rates for senice to customers in the state, require proper accounting, control the issuance and sale of securities, and issue certificates of convenience and necessity. GSU is subject to the jurisdiction of the municipal authorities ofincorporated cities in Texas as to retail rates and senices within their boundaries, with appellate jurisdiction over such matters residing in the PUCT. GSU is also subject to regulation by the PUCT as to retail rates and services in rural areas, certiScation of new generating plants, and extensions of senice into new areas GSU is subject to regulation by the LPSC as to electric and gas senice, rates and charges, certification of generating facilities and power or capacity purchase contracts, and other matters. LP&L is subject to the jurisdiction of the LPSC as to rates and charges, standards of senice, depreciation, accounting, and other mat *ers, and is subject to the jurisdiction of the Council with respect to such matters within Algiers. l Mr' kL is subject to regulation as to service, senice areas, facilities, and retail rates by the MPSC. MP&L ' is also sub9et to regulation by the APSC as to the certificate of enviraamaa' I cortpatibility and public need for the Independence Station. NOPSI is subject to regulation as to electric and gas senice, rates and charges, standards of service, ,
' depreciation, accounting, issuance of certain securities, and other matters by the C&~il Fmnchises. AP&L holds franchises to provide electnc sernce in 301 incorporated cities and towns in j
Arkansas, all of which are unlimited in duraten and termmable by either party, GSU holds non-exclusive franchises, permits, or certificates of convemence and necessity to provide electric and gas service in 55 incorporated villages, cities, and towns in Imisiana and 64 iseg .;ai cities and towns in Texas. GSU ordmarily holds 50-year franchises in Texas towns ' 60-year francinaam in lausiana 7-2036 in Ter.as and in the years towns The present terms of GSU's electric fraachi- will expire in the years 2015-2046 in Louisiana The natural gas francluse in the City of Baton Rouge i expirein the yont 2015. LP&L holds franchises to provide electric service in 116 incorporated nllages, cities, and towns. Most of these franchises have 25-year terms expiring during the period 1995-2015. However, six of these numicipahcies have granted 60-year franchises, with the last one expiring in the year 2040. Of these fr==eki , nosu has expired to date, one is scheduled to egire as early as 1995, and 37 are echarblari to expire by year <md 2MO. LP&L also supplies electric service in 353 umncorporated communities, all of which are located in panshes (counties) from which LP&L holds franchises to serve the areas in which the umacorporated commumties are lacarani MP&L has received from the MPSC certificates of public convemence and necessity to provide electnc sersice to the areas of Mississippi that MPAL serves, which include a number of mumcipalities. MPAL contmues to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence NOPSI provides electric and gas service in the City of New Orleans pursuant to city ornhnances, which state, among other thmgs, that the City has a continuing optaon to purchase NOPSI's electric and gas utahty properties. 1 System Energy has no franchises from any municipality or state. Its busmess is currently hmited to wholesale sales of power. Environmental Reenlation Geneml. In the ancas of air quality, water quahty, control of toxic substances and hazardous and solid .] wastes, and other environmental matters, the System operatmg compames, System Energy, Entergy Power, and Entergy Operations are subject to regulation by various federal, state, and local authorities. Each of the Entergy l companies considers itself to be in substantial compliance with those environmental regn1=hana currently cpp to its business and operations. Entergy has incurred increased costs of construction and other increased costs in ; 2 - meeting environmental protection standards. Because envis= ^ 1 regulaticas are canhanally ek-= pas the ultimate compliance costs to Entergy cannot be precisely a=+i==*ad at any one time. Iloweven, Fasergy currently estunates that its potential capital expenditures for environmental control purposes, 'r +-N those discussed in
" Clean Air legislation," below, will not be material for the System ac s whole
Clean Air Legislation. He Clean Air Act Amendments of 1990 (the Act) place limits on emissions of sulfur dioxide and nitrogen oxide from fossil-fueled generating plants. Entergy has evaluated the Act to determine the impact on the System's overall cost of emission control and monitoring equipment. Based upon such evaluation in connection with existing generating facilities, the System has determined that no additional control equipment will be required to control sulfur dioxide. In the area served by GSU, control equipment will be required for nitrogen oxide reductions due to the ozone nonattainment status of the Baton Rouge, Louisiana and Beaumont and Houston, Texas air quality control regions no later than May 1995. The cost of such control equipment is estimated at $16.0 million. He remamder of the System may be required to install nitrogen oxide emission controls on its coal units by the year 2000. He EPA is currently drafbng rules that will determme the lewis of nitrogen oxide emissions that will be allowed by affected units. Under the latest EPA-proposed regulations on nitrogen oxide, Entergy would not have to install additional controls. It is not possible to determme at this time if the fmal regulations promulgated by EPA would require the System's coal units to install nitrogen oxide emission controls. Should additional controls be required, the overall cost would vary depending on the ewntual emission levels that are set. In addition, the System will be required to install additional continuous emission monitoring equipment at its coal units to comply with fmal EPA regulations. It is estimated that the continuous emission monitoring systems could cost as much as $1.0 million for all of the coal units. Final EPA regulations established the acceptable continuous monitoring methods, as well as alternative monitoring methods, that make it possible to determme the compliance of the units with respect to emission levels through fuel sampling and other estimation methods. Capital expenditures of approximately $11.0 million are estimated for continuous emission monitoring systems at the other fossil-fueled units. He authority to impose permit fees has been delegated to the states by EPA and, depending on the extent of the state program and the fees imposed by each state regulatory authority, permit fees for tha 9ystem could range from $1.6 to $5.0 raillion annually. There are several other areas, such as air toxins and visibility, that will require regulatory study and rule promulgation to determine whether pollution control equipment is necessary. Regarding sulfur dioxide emissions, the Act provides " allowances" to most Entergy units based upon past emission levels and operating characteristics. Each unit of allowance is an entitlement to emit one ton of sulfur dioxide per year. Under the Act, utilities will be required to pcssess allowances for sulfur dioxide emissions from affected units. Based on Enterg/s past operating nistory, it is considered a " clean" utili:y and as such will receive more allowar.ces than are currently necessary for normal operatroas. He System believes that it will be able to operate its units efficiently without installing scrubbers or purchasing allowances from outside sources, and the System may have excess allowances available for sale to other utilities. j Entergy currently estunates that total capital costs of approximately $39.4 million could be required to { comply with the Act. Rese estimated costs for each legal entity are as follows: 1 Nitrogen Continuous Company Oxide Emissions Control 3fonitors I_qtal (In Thousands) 5 7,275 5 3,300 $10,575 AP&L 16,000 4,900 20,900 GSU
- 2,300 2,300 LP&L 2,500 1,500 4,000 MP&L -
NOPSI - System Energy 1.575 - 1575 l Entergy Power ! Total Entergy System $27.350 $12.000 $39.350 Other Environmental Matters. Le provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (Superfund), among other things, authorize the EPA and, indirectly, the states to require the generators and certain transporters of certain hazardous substances released fro or at a site, and the owners or operators of such site, to clean up the site or reimburse the costs therefor, nis statute has been interpreted to impose joint and several liability on responsible parties. In compliance with applicable laws and regulations at the time, the System operating companies have sent waste matenals to various disposal sites over the years. Also, past operating procedures and maintenance practices, which were not subject regulation at that time, are now regulated by various emironmentallaws. Some of these sites have been the subject of govemmental action, thereby causing one or more of the System operatmg companies to be involved with site cleanup activities. The System operating companies have participated to various degrees in accordance with their i potential liability with these site cicanups and have, therefore, developed experience with cleanup costs. Their experience in these matters, and their judgments related thereto, are utilized by them in evaluating these sites. In addition, the System operating companies have established reserves for environmental clean-up/ restoration activities. AP&L AP&L has received notices from time to time between 1989 and 1993, from the EPA, the Arkansas Department of Pollution Control and Ecology (ADPC&E), and others that it (among numerous others, including various utilities, municipalities and other governmental units, and major corporations) may be a PRP for cleanup costs associated with various sites in Arkansas. Most of these sites are neither owned nor operated by any System company. Contaminants at the sites include principally polychlorinated biphenyls (PCB's), lead, and other hazardous wastes. Rese sites and others are described below. AP&L received notices from the EPA and ADPC&E in 1990 and 1991, identifying it as one of 30 PRP's (along with LP&L and GSU) at two Saline County sites in Arkansas Both sites are believed to be contaminated with PCB's and lead. Cleanup costs for both sites are estimated at $6.0 million, with AP&L's total share of the costs being estunated at approxunately $2.0 million. AP&L to date has expended approximately $1.0 million for remediation at one of these sites. He total liability cannot be precisely determmed until remediation is complete at both sites. AP&L believes its potentialliability for these sites will not be material. l Reynolds Metals Company (RMC) and AP&L notified the EPA in 1989, of possible PCB contammation at two former RMC plant sites in Arkansas to which AP&L had supplied power. AP&L completed remediation at the substations serving the plant sites at a cost of St.7 million. Additional PCB contanunation was found in a portion of a drainage ditch that flows from the RMC's Patterson facility to the Ouachita River RMC has demanded that AP&L participate in the remediation efforts with respect to the ditch. AP&L and independent contractors engaged by AP&L conducted an investigation of the ditch contammation and the potential migration of PCB's from the
electrical equipment that AP&L maintained at the plant. The invcstigation concluded that little, if any, of the contanunation was caused by AP&L. AP&L's expenditures thus far on the ditch have been approximately $150,000. It is AP&L's understandmg that RMC has spent approximately $10.0 million to complete remediation of the ditch contammation. AP&L has not received a notice from the EPA that it may be a PRP with respect to remediation costs for this site. However, RMC is seeking reimbursement of $5.0 million (50% of expenditures) from AP&L. AP&L continues to deny responsibility for any of such remediation costs and believes that its potential liability, if any, for this site will not be material. AP&L entered into a Consent Admmistrative Order dated February 21, 1991, with the ADPC&E that named AP&L as a PRP for cleanup of contamination associated with the Utilities Sersices, Inc. state Superfund site located near Rison, Arkansas Such site was found to have soil contammated by PCB's and pentachlorophenol (a wood preservative chemical). Also, containers ar,d drums that contamed PCB's and other hazardous substances were found at the site. AP&L's share of total remediation costs are estunated to range between S3.0 million and $5.0 million. AP&L is attempting to identify and notify other PRP's. AP&L has received assurances from the ADPC&E that it will use its enforcement authority to allocate remediation expenses among AP&L and any other PRP's that can be identified (approxunately 30 - 35 have been identified to date). AP&L has performed the activities necessary to stabilize the site, which to date has cost approximately $114,000. AP&L believes that its potential liability for this site will not be material. AP&L received Notice of Potential Liability and a Demand for Payment in November 1992 from the EPA in conjunction with a contammated site in Union County, Arkansas AP&L was identined as one of eleven PRP's, which also include LP&L. The EPA has already completed cleanup of the site. An agreement has been negotiated with the EPA which detennined AP&L to be a de muumis party with total liability of approximately S47,000. As a result of an internal investigation, AP&L has discovered soil contammation at two AP&L owned sites located in Blpheville, Arkansas and Pine Bluff, Arkansas The contammation appears to be a result of past operating procedures that were performed prior to any applicable emironmental regulation. AP&L is still investigating these sites to determme the full extent of the contammation. Until the investigations are complete, AP&L cannot estimate the liabilities associated with these sites. However, AP&L believes its potential liability for both of the sites should not be material. For all of these sites and for certain sites in which remediation has been completed, AP&L has expended approximately $3.2 million for cleanup costs since 1989. i l GSU. GSU has been notified by the EPA that it has been designated 2s a PRP for the cleanup of sites on which GSU and others have, or have been alleged to have, disposed of hazardous materials. GSU is currently negotiating with the EPA and various state authorities regarding the cleanup of some of these sites. Several class action and other suits have been filed seeking relief from GSU and others for damages caused by the disposal of hazardous waste and for asbestos-related disease that allegedly occurred from exposure on GSU premises or on premises on which GSU allegedly disposed of materials (see *Other Rerulation and Litication - GSU," below). l While the amounts at issue in the cleanup efforts and suits may be very substantial rums, management believes that ) its fmancial condition and results of operations will not be materially affected by the outcome of the suits. These ; environmental liabilities are described below. In 1971, GSU purchased certain property near its Sabine generating station for possible cooling water capability expansion. Although it was not known to GSU at the time of the purchase, the property was utilized by area industries in the 1950's and 1960's as an industrial waste dump. GSU sold the property in 1984. In October 1984 the abandoned waste site on the property was included on the Superfund National Priorities List (NPL) by the EPA. The EPA has indicated that it believes GSU to be a PRP for cleanup of the site based on its past ownership. GSU has advised the EPA that it does not believe that it has such responsibility. GSU has pursued negotiations with the EPA and is a member of a task force made up of other PRP's for the voluntary cleanup of the waste site. A Consent Decree has been signed by all parties. Because additional wastes have been discovered at the site since the I original cleanup costs were estimated, the total costs for the voluntary cleanup are unknown. However, it is estimated that cleanup will exceed $15.0 million. GSU has negotiated a responsible share of 2.26% of the estimated cleanup cost. Federal and state agencies are presently exammmg potential liabilities associated with natural resource damages. His matter is currently under negotiation with the other PRP's and the agencies. Remediation of the site is expected to be completed in 1996. In March 1993, GSU completed its cleanup activities at a site in Houston, Texas, which is included in the NPL. On September 20,1993, GSU received formal notification from the EPA ofits acceptance of the remedial activities conducted at the site. Currently, other parties are conducting cleanup activities at the site. However, these cleanup activities are unrelated to GSU's involvement at the site. nrough 1993, GSU incurred cleanup costs of approximately $3.3 million. Pursuant to the Consent Decree, GSU is responsible for oversight costs incurred by the EPA. GSU has not received a reimbursement request for outstanding oversight costs, but anticipates these costs may total between $250,000 and $500,000. GSU is pursuing contribution for the cleanup costs at the site from other parties believed to be potentially responsible. GSU is currently involved in a multi-phased remedial investigation of an abandoned manufactured gas plant (MGP) site Ic ed in Lake Charles, Louisiana. He property was the site of an MGP that is beliewd to have operated durir 2 period from approximately 1916 to 1931. Coal tar, a by-product of the distillation pecess, was apparently rot. J to a portion of the property for disposal. Since GSU purchased the property in 1924 the same area has been tilled with soil and used as a landfill for miscellaneous items including electrical poles, electrical equipment, and other debris. Under an Order by the Louisiana Department of Environmental Quality (LDEQ), which is currently stayed, GSU was required to investigate and, if necessary, take remedial action at the site. The EPA has notified GSU that it is performing an independent review and rankmg of the site to detemune whether the site should be listed on the NPL. Another PRP has been identified and is believed to have had a role in the ownership and operation of the MGP. Negotiations with that company for joint participation and any remedial action are expected to continue. GSU currently is awaiting notification from the EPA before initiatmg additional cleanup negotiations or actions. While studies to determine the location of the coal tar have been conducted, the cleanup costs of the site are unknown. GSU does not presently believe that its ultimate responsibility with respect to this site will be material. GSU has also been advised that it has been named as a PRP, along with a number of other companies (including LP&L), for an abandoned waste oil recycling plant site in Livingston Parish, Louisiana, which is included on the NPL. Although significant remediation has been completed, additional studies are expected to continue in 1994. GSU and LP&L have been named as defendants in a class action lawsuit lodged agamst a group of PRP's associated with the site. (For information regarding litigation in connection with the Livingston Parish site, see "Q1her Reculation and Litigation - GSU," below.) GSU does not presently believe that its ultunate responsibility I with respect to this site will N material. GSU received notification in 1992 from the EPA of potential liability at a site located in lota, Louisiana. His site accepted a variety of wastes, including medical and chemical wastes. In addition to GSU, over 200 parties have been named as PRP's. He EPA is continuing its investigation of the site and has notified the PRP's of the possibility of this site being linked to another site. To date, GSU has not received notification ofliability with regard to the other site. GSU does rot presently believe its ultimate responsibility with respect to this site will be material. GSU has also been notified by the EPA of potential liability at two sites located in Saline County, Arkansas It is believed that both sites served as a salvaging facility for transformers and batteries. In addition to GSU,32 other parties (including AP&L and LP&L) have been named as PRP's. At this time, GSU's involvement with the site is unknown. GSU does not presently believe that its ultimate responsibility with respect to ttus site will be material. I In November 1993, GSU received informal notification from the Rhode Island Department of Emiromaental Management regarding a site at which electrical capacitors had been located The State traced several of these ! l 3
i l I capacitors to GSU. GSU records indicate these capacitors were returned under warranty to the manufacturer in the i 1960's due to defects. GSU does not presently believe it is responsible for any alleged actisities occurring at this site. As o' Dwember 31,1993, GSU had expended $7.0 million toward the cleanup of such sites. In 1990, GSU received an order from the LDEQ to reduce emissions of nitrogen oxides and reactive hydrocarbons at its Willow Glen and Louisiana Station plants located near Baton Rouge, Louisiana. GSU has requested an adjudicatory hearing on the matter, which the LDEQ secretary has deemed as staying the order. In the interim, GSU has joined several other Baton Rouge industries to develop and submit to LDEQ a comprehensive set of short- and long-range reduction plans. In 1993, LDEQ adopted regulations requiring permanent reductions in nitrogen oxides emissions at Willow Glen and Louisiana Station and is considering requirements for further reductions. The estimates for actions necessary to comply with these regulations are included in the discussion under
" Clean Air Legislation," above. GSU believes these regulations implement the intent of the 1990 order, and actions beyond those required by the regulations will not be required.
LP&L and NOPSI. LP&L and NOPSI have received notices from time to time between 1986 and 1993 from the EPA and/or the states of Louisiana and Mississippi that each or either of the companies may be a PRP for cleanup costs associated with disposal sites that are currently in various stages of remediation in Arkansas, Illinois, Louisiana, Mississippi, and Missouri that are neither owned nor operated by any System company. As to one Missouri site, LP&L's and NOPSI's aggregate liability is currently estimated not to exceed $558,000, and because of the type and the large number of PRP's (over 700, including many large utilities and national and international corporations), LP&L and NOPSI do not expect liabilities in excess of this amount. For the other Missouri site, LP&L and the other 64 PRP's (including several large, creditwordly utility companies) have received an EPA demand to pay approximately $1.2 million expended by the EPA. In June of 1993, LP&L paid $12,392 in full payment ofits share of the cleanup costs. LP&L considers cleanup at this site to be complete. As to the two Saline County, Arkansas sites (involving AP&L, GSU, and LP&L), LP&L has been advised that current estimates for total cleanup are approximately $6.0 million. LP&L believes that, because of the number and nature of the PRP's, its expos tre for these sites will not be material. Initial indications are that LP&L was involved in the Saline sites, but LPAL believes that because of the limited scope ofits involvement and the number and nature of PRP's, its exposure for these sites will not be material. l LP&L received notice from the EPA in November 1992, that it (along with AP&L) was involved in the ! Union County, Arkansas site. An agreement has been negotiated with the EPA that determined LP&L to be a de l minimis party with a total liability of approximately $47,000 (see "AP&L," above.) l As to the Mississippi site, LP&L (along with System Energy) understands that EPA has expended approximately $740,000 for this cite (three separate locations being treated adnunistratively as one). He State of Mississippi has indicated it intends to have PRP's conduct a cleanup of the site but has not yet taken formal action. LP&L has expended $22,300 to settle with the EPA for its costs for this site and, because there are 44 PRP's for this site (including a number of major oil companies), does not expect its share of future costs to be material. l l For a Livingston Parish, Louisiana site (invohing at least 70 PRP's, including GSU and many other large l and creditworthy corporations), LP&L has found in its records no evidence of its involvement. (For information ) regarding litigation in connection with the Livingston Parish site, see "Other Reculation and Litiration - LP&L," below.) At a second Louisiana site (also included on the NPL and invohing 57 PRP's, including a number of major corporations), NOPSI believes it has no liability for the site because the material it sent to the site was not a l hazardous substance. For the Illinois site, NOPSI, upon its review of the site documentation and ofits own records, has asserted to the EPA that it has no involvement in this site. However, NOPSI is participating with other PRP's (including many large and creditworthy corporations) as a prudent means of resolving pctential liability, if any. For all these sites, LP&L has expended approximately $349,000 and NOPSI has expended approximately 5172,000 for cleanup costs (commencing in 1986) to date. I During 1993, LP&L performed prelimmary site assessments at the locations of two retired power plants previously owned and operated by two Louisiana municipalities. LP&L had purchased the power plants by agreement (as part of the municipa! electric systems) aAer operatmg them for the last few years of their useful lives. The assessments indicated some subsurface contammation from fuel oil. LP&L and the LDEQ are now reviewing I site remediation procedures that LP&L ntst" will not exceed 5650,000 in the aggregate. During 1993, the LDEQ issued new rules for solid waste regulation, including waste water impoundments. I LP&L has determined that certain of its power plant waste water impoundments are affected by these regulations and has chosen to close them rather than retrofit and permit them. The aggregate cost of the impoundment closures, tc : completed by 1996, is estimated to be $7 ' million. System Energy. In February 1990, System Energy received an EPA notice that it (among numerous other companies) may be a PRP for cleanup costs associated with the same site in Mississippi in which LP&L is involved. Potential liability is based on the alleged shipment of waste oil to the site from 1981 to 1985. System _ Energy does not expect its share of the total expenditures to be material because there are 44 PRP's for this site, including a number of major oil companies. Other Regulation and Litiration Entergy Corporation and GSU. In July and August 1992, Entergy Corporation and GSU Sled applications with FERC, the LPSC, and the PUCT, and Entergy Corporation, Entergy Oi>erations, and Entergy Services filed an application with the SEC under the Holding Company Act, seekmg authorization of various aspects of the Merger. In January 1993, GSU filed two applications with the NRC seekmg approval of the change in ownership of GSU and an amendment to the operating license for River Bend to reflect its operation by Entergy j Operations. All regulatory approvals were obtained in 1993 and the Merger was consummtM on December 31, 1993 (see " Business of Entergy - Enterry Corooration-GSU Mercer " above, for further information). Requests for rehearmg of certain aspects of the FERC order were filed on January 14,1994, by 14 parties, including Entergy Corporation, the APSC, the Mississippi Attorney General, the LPSC, the MPSC, the Texas Office of Public Utility Counsel, and the PUCT. Entergy Corporation, the LPSC, the Texas Office of Public Utility Counsel, and the PUCT are requesting FERC to restore a 40% cap on the amount of fuel savings GSU may be required to transfer to other Entergy operating companies under a tracking mechanism designed to protect the other companies from certain unexpected increases in fuel costs. The other parties are seekmg to overturn FERC's decision on various grounds. Requests for rehearing of the SEC order were filed with the SEC by Houston Industries Incorporated and Houston Lighting & Power Company on December 28,1993, and petitions for review seeking to set aside the SEC order were filed with the D.C. Circuit by these parties on February 15,1994 and by Cajun on February 14,1994. See " Nuclear Ooerations - River Bend," above for information on challenges to the NRC's approval of GSU's applications. Appeals seeking to set aside the LPSC order related to the Merger were filed in the 19th Judicial District Court for the Parish of East Baton Rouge, Louisiana, by Houston Lighting & Power Company on August 13, 1993, and by the Alliance for Affordable Energy, Inc. on August 20,1993. Subsequently, on February 9,1994, Houston Lighting & Power Company filed a motion voluntarily dismissing its appeal.
i l AP&L nree lawsuits (which have been consolidated) were filed in the Arkansas District Coun by l numerous plaintiffs agamst AP&L and Entergy Services in connection with the operation of two dams during a period of heavy rainfall and flooding in May 1990. The consolidated lawsuits sought approximately $14.4 million in property losses and other compenst. tory damages, and $500 million in punitive damages. In their responses to these complaints, AP&L and Entergy Services asserted, among other things, that AP&L owns flowage easements i giving it the permanent right to inundate the lands owned or occupied by the plaintiffs in connection with the ; operation of the dams. In June 1991, the Arkansas District Court granted summary judgment to AP&L with respect to the enforceability ofits flowage easements. In November 1991, the Arkansas District Coun ruled that Entergy Services was entitled to the benefit of AP&L's flowage casements, in effect, removing from consideration damages in the approximate amount of $13.5 million alleged to have occurred within the areas covered by the casements. As a renit, over 300 plaintiffs claiming damage within the casements were dismissed from the consolidated case in December 1991. Certain plaintiffs appealed these orders to the Eighth Circuit, which appeal was denied in March 1992. Following the Eighth Circuit's denial of their interlocutory appeal from the Arkansas District Court's orders, cenain of the plaintiffs, without prejudice to their right to refile, voluntarily dismissed their claims which had not been disposed of in the Arkansas District Coun's orders, thus makmg the orders a final adjudication, and appealed these orders to the Eighth Circuit. He remammg plaintiffs obtained a stay and an adrninictrative termmation of their claims, pending the outcome of the appeal. In December 1993, a three-judge panel of the Eighth Circuit Sled its opinion affirming the judgment of the Arkansas District Coun and entered judgment accordingly. The plaintiffs appealing the Arkansas District Coun's orders filed petitions with the Eighth Circuit for a rehearing by the entire Court sitting en banc, which petitions were denied. He plaintiffs may petition the U.S. Supreme Court to issue a writ of certiorari to permit its review of the Eighth Circuit's decisions. Neither AP&L nor Entergy Services can predict whether the U.S. Supreme Court will grant such a petition, if one is filed. GSU. Between 1986 and 1993, GSU and approximately 70 other defendants, including many national and intemational corporations, including LP&L, have been sued in 17 suits in the Lisingston Parish, louisiana District Court (State District Coun) by a number of plaintiffs who allegedly suffered damage or injury, or are survivors of persons who allegedly died, as a result of exposure to " hazardous toxic waste" that eman*d from a site in Livingston Parish. He plaintiffs alleged that the defendants generated, transported, or participated in the storage of such wastes at the facility, which was previously operated as a waste oil recycling facility. These State District Coun suits, which seek damages in total amounts ranging from $1.0 million to $10.0 billion and are now consolidated in a class action, and three federal suits in three states other than louisiana involving issues arising from the same facility, have been removed and transferred, respectively, to the U.S. District Court for the Middle District of Louisiana (Federal District Court). Motions to remand the class action to the State District Court have been filed, and procedural issues regarding the federal suits are being considered as well. It is not known what effect any action taken on these motions and issues, whenever taken by the Federal District Coun, would have on the April 11, 1994 State District Court trial date that was established before the suits were removed to Federal District Court; but it is unlikely such trial date will be met. He matter is pending. In October 1989, an amended lawsuit petition was filed on behalf of 985 plaintiffs in the District Court of Jefferson County, Texas, 60th Judicial District in Beaumont, Texas, nammg 55 defendants including GSU. In February 1990, another amended lawsuit petition was filed in a different state District Court in Jefferson County, Texas, on behalf of over 200 plaintiffs (subsequently amended to include a total of 660) nammg 127 defendants including GSU. Possibly 300 to 400 or more of the plaintiffs in Texas may have worked at GSU's premises. At least five other individual suits have been filed in Beaumont against GSU and others, seeking damages for alleged asbestos exposure. All of the plaintiffs in such suits are also suing GSU and all other defendants on a conspiracy ( count. There are 25 asbestos-related law suits filed in the 14th Judicial District Court of Calcasieu Parish in Lake I Charles, Louisiana, on behalf of an aggregate of 53 plaintiffs narmng from 16 to 24 defendants including GSU, and GSU is aware of as many as 61 additional cases that may be filed. The suits allege that each plaintiff contracted an l
- asbestos-related disease from exposure to asbestos insulation products on the premises of such defendants.
Management believes that GSU has meritorious defenses, but there can be no assurance as to the outcome of these l cases or that additional claims may not be asserted. In asbestos-related suits agamst the manufacturers, very l
. ___ . _. . _ . _ . . .- _ ._. -_ _-~ _ . _ _. _
substantial recoveries have been achieved by large groups of claunants GSU does not presently believe that the ultimate resolution of these cases will materially adversely affect the financial position of GSU. On February 3,1984, Dow Chemical Company filed a request with the LPSC for a heanng to consider - issues related to the purchase of cogenerated power by GSU. Other industries subsequently filed simdar requests and the matters were consolidated. In November 1984, the LPSC completed hearmgs on rules, policies, and pricing methodologies applicable to cogeneration. Key issues were whether or not (1) GSU should be required to pay the industries for avoided capacity costs, and (2) GSU should be required to wheel power to or from the industnal
~
plants. While the matter is still pending before the LPSC, the LPSC did set interim rates, subject to refund by either Dow or GSU, which exclude capacity costs. GSU has significant business relationships with Cajun, pnmarily co-ownership of River Bend and Big Cajun 2 Unit 3. GSU and Cajun own 70% and 30% of River Bend, respectively, while Big Cajun 2 Unit 3 is owned 42% and 58% by GSU and Cajun, respectively. GSU op.4 s River Bend and Cajun operates Big Cajun 2 Unit 3. GSU was requested by Cajun and Jefferson Davis Electnc Cooperative, Inc., (Jefferson Davis) to provide transmission of power over GSUs system for delivery to the Industrial Road area near Lake Charles, Louisiana. GSU provides electric service to industrial and other customers in such area, and Cajun and Jefferson Davis do not. On October 10,1989, Cajun filed a complaint at FERC contanding that GSU wrongfully refused to provide Cajun
~
certain transmission services so that its member, Jefferson Davis, could provide service to certain industrial customers, and it requested FERC to order GSU to provide the service. On October 26,1989, FERC m i rily dismissed Cajun's complaint, but the D.C. Circuit reversed FERC's summary determmation and remanded the case to FERC for a heanng. On June 24,1992, after a heanng, an ALJ issued an Initial Decision, again' ^== Cajun's complaint. The ALJ found that the parties' contract did not require GSU to provide the service and that Crjun's member, Jefferson Davis, had not sought permission from the LPSC to serve the end-use customers in question. If Jefferson Davis secured permission from the LPSC, the ALJ believed (but did not decide) that FERC would require GSU to provide the requested transmission service. Both Cajun and GSU have filed exceptions to the ALJ's decision, and the matter is pendmg before FERC. Lajun and Jeffersoc Davis also brought a related action in federal court in the Western District of Louisiana alleging that GSU breached its obligations under the parties' contract and violated the antitrust laws by . refusing to provide the transmission service described above Cajun and Jefferson Davis. seek an injunction requiring GSU to provide the requested service and unspecified treble damages for GSU's refusal to provide the service. On November 9,1989, the district court judge denied Cajun's and Jefferson. Davis' motion for a preliminary injunction. On May 3,1991, the judge stayed the pr*~ ding pendmg final resolution of the matters still pending before FERC. GSU and Cajun are parties to FERC pr-~diage regarding certain long-s ding disputes relating to transmission service charges. Cajun asseit: that GSU has improperly applied the terms of a rate schedule, Service . Schedule CTOC, to its billings to Cajun and it seeks an order from FERC diwag GSU to recompute the bills. GSU asserts that Cajun underpaid its bills, and it seeks an order directing Cajun to pay surcharges to make up the underpayments. On April 10, 1992, FERC issued an order affirming in part and reversing in part an ALJ's recommendations. Both GSU and Cajun have requested reheanng, and the requests are still panding In addition, on August 25,1993, the United States Court of Appeals for the Fifth Circuit reversed portions, of FERC's order previously decided adversely to GSU,- and remandad the' case to FERC for further pr~-diag =. On 3 January 13,1994, FERC rejected GSUs proposal to collect an interim surcharge while FERC considers the court's remand GSU interprets FERC's 1992 order and the Court of Appeals decision to mean that Cajun owes OSU approximately $85 million through December 31,1993. If GSU also prevads on all of the issues raised in its
. pending request for rehearing of FERC's earlier orders, then GSU estimates that Cajun would owe GSU approximately $118 million through December 31,1993. If GSU does not prevail on its reheanng request, and Cajun prevails on its reheanng request, and if FERC rejects the modifications GSU 1,rprets the court of appeals 40 l
to have directed, then GSU would owe Cajun an estimated $76 million through December 31, 1993. Pending FERC's ruling on the May 1992 motions for rehearing, GSU has continued to bill Cajun utilizing the historical billing methodology and has booked underpaid transmission charges, including interest, in the amount of $140.8 million as of December 31,1993. His amount is reflected in long-term receivables and in other deferred credits, with no effect on net income. On December 7,1993, Cajun filed a complaint in the Middle District of Louisiana alleging that GSU failed to provide Cajun an opportunity to construct certain facilities that allegedly would have reduced its rates under Service Schedule CTOC, and Cajun seeks an order compelling the conveyance of certain facilities and unspeci5ed damages. GSU has moved to dismiss the complaint on the basis, among others, that FERC has already addressed the matter in the proceedmgs described above. In May 1990, GSU received a subpoena from the Office of Inspector General - Investigations, United States Department of Agriculture, seeking production of documents relatmg to the construction costs of River Bend. Such office is authorized to investigate matters relating to programs of the Depanment of Agriculture. GSU has been sued by Cajun with respect to its participation in River Bend with funds made available through Department programs admmistered by the REA. GSU has failed in its efforts to have the REA made a party to the Cajun litigation. GSU does not know the purpose of such Office's investigation, but presently assumes that it relates to the Cajun civil litigation since the production of documents sought by such Office is simdar to that sought by Cajun in its action against GSU. However, there can be no assurance given by GSU as to the real purpose of such Office's investigation. Among other areas of responsibility, such office is authorized to investigate possibic violations oflaw. GSU believes the subpoena proceedmg has been adminictratively dismissed without prejudice to the parties. On December 2,1991, Cajun filed a complaint seeking declaratory and injunctive relief from the U. S. District Court for the Middle District of Louisiana. He complaint concerns GSU's position that Cajun is in default with respect to paying its share of certain expenditures to repair corrosion damage in the service water system, to repair a feedwater noi.zle crack, and to repair a turbine rotor. Cajun alleges that it has no obligation to pay its share of such costs and seeks a declaration that it may elect not to participate in the fundmg of such costs and enjoining GSU from demanding payment therefor or attempting to implement default provisions in the Operating Agreement with respect thereto. Cajun alleges that ifit is required to pay its share of such costs it would be forced to default on other obligations and would be forced to seek relief in bankruptcy. GSU believes that Cajun is in default under the provisions of the Operating Agreement. No assurance can be given as to the outcome or timing of this action brought by Cajun. On November 25, 1992, Dixie Electric Membership Corporation and Southwest Louisiana Electric Membership Corporation, both members of Cajun, filed suit in the U.S. District Coun for the Western District of Louisiana seeking a declaration that the River Bend Joint Ownership Agreement between GSU and Cajun is void because an allegedly required approval of the LPSC was not obtamed, his suit has been transferred from the Western District to the Middle District, and is being processed in conjunction with the suit described in the following paragraph. GSU believes the suit is without merit. In June 1989, Cajun filed a civil action agamst GSU in the U. S. District Court for the Middle District of Louisiana. Cajun stated in its complaint that the object of the suit is to annul, rescind, termmate, and/or dissolve the Joint Ownership Participation and Operating Agreement entered into on August 28,1979 (Operating , Agreement), related to River Bend. Cajun alleges fraud and error by GSU, breach ofits 6duciary duties owed to Cajun, and/or GSU's repudiation, renunciation, abandonment, or dissolution of its core obligations under the Operating Agreement, as well as the lack or failure of cause and/or consideration for Cajun's performance under the Operating Agreement. The suit seeks to recover Cajun's alleged $1.6 billion investment in the unit as damages, plus l attorneys' fees, interest, and costs. In March 1992, the district court appointed a mediator to engage in settlement i discussions and to schedule settlement conferences between the parties. Discussions with the mediator began in l July 1992, however, GSU cannot predict what effect, if any, such discussions will have on the timing or outcome of the case. A trial without c jury is set for April 12, 1994, on the portion of the suit by Cajun to rescind the Operating Agreement. GSU believes the suits are without merit and is contesting them vigorously. No assurance can be given as to the outcome of this litigation. If GSU were ultimately unsuccessful in this litigation and were required to make substantial payments, GSU would probably be unable to make such payments and would probably have to seek relief from its creditors under the Bankruptcy Code. See Note 12 of GSU's Notes to Financial Statements, "Entergy Corporation-GSU Merger," for the accounting treatment of preacquisition contingencies, including a charge resulting from an adverse resolution o litigation with Cajun related to River Bend. In July 1992, Cajun noti 6ed GSU that it would fund a limited amount of costs related to the fourth refueling outage at River Bend, completed in September 1992. Cajun has also not funded its share of the costs associated with certain additional repairs and improvements at River Bend completed during the refueling outage. GSU has paid the costs associated with such repairs and improvements without waiving any rights agamst Cajun. GSU believes that Cajun is obligated to pay its share of such costs under the terms of the applicable contract. Cajun has filed a suit seeking a declaration that it does not owe such funds and seeking injunctive relief agamst GSU. GSU is contesting such suit and is reviewing its available legal remedies. In September 1992, GSU received a letter from Cajun alleging that the operatmg and maintenance con for River i are "far in excess of industry averages" and that "it would be imprudent for Cajun to fund h:se excessi osu." Cajun funher stated that until it is satisfied it would fund a maxunum of $700,000 per week under puest for the remamder of 1992. In a December 1992 letter, Cajun stated that it would also withhold costs associated with certain additional repairs, of which the majority will be incurred during the next refueling outage, currently scheduled for April 1994. GSU believes that Cajun's allegations are without merit and is considering its legal and other remedies available with respect to the underpayments by Cajun. The total resulting from Cajun's failure to fund repair projects, Cajun's fundmg limitation on the fourth refueling outage, and the weekly fundmg limitation by Cajun was $33.3 million as of Deccmber 31,1993, compared with a S28.4 million unfunded balance as of December 31,1992. During 1994, and for the next several years, it is expected that Cajun's share of River Bend-related costs will be in the range of $60 million to $70 million per year. Cajun's weak financial condition could have a material adverse effect on GSU, including a possible NRC action with respect to the operation of River Bend and a need to bear additional costs associated with the co owned facilities. If GSU were required to fund Cajun's share of( s, there can be no assurance that such payments could be recovered. Cajun's weak financial condition cout a affect the ultimate collectibility of amounts owed to GSU. Since 1986, GSU had been in litigation with the Southem Company regarding unit power and long-term power purchase contracts with the Southern Company. GSU entered into a settlement agreement dated December 21,1990, which was consumm*A on November 7,1991, and the settlement obligations were fully satisfied in 1993. In 1986, the PUCT and the LPSC disallowed the pass-through by GSU in its retail rates of the costs of the capacity purchases from the Sou*hern Company, which were being incurred by GSU. GSU appealai the actions the PUCT and the LPSC disallowing pass-through of Southern Company capacity charges to the appropriate state courts. The appeal from the LPSC is pendmg. As part of a settlement of a retail rate case in Texas during the fourth quarter of 1993, GSU has discontinued its appeal of the PUCT disallowance. Following the announcement of the execution of the Reorgmntion Agreement, a purported class action complaint was Sled on June 9,1992, in the District Court 60th Judicial District in Jefferson County, Texas (District Court) agamst GSU and its directors relating to the then proposed business combination with Entergy Corporation. On June 11, 1992, two additional purported class action complaints were filed agamst such defendants in the District Court. All three of the complaints (the Shareholder Actions) were filed by persons alleged to be shareholders of GSU and seeking declaration of a class action on behalf of all persons owning common stock of GSU. GSU has executed a Memorandum of Understanding with counsel for the plaintiffs in these suits agreeing in principle to settle such actions subject to execution of an appropriate stipulation of settlement, approval by the court, and certain other conditions. In the Memorandum, the defendants have denied any actionable acts or omissions and state that they have entered into the Memorandum solely to elimirate the burden and expense of further litigation and to facilitate the consummation of the business combination. 'Ihe Memorandum memorialized certain agreements by GSU and Entergy Corporation for the benefit of shareholders principally in the event the business combination were not consummated, including a covenant to consider reinstitution of dividends on the common stock of GSU in such event. The business combination was consummated on December 31, 1993. Incident to the settlement, the defendants agreed not to oppose an application for attorneys' fees by plaintiffs' counsel that do not exceed $500,000 or for an award of expenses not to exceed $50,000. The individual directors i named as defendants in these complaints are entitled to indemnincation pursuant to GSU's Restated Articles of ! Incorporation, By-laws, and individual indemnity agreements, provided that the terms and conditions of the { I indemnities are satisfied. l LP&L For information regarding litigation in connection with an abandoned waste oil recycling plant site l in Livingston Parish, Ieuisiana, in which LP&L and GSU are defendants, see "GSU," above. LP&L does not believe that it was a generator of any material delivered to this facility and is defending vigorously against the l claims in these suits. Since the mid-1980's, LP&L and the tax authorities of St. Charles Parish, Louisiana (Parish), in which i Parish Waterford 3 is located, have disputed use taxes paid on nuclear fuel ($4.9 million through 1989) under protest by LP&L. LP&L has been successful in a lawsuit in the Parish with regard to recovering these taxes, plus j interest, and also with regard to Parish lease tax issues pertauung to fuel financing arrangements. On the grounds of the previous favorab!c court decisions, LP&L continues to challenge in the courts additional use tax assessments that it has paid to the Parish and to seek additional interest that LP&L claims it is due. Also, in early procedural stages are (1) suits by LP&L with regard to the state use tax on nuclear fuel, and (2) LP&L's defense (and indemnification, if necessary) of nuclear fuel lessors under LP&L's fuel financing arrangements in the suits filed by l the Parish use tax authorities claiming approximately $64.0 million in lease and use taxes. These matters are I pending. . I I System Energy. In connection with an IRS audit of Entergy's 1988,1989, and 1990 consolidated federal income tax retems, the IRS is proposing that adjustments be made to the Grand Gulf 2 abandonment loss deduction ' claimed on Entegy's 1989 consolidated federal income tax retum. If any such adjustments are necessary, the effect on System Ener,ty's net income should be immaterial. Entergy intends to contest the proposed adjestments if finalized by the Ills. The outcome of such proceedmgs cannot be predicted at this time. 1 I l
EARNINGS RATIOS OF SYSTEM OPERATING COMPANIES AND SYSTEM ENERGY ;
'Ibe System oper ng companies and System Energy have calculated rataos of carmngs to fixed charge l
and ratios of earmngs to sd charges and preferred dividends pursuant.to Itera 503 of Regulation S-K of the SEC as follows: Years v.aad C= tr 3L 12 7. E E E E l Ratios of Earnings to Fixed Charges (a) 2.31 2.16 2.25 2.28 3.11(h) AP&L i 1.56 1,72 1.54 GSU 1.16 .80(i) 1.79 2.32 2.40 2.79 3.06 i LPAL 1.04(c) 2.42 2.36_ 2.37 3.79(h) - ! MP&L ' 1.89 2.73 5.66(g) 2.66 4.68(h) NOPSI 2.10 1.74 2.04 1.87' System Energy -(f) Yean E= dad h-- --Mr 3L E E E E E l Ratios of Earmass to Fixed Charges and . Preferred Dividends (a)(b)(c) 1.88 1.81 1.87 1.86 2.54(h) AP&L 1.21
.66(i) .59(i) 1.19 1.37 GSU(d) 2.39 1.39 1.87 1.95 2.18 .
LP&L 1.00(e) 1.93 1.94 1.97 3.08(h) MP&L 1.62 2.36 4.97(g) 2.36 4.12(h) NOPSI , (a) *Earmngs" as defined by SEC Regulation S-K represent the aggregsta of (1) net income, (2) taxes based on' income, (3) investment tax credit adjustments-net, and (4) fixed charges. " Fixed Charges" inchide interest (whether expensed er capitahnd), related amortazation, and interest apphcable to rentals charged to operating expenses.
" Preferred Dividends" as defined by SEC Regulation S-K are counputed by dividag the preferred drvidend (b) ,
requirement by one hundred percent (100%) minus the income tax rate. (c) System Energy's Amendad and Restated Articles of Incorporation do not c .Jy provide for the lamianne o preferred stock. . (d)
"Prefe:Ted Dividends" in the case of GSU also include dividends on y..'a stock.
(c) Earnings for the year ended December 31,1989, include the impact of the writo off of $60 milhan of deferred Grand Gulf 1-reisted costs pursuant to an na . ar.1 between MP&L and the MPSC. l i (f) Earnings for the year ended December 31,1989, were inadequate to cover fixed charges due to System E canoc11ation and write off of its investment in Grand Gulf 2 in b- W 1989. The amount of the coverage deficiency for fixed charges was $745.2 million. l (g) Earnings for the year ended December 31,1991, include the $90 million effect c(the 1991 NOPSI hele= ant. J (h) Earnings for the year ended December 31,1993, include r e y. ..:r.='y $81 nulhon, $52 milhan, and $18 mdhon for AP&L, MPAL, and NOPSI, respectively, related to the change in accounting principle to provide for the l, accrual of estimated unbilled revenues. (i) Earnings for the year ended December 31, 1990, for GSU were not adequate to cover fixed ' charges by } I
$60.6 million. Earnings for the years ended December 31,1990 and 1989, were not adequate to cover fixed charges and preferred dividends by $165.1 million and $190.8 million, Mrdy. Earmngs in 1990 include a
$205 million charge for the settlement of a purchased power dispute.
44
I INDUSTRY SEGMENTS l l NOPSI Narrative Description of NOPSIIndustry *as.3 l Electric Service. NOPSI supplied electric service to 190,613 customers as of December 31,1993. Dunns ; 1993,36% of electnc operanns revenues was derived from r== Mal sales,40% ham commercial sales,6% from 2 industrial sales,15% from sales to governmental and mumcipal customers, and 3% from sales to public utilities and other sources. i Natural Gas Service. NOPSI supplied natural gas servia to 154,251 customers as of December 31,1993. ; During 1993,56% of gas operstmg revenues was derived from resid=nal sales,18% hem commercial sales,9% ; from industrial sales, and 17% from sales to sow . ;.1 and municipal customers. (See " Fuel Supply - Natural ! Gas Purchased for Resale." incorporated herem by reference.) Selected Financial Information Relating to Industry Serments : For selected financial informatma relatmg to NOPSPs industry segments, see NOPSrs flamaani statements ; and Note 11 of NOPSPs Notes to Financial Statemmts, " Business _W Informanon," incorporated herem by ! reference. ; i Emolovees by Serment , I NOPSrs full-time employees by industry segment as of December 31,1993, were as follows: , i Electric 568 Natural Gas lit : Total 211 ! (For further information with respect to NOPSPs segments, see "P.%Tf.") ; GSU , For the year ended December 31,1993, %% of GSU's operatag revenues were derived from the electric I utility business. 'Ihe remai* of w. hug revenues were derived 2% &am the stenra busmess and 2% from the ! natural gas business. Segment information for GSU is not provided. f, l i I s I
PROPERTY ; Generatine Stations ,
"Ihe total capability of Entergy 's owned and leased generating stations as of December 31,1993, by company, is iadie='d below:
Owned and 1*==4 Canability MW(li i Gu. ; Turbine - - and ; Fossil ~ Internal Comoany 19.13[ Eps[ Eghat Combustica gr.dist 4,367 (2) 2,373- 1,694 230 (8) 70 -l AP&L 6,420 (2) 5,693 652 (5) 75 - GSU LP&L 5,535 (2) 4,441 1,075 (6) 19 - MPA', 3,046 (2) 3,035 A - 11 - NOP51 927 (2) 912 - 15 - 1.028. - 1.023 (7) - ,,- System Energy Total System 21.323 (3) 16.454 (3)(4) 4.449 J J2 c. (1) " Owned and Imsed Capability" is the dependable load carrymg capability of the stations, as damanarr=ed under , actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to ' utilize. (2) Excludes the capacity of fossil-fueled generating stations placed on extendM reserve as follows: AP&L - 506 MW; . GSU - 405 MW; LP&L - 19 MW;,MP&L - 73 MW; and NOPSI - 143 MW. Generating stations that are not l j : ' expected to be utilized in the near-term to meet load requirements are placed in extended reserve shutdown in order to minimize operating expenans Excludes net capability o'Entergy Power, which owns 809 MW of fossil-fueled capacity (see " Rate Matters and i (3) I Regulation - Rate Matters - Wholesale Rate Matters - EnterEy Power," above).
.J (4) Independence 2, a coal' unit operated by AP&L and jointly owned 25% by MP&L (210 MW), 31.5% by Entergy !
l Power (265 MW), and the balance by various municipalities and a soperative. The unit was out of service, due to f I an explosion Dom August 11,1993 to February 18,1994. f I i '- (5) GSU's nuclear capability represents its 70% ownership interest in River Bend, C4un owns the remanung 30% undivided interest. (6) LP&L's nuclear capability represents its 90.7% ownership interest and 9.3% leasehold interest in Waterford 3. i (7) System Energy's capability represents its 90% interest in Grand Gulf 1 (78.5% ownership interest and 11.5% leasehold interest). South Mississippi Electric Power Association has the remaining 10% undivided ownership ;
. interest in Grand Gulf 1. Entitlement to System Energy's capacity has been allace*M to AP&L, IE&L, MP&L, and NOPSI pursuant to the Unit Power Sales Agreement. [
i (8) Includes 188 MW of capacity leased by AP&L through 1999. Representatives of the System regularly review load and capacity projections in order to coordmate and - . re-m.cr.d the location and time ofinstallation of additional generatmg capacity and ofinterconnections in light of \ I 1 l u _________________ _ _ _ _ _ _ _ _ _ _ _ _ _ , __ __
1 the cvailability of power, the location of new loads, and maximum economy to the System. Based on load and capability projections, the System has no need to install additional generatmg capacity until 1999. To delay the need for new capacity, the System is engaging in conservation and DSM programs, as discussed in " Business of Entergy - Competition - Least Cost Planning," above. When new generation resources are needed, the System plans to meet this need with a variety of sources other than construction of new base load generatmg capacity. In the meantime, the System will meet capacity needs by, among other thmgs, removing generating stations from extended reserve shutdown. Generating stations brought out of extended reserve shutdown during 1993 added 248 MW to meet operating requirements. l l Under the terms of the System Agreement, some of the generating capacity and other power resources are shared among the System operating companies. Among other things, the System Agreement provides that parties ! having generating capacity greater than their load requirements sell such capacity to those parties having deficiencies in generating capacity and that the purchasers pay to the sellers a charge suf5cient to cover certain of the sellers' ownership costs, including operating expenses, fixed charges on debt, dividend requirements on preferred and preference stock, and a fair rate of return on common equity investment Under the System Agreement, these charges are based on costs associated with the sellers' steam electric generatmg units fueled by oil or gas. In addition, for all energy to be exchanged among the System operatmg companies under the System Agreement, the purchasers are required to pay the cost of fuel consumed in generatmg such energy plus a charge to cover other associated costs (see " Rate Matters and Regulation - Rate Matters - Wholesale Rate Matten - System Agreement," above, for a discussion of FERC proceedings relating to the System Agreement). He System's business is. subject to seasonal fluctuations with the peak period occurrmg in the summer months. Excluding GSU, Entergy 's 1993 peak demand of 12,858 MW occurred on August 19,1993. He net System capability at the time of peak was 14,029 MW, which reflects a reduction of the System's total 14,765 MW of owned and leased capability by net off-system firm sales of 736 MW. He capacity margin at the time of the peak was approximately 8.4%, not including units placed on extended reserve and capacity owned by Entergy Power. GSU's 1993 peak demand of 5,612 MW occurred on August 18,1993. ne net GSU capability at the time of peak was 6,704 MW, which reflects an increase of GSU's total 6,420 MW of owned and leased capability by net off-system purchases of 284 MW. The capacity margin at the time of the peak was approxunately 18.2%, not including units placed on extended reserve. Interconnections The electric power supply facilities of Entergy consist principally of steam-electric production facilities strategically located with reference to availability of fuel, protection of local loads, and other controlling economic factors. Rese are interconnected by a transmission system operating at various voltages up to 500 KV. Generally, with the exception of Grand Gulf 1, Entergy Power's capacity and a small portion of MP&L's capacity, operatmg facilities or interests therein aie owned by the System operating company serving the area in which the facilities are located. However, all of the System's generating facilities are centrally dispatched and operated with a view to realizing the greatest economy. This operation seeks, among other things, the lowest cost sources of energy from hour to hour. He nummum of investment and the most efEcient use of plant are sought to be achieved, in part, through the coordmated scheduling of maintenance, inspection, and overhaul. ne System operating companies have direct interconnections with neighboring utilities including, in individual cases, Mississippi Power Company, Sou'.hwestern Electric Power Company, Southwest Power Administration, Central Louisiana Electric Company, Inc., Oklahoma Gas and Electric Company, The Empire District Electric Company, Union Electric Company, Arkansas Electric Cooperative Corporation, Tennessee Valley Authority, Cajun, Sam Raybum Dam Electric Cooperative, Inc., SRG&T, SRMPA, Associated Electric Cooperative, Inc., Municipal Energy Agency of Mississippi, Louisiana Energy and Power Authority, Farmers Electric Cooperative, South Mississippi Electric Power Authority, and the cities of Lafayette, Plaquemme, and New Roads, Louisiana, GSU also has an mterconnection ayw..cr.: with Houston Lighting and Power Cocony providing a nunor amount of emergency service only. De System operatmg companies also have interchange agreements with Alabama Electric Cooperative, Big Rivers Electne Cooperative, Northeast Texas Electric Cooperative, Inc., Sam Rayburn GAT Electric Cooperative, Inc., Florida Power Corporation, Florida Power & Light Company, Jacksonville Electric Authority, Oglethorpe Power Cooperative, the City of Lafayette, Louisiana, the City of Sprirged, Missouri, and East Kentucky Electric Cooperative. De System +4 4 w..penics are members of the Southwest Power Pool, the pnmary purpose of which is to ensure the reliability and adequacy of the electric bulk power supply in the southwest region of the United States. De Southwest Power Pool is a member of the North Amencan Electric Reliability Council. AP&L, ' LP&L, MP&L, and NOPSI are also members of the Western Systems Power Pool. Gas.Prenedr i As of December 31,1993, NOPSI distributed and tre p.t.4 natural gas for distribution solely within the limits of the City of New Orleans through a total of 1,422 miles of gas distribution mams and 32 miles of gas l transmission lines. NOPSI rxcives delivenes of natural gas for distribution purposes at 14 separate locations, , including deliveries from Uni: Gas Pipe Line Company (United) at six of these I.vatums. Of the romanung delivery poets, two are princyally served by interstate suppliers and the remaining are served by merastate j suppliers. . As of C+=*= 31,1993, the gas property of GSU was not matenal to GSU. 1 T.itisa De System's ,.-.Grq stations are generally located on lands owned in fee simple. De greater portion , of the transnussion and distribution lines of the System operstmg companies has been constructed over lands of private owners pursuant to casements or on public highways and streets pursuant to appropriate permits. The rights of each company in the realty on which its properties are located are considered by it to be ad=>* for its use in the conduct of its business. Mmor defects and irregulanties e='-ily found in properties oflike size and , character exist, but such defects and inegularities do not matenally impair the use of the prope: ties affected thereby. De System operstmg cv...yesies generally have the right of eminent domam v4 J,y they may, if l i necessary, perfect or secure titles to, or casements or servitudes on, privately-held lands used or to be used in their. utility operations. l i Substantially all the physical properties owned by each System w.J.g s..y.;.y and System Energy are subject to the lien of the mortgage and deed of trust securing the first mortgage bonds of such company. De Iewis Creek generating station is owned by GSGAT, Inc., and is not subject to the lien of the GSU mortgage secunng the l first mortgage bonds of GSU, but is leased and operated by GSU. In the case of LP&L, certam properties are subject to the liens of ===d mortgages secunng other obligations of LPAL.- In the case of MP&L and NOPSI, l i substantially all of their properties and assets are subject to the second mortgage lien of their respective general and refundmg mortgage bond ind-emes !
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i i
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FUEL SUPPLY The following tabulation shows the percentages of natural gas, fuel oil, nuclear fuel, and coal used in ge ration, excluding that of Entergy Power, during the past three years. It also shows the average fuel cost per KV,H generated by each type of fuel during that period. The balance of generation, which was unmaterial, was provided by hydroelectric power. ENTERGY EXCLUDING GSU Natural Gas Fuel Oil Nuclear Fuel Coal
% Cents % Cents % Cents % Cents of per of per of Per of Per Xes.I Esn M Gsn M Gsn M Esa M 1993 27 2.70 7 2.10 51 .58 15 1.91 1992 32 1.99 - - 49 .67 18 1.90 1991 31 1.64 - - 50 .79 18 1.75 9.El Natural Gas Fuel Oil Nuclear Fuel Coal
*/. Cents % Cents % Cents % Cents of Per of Per of Per of Per Xssr Gsn M Gsn M Esa M Gra M 1993 69 2.44 - - 14 1.19 17 1.77 1992 76 2.01 - - 8 1.64 16 1.68 1991 66 1.79 - - 19 1.24 15 2.08 The following tabulation shows the percentages of generation by fuel type used in generation, excluding that of Entergy Power, for 1993 (actual) and 1994 (projected).
Netur=1 Ces Fuel Oil Nuclear Coal U.92 M M M M M M M System (s) 27% 36 % 7% 3% 51% . 38 % 15 % 23 % AP&L 7 1 - - 60 48 33 51 GSU 69 59 - - 14 21 17 20 LPAL 52 62 1 - 47 38 - - MP&L 24 39 52 27 - - 24 34 NOPSI 92 100 8 - - - - - System Energy - - - - 100(b) 100(b) - - (a) The System's 1993 actual generation by fuel type excludes GSU; 1994 estimated generation by fuel type includes GSU. (b) Capacity and energy from System Energy's interest in Grand Gulf 1 is allocated as follows: AP&L - 36%; LP&L - 14%; MP&L - 33%; and NOPSI- 17%. . Natural Gas The System operatmg companies have various long-term gas contracts that will satisfy a signi6 cant percentage of each operating company's needs; however, such contracts typically require the operating companies to purchase less than half of their annual gas requirements under such contracts Additional gas requirements are satisfied under less expensive short-term contracts and spot-market purchases. In November 1992, GSU entered into a transportation service agreement with a gas supplier that obligates such supplier to provide GSU with flexible natural gas swing service to certain generaung stations by using such supplier's pipeline and salt dome gas storage facility. Many factors influence the availability and price of natural gas supplies for power plants including wellhead deliverability, storage and pipeline capacity, and the demand requirements of the end users. " Ibis demand is closely tied to the severity of the weather conditions in the region. Furthermore, pricing relative to other coergy I sources (i.e. fuel oil, coal, purchased power, etc.) will affect the demand for natural gas for power plants. Supplies of natural gas are expected to be adequate in 1994. Pursuant to FERC and state regulations, gas supplies may be interrupted to power plants durms penods of shortage. To the extent natural gas supplies may be disrupted, the System operatmg companies will use alternate sources of energy such a fuel oil. ;
.C9.al AP&L has long-term contracts for the supply of low-sulfur coal for the White Bluff Steam Electric Generatmg Station and the Indepgdence Steam Electric Station (which is owned 25% by MP&L). Coal for the White Bluff Station is supplied under a contract from a mine in the State of Wyonung. 'Ihe coal contract provides for the delivery of sufficient coal to operate the White Bluff Station through appW- o dy 2002. Coal for the InWe Station is also supplied under a contract from a mine in the State of Wyommg Coal supplied under this contract is expected to meet the requirements of the TW Station through at least 2014. GSU has a contract for a supply oflow-sulfur Wyommg coal for Nelson Unit 6, which should be sufficient to satisfy the fuel ,
requirements at Nelson Unit 6 through 2004. Cajun has advised GSU that it has contracts that should prtmde an ; adequate supply of coal until 1997 for the operation of Big Cajun 2, Unit 3 (which is operated by Cajun and of { which GSU owns 42%). ; Nuclear Fuel i Generally, the supply of fuel for nuclear ga ..dng units involves the maing and nulhng of uranium ore to produce a concentrate, the conversion of uranium concentrate to uranium hexafluoride gas, enrichment of that gas, fabrication of the nuclear fuel assemblies, and disposal of the spent fuel. t System Fuels is responsible for contracts to acquire nuclear fuel to be used in AP&L's, LP&L's, and - System Energy's nuclear units and for maintmining inventories of such matenals durmg the vanous stages of , processing. Each of these companies is currently responsible for contractmg for the fabrication ofits own nuclear fuel and for purchasing the required enriched uranium hexafluoride from System Fuels. Currently, the .,.. for GSU's River Bend plant are covered by contracts made by GSU. ] On October 3,1989, System Fuels entered into a revolving credit a,s.= with banks permitting it to borrow up to S45 million to finance its nuclear matenals and services inventory. AP&L, LP&L, and System ; Energy agreed to purchase from System Fuels the nuclear matenals and services financed under the agreement if System Fuels should default in its obligations thsreunder. Such purchamen would be allocated based on percentages agreed upon among the parties In the absence of such s a iw.m AP&L, LP&L, and System Energy would each , be obligated to purchase one-third of the nuclear materials and services. iI 1
Based upon the planned fuel cycles for the System's nuclear units, the following tabulation shows the ycars through which existing contracts and inventory will provide materials and services: Acquisition ofor Conversion Spent Uranium to Uranium Enrich- Fabri- Fuel Concentrate Herafluoride ment (3) cation Disnosal ANO1 (1) (1) 1995 1997 (4) ANO2 (1) (1) 1995 1994 (4) River Bend (2) (2) 2000 1995 (4) Waterford 3 (1) (1) 1995 1999 (4) Grand Gulf 1 (1) (1) 1995 1995 (4) (1) Current contracts will provide these materials and senices through ternunation dates ranging from 1994-1997. Additional materials and senices required beyond these dates are estunated to be available for the foreseeable future. (2) Current GSU contracts will provide a signincant percentage of these materials and services for River Bend through 1995. (3) Enrichment services for ANO 1, ANO 2, Waterford 3, and Grand Gulf I are provided by a System Fuels contract with the United States Enrichment Corporation (USEC). The contract has been temunated after 1995 to permit flexibility on future pricing and terms that could be obtained. Enrichment senices for River Bend are provided by a GSU contract with USEC that may be partially ternunated after 1998 and fully terminated after 2000. (See " Rate Matters and Regulation - Regulation - Reculation of the Nuclear Power Industry - Decommissioning " above for information on annual contributions to a federal decontammation and decommissioning fund required by the Energy Act to be made by AP&L, GSU, LP&L, and System Energy as a result of their enrichment contracts with DOE.) (4) He Nuclear Waste Policy Act of 1982 provides for the disposal of spent nuclear fuel or high level waste by the DOE. Under this Act, the DOE was to begin accepting spent fuel in 1998 and to continue until the disposal of all spent fuel from reactor sites has been accomplished. In November 1989, the DOE indicated that the repository program will be delayed. Current on-site spent fuel storage capacity at ANO, River Bend, Waterford 3, and Grand Gulf 1 is estimated to be sufficient to store fuel from normal operations until 1995, 2003, 2000, and 2004, respectively. It is expected that any additional storage capacity required, due to delay of the DOE repository program, will have to be provided by the affected companies (see " Rate Matters and Regulation - Regulation - Regulation of the Nuclear Power Industry - Spent Fuel and Other High-Level Radioactive Waste," above). He System will reqmre additional arrangements for segments of the nuclear fuel cycle beyond the dates shown above. Except as noted above, Entergy cannot predict the ultimate availability or cost of such arrangements at this time. AP&L, GSU, LP&L, and System Energy currently have nuclear fuel leasing arrangements that proside that AP&L, GSU, LP&L, and System Energy may lease up to $125 million, $105 million, S95 million, and $105 million of nuclear fuel, respectively. As of December 31,1993, the unrecovered cost base of AP&L's, GSU's, LP&L's, and System Energy's nuclear fuel leases amounted to approximately $93.6 million, $96.5 million, $61.3 million, and $79.7 million, respectively. Each lessor finances its acquisition and ownership of nuclear fuel under a credit agreement and through the issuance ofintermediate-term notes. He credit agreements, which were l
entered into by AP&L in 1988, by LP&L and System Energy in 1989, and GSU in 1993, had initial terms of five years, with the exception of GSU, which has an initial term of three years. Rese agreements are subjec renewal with, in LP&L's and GSU's case, the consent of the lenders. The credit agreements for AP&L, LP&L, a System Energy have all been extended and now have termmation dates of December 1996, January 1 February 1997, respectively. The credit agreement for GSU was entered into in December 1993 and has termmation date of December 1996. He intermediate-term notes have varying maturities through January 31, 1999. It is expected that the credit agreements will be extended, or alternative financing will be secured b lessor, based on the particular lessee's nuclear fuel requirements. If extensions or alternative financing cannot b arranged, the particular lessee must purchase sufficient nuclear fuel to allow the lessor to retire such borrowing Natural Gas Purchased for Resale NOPSI has several suppliers of natural gas for resale. Its system is interconnected with three interstate and three intrastate pipelines. Presently, NOPSI's pnmary suppliers of natural gas for resale are United, an interstate pipeline, and Bridgeline and Pontchartrain, intrastate pipelines. NOPSI has a firm gas purchase contract United and receives this senice subject to FERC-approved rates pursuant to a certificate granted by FERC. NOPSI also has firm contracts with its two intrastate suppliers and also makes interruptible spot market purchases when economically attractive. In recent yeam, natural gas deliveries have been subject pnmarily to weather-relate curtailments. However, NOPSI has experienced no such curtailments. In April 1992, FERC issued Order No. 636, which mandated interstate pipeline restructuring. He order requires interstate pipelines to cease selling gas to local distribution customers at the city-gate interconnecti although transportation service can be provided in lieu of the fbrmer sale. As a result, in the future, NOPSI mus substitute sources upstream of the United system for its current gas supply from United. NOPSI is considering purchases from independent intrastate or interstate supply aggregators and/or from intrastate pipeline so manner consistent with its economic and supply reliability objectives. Prior to the effectiveness of Order No. 636, discussed above, in the event of a natural gas shortage on the ) United system, NOPSI would have received a portion of the available gas supply from United and its other Il suppliers. After Order No. 636 mandated restructuring (October 31,1993), curtailments of supply could occu NOPSI's suppliers failed to perform their obligations to deliver gas under their supply agreements with NOPSL United could curtail transportation capacity only in tN -: vent of pipeline system constmints. Based on the current
- d curtailments, NOPSI does not anticipate that there will l supply of natural gas, and absent extreme weather r.
I be any intermptions in natural gas deliveries to its cu;. mers. j GSU purchases natural gas for resale from e single interstate supplier. Abandonment of senice by the present supplier would be subject to abandonment proceedmgs by FERC. Research l AP&L, GSU, LP&L, MP&L, and NOPSI are members of the Electric Power Research Institute (EPRI). EPRI conducts a broad range of research in major technical fields related to the electric utility industry. Entergy participates in various EPRI projects, based on its needs and available resources. During 1991,1992, and 1 the System, including GSU, contributed approximately $12 million,516 million, and $17 million, respectively, fo the various research programs in which Entergy was involved. Item 2. f_ronerties Refer to item 1. " Business - Property," incorporated herein by reference, for information regarding the properties of the registrants. i l Item 3. Legal Proceedings Refer to Item 1. " Business - Rate Matters and Regulation," incorporated herein by reference, for details of the registrants' material rate proceedmgs and other regulatory proceedmgs and litigation that are pending or that termmated in the fourth quarter of 1993. Item 4. Submission of Matters to a Vote of Security Holders A consent in lieu of a special meeting of common stockholders of Entergy-GSU Holdings, Inc. (Holdings) was executed on December 30,1993, pursuant to a Delaware statute that permits such a procedure. %c consent was signed on behalf of Entergy Corporation and GSU, which at that time owned all of the outending common stock of Holdings. He common stockholders acted to: (1) increase the number of directors from 2 to 18 upon the occurrence of the combination of Entergy Corporation and GSU, such expanded board to consist of Edwin Lupberger and Joseph Donnelly, who continued as directors, and the following new directors: W. Frank Blount; John A. Cooper, Jr.; Brooke H. Duncan; Lucie J. Fjeldstad, Kan~*r Hodges, Jr.; Robert v.d. Luft; Adm. Kinnaird R. McKee; Paul W. Murrill; James R. Nichols; Eugene H. Owen; John N. Palmer, Sr.; Robert D. Pugh; H. Duke Shackelford; Wm. Clifford Smith; Bismark A. Steinhagen; and Dr. Walter Washington; (2) approve the terms and provisions of certain agreements related to such combination; (3) approve the actions of the officers in connection with those agreements and the transactions contemplated thereby; (4) approve the assumption and adoption by Holdings of certain benefit plans of Entergy Corporation; and (5) approve the takmg of actions to issue stock with respect to such plans, including the listing of Holdings' common stock on the New York, Pacific, and Midwest Stock Exchanges and the filing of registration statements with the Securities and Fvchnga Cnmmi" ion. After the consummation of the transactions involved in the combination, the name of Holdings was changed to Entergy Corporation. On January 22, 1994, Mr. Donnelly resigned from the position of ducctor of Entergy Corporation. PARTII l l Item 5. Market for Registrants' Common Eauity and Related Stockholder Matters Entergy Corporation. 'Ihe shares of Entergy Corporation's common stock are listed on Midwest, and Pacific Stock Exchanges. The high and low prices for each quarterly period in 1993 and 1992, were as follows: 1993 1992 Low liigh Low g JJ{igli (In Dollars) 32 1/2 29 5/8 27 1/8 First 36 1/2 33 1/4 28 1/2 26 1/8 Second 38 1/4 36 1/4 31 7/8 28 1/4 Third 39 7/8 351/8 33 5/8 30 1/2 Fourth 39 1/4 Four consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in each of 1993 and 1992. In 1993, dividends of 40 cents per share were paid quarters and dividends of 45 cents per share were paid in the last quarter. Dividends of 35 ce paid in each of the first three quarters of 1992, and dividends of 40 cents per share were 1992. As of February 24,1994, there were 63,7"i9 stockholders of record of Entergy Corporation. For information with respect to Entergy Corporation's future ability to pay dividends, refer to No Entergy Corporation and Subsidiaries' Notes to Consolidated Financial Statements, " Divide incorporated herein by reference. In addition to the restrictions described in Note 7, the H provides that, without approval of the SEC, the unrestricted, undistributed retamed cammg Corporation subsidiary are not available for distribution to Entergy Cogoration's common carmngs are made available to Entergy Corporation through the declaration of dividends by s AP&L GSU, LP&L, MP&L, NOPSI, and System Energy. There is no market for the common st Prior to System Energy and the System operating companies, all of which is December 31, 1993, common stock were acquired by Entergy Corporation. No cash dividends on common stock wer Cash dividends on common stock paid by AP&L, LP&L, MP&L, NOPSI, and its stockholders in 1992-1993. System Energy to Entergy Corporation during 1993 and 1992, were as follows: 1993 1991 (In Millions)
$156.3 5 75.0 AP&L 167.6 174.6 LP&L 85.8 68.4 MP&L 43.9 32.2 NOPSI 233.1 137.7 System Energy For information with respect to restrictions that limit the ability of System Energy and the System companies to pay dividends, and for information with respect to dividends paid to Entergy subsidiaries subsequent to December 31, 1993, refer respectively, to Note 6 of S> tem Energ
- AP&L's, GSU's, LP&L's, MP&L's, and NOPSI's Notes to Financial Statements, " Dividend Restrictions," incorporated herein by reference. Item 6. Selected Financial Data Entergy Corporation. Refer to information under the heading "Entergy Corporation and Subsidiaries Selected Financial Data - Five-Year Comparison," which information is incorporated herein by reference. AP&L Refer to information under the heading " Arkansas Power & Light Company Selected Financial Data - Five-Year Comparison," which information is incorporated herein by reference. . 1 1 GSU. Refer to information under the heading " Gulf States Utilities Company Selected Financial Data - Five Year Comparison," which information is incorporated herein by reference. ; LP&L Refer to information under the heading " Louisiana Power & Light Company Selected Financial Data - Five-Year Comparison," which information is incorporated herein by reference. AF&L Refer to information under the heading " Mississippi Power & Light Company Selected Financial Data - Five-Year Comparison," which information is incorporated herein by reference. NOPSI. Refer to information under the heading "New Orleans Public Service Inc. Selected Financial Data
- Five-Year Comparison," which information is incorporated herein by reference.
System Energy. Refer to infonnation under the heading " System Energy Resources, Inc. Selected Financial Data - Five-Year Comparison," which information is incorporated herein by reference. Item 7. Manneement's Discussion and Analysis of Financial Condition and Results of Operations Entergy Corporation. Refer to information under the heading "ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT 5 FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference. AP&L Refer to information under the heading " ARKANSAS POWER & LIGHT COMPANY MANAGEMENTS FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference. GSU. Refer to information under the heading " GULF STATES UTILITIES COMPANY MANAGEMENTS FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference. LP&L Refer to information under the headmg " LOUISIANA POWER & LIGHT COMPANY MANAGEMENTS FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference. AF&L Refer to information under the heading " MISSISSIPPI POWER & LIGHT COMPANY MANAGEMENTS FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference, i l 1 1
NOPSI. Refer to information under the headmg "NEW ORLEANS PUBLIC - SERVICE INC. MANAGEMENTS FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by reference. System Energy. Refer to information ander the headmg " SYSTEM ENERGY RESOURCES, INC. MANAGEMENTS FINANCIAL DISCUSSION AND ANALYSIS," which information is incorporated herein by r reference. l l l
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. $f .
Itsm 8. Financial Statements and Suoolementary Data. INDEX TO FINANCIAL STATEMENTS Entergy Corporation and Subsidiaries: 61 Definitions 63 Repon of Management 64 Audit Committee Chatnnan's Letter 65 Independent Auditors' Report Consolidated Balance Sheets, December 31,1993 and 1992 66 Statements of Consolidated Cash Flows For the Years Ended December 31,1993,1992 and 1991 68 69 Management's Financial Discussion and Analysis Statements of Consolidated Income For the Years Ended December 31,1993,1992 and 1991 71 Statements of Consolidated Retained Earnings and Paid-In Capital for the Years Ended 72 l l December 31,1993,1992 and 1991 73 Management's Financial Discussion and Analysis (continued) 78 Notes to Consolidated Financial Statements 106 Selected Financial Data - Five-Year Comparison AP&L: 109 l Definitions 111 Report of Management 112 l Audit Committee Chairman's Letter i13 Independent Auditors' Report 114 Balance Sheets, December 31,1993 and 1992 Statements of Cash Flows For the Years Ended December 31,1993,1992 and 1991 116 117 Management's Financial Discussion and Analysis Statements ofIncome For the Years Ended December 31,1993,1992 and 1991 118 Statements of Retained Earnings for the Years Ended December 31,1993,1992 and 1991 119 120 Management's Financial Discussion and Analysis (continued) 124 i Nctes to Financial Statements Selected Financial Data - Five-Year Comparison 139 GSU: 143 Definitions 145 Report of Management 146 l Audit Committee Chairman's Letter 147 Independent Auditors' Report Balance Sheets, December 31,1993 and 1992 148 Statements of Cash Flows For the Years Ended December 31,1993,1992 and 1991 150 151 Management's Financial Discussion and Analysis Statements ofIncome For the Years Ended December 31,1993,1992 and 1991 152 Statements of Retained Earnings and Paid-In Capital for the Years Ended December 31,1993,1992 153 l and 1991 154 Management's Financial Di:cussion and Analysis (continued) 158 Notes to Financial Statements Selected Financial Data - Five-Year Comparison 182 , 1 LP&L: ! 185 Definitions 187 Report of Management 188 ! Audit Committee Chairman's Ixtter Independent Auditors' Report i89 Balance Sheets, December 31,1993 and 1992 190 Statements of Cash Flows For the Years Ended December 31,1993,1992 and 1991 192 193 l Management's Financial Discussion and Analysis Statements ofIncome For the Years Ended December 31,1993,1992 and 1991 194 ) 195 Statements of Retained Earnings for the Years Ended December 31,1993,1992 and 1991 l 1% l Management's Financid Discussion and Analysis (continued) 198 l Notes to Financial Statements Selected Financial Data - 9 <c-Year Comparison 215 l l f l - _ - - - - - - - - - _ - - - - - - - - - - - _ - - _ _
MP&L: 219 . Definitions ' 221 Report of Management 222 Audit Committee Chairman's Letter 223 Independent Auditors' Report Balance Sheets, December 31,1993 and 1992 224 ; Statements of Cash Flows For the Years Ended December 31,1993,1992 and 1991 226 , 227 Management's FinancialDiscussion and Analysis Statements ofIncome For the Years Ended December 31,1993,1992 and 1991 .228 Statements of Retained Earmngs for the Years Ended December 31,1993,1992 and 1991 229 i 230 i Management's Financial Discussion and Analysis (continued) ' 234 Notes to Financial Statements Selected Financial Data - Five-Year Comparison 247 NOPSI: 251 Definitions 253 Report of Management 254 l Audit Committee Chairman's Letter ' 255 Independent Auditors' Report Balance Sheets, December 31,1993 and 1992 256 Statements of Cash Flows For the Years Ended December 31,1993,1992 and 1991 258 ' r 259 Management's Financtal Discussion and Analysis Statements ofIncome For the Years Ended December 31,1993,1992 and 1991 260 Statements of Retained Earnings for the Years Ended Decembes 31,1993,1992 and 1991 261 Management's Financial Discussion and Analysis (continued) 262 265 Notes to Financial Statements Selected Financial Data - Five-Year Comparison 278 System Energy: 281 , Definitions 283 Report of Management 284 Audit Committee Chairman's letter ; 285 > Independent Auditors'Repost Balance Sheets, December 31,1993 and 1992 286 Statements of Cash Flows For the Years Ended December 31,1993,1992 and 1991 288 ; 289 _ Management's Financial Discussion and Analysis Statements ofIncome For the Years Ended D- -4 = 31,' 1993,1992 and 1991 290 , Statements of Retained Earnings for the Years Ended December 31,1993,1992 and 1991 291 ! 292 Management's Financial Discussion and Analysis (continued) 295 i Notes to Financial Statements ' Selected Financial Data - Five-Year Comparison 309 l 1
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Entergy Corporation and Subsidiaries /1993 Financial Statements 1 J E NTERGY: Ubis pageinteonallyleft blank)
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1 I ll 1 l 1 i 1 1
ENTERGY CORPORATION AND SUBSIDIARIES DEFINITIONS 1 I 1 Certain abbreviations or acronyms used in the Financial Statements, Notes to Financial Statements, and Management's Financial Discussion and Analysis are defined below: Abbreviation or Acronym 110B AFUDC Allowance for Funds Used During Construction ANO Arkansas Nuclear One Steam Electric Generatmg Station : ANO2 Unit No. 2 of ANO { AP&L Arkansas Power & Light Company , Arkansas Public Service Commission .: APSC 1 Council Council of the City of New Orleans, Louisiana i Entergy or System Entergy Corporation and its various direct and indirect subsidianes Entergy Enterprises Entergy Enterprises, Inc. (formerly Electec, Inc.) Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy Corporation that has operating responsibility for Grand Gulf 1, Waterford 3, ANO, and River Bend j Entergy Porzer Entergy Power, Inc., a subsidiary of Entergy Corporation that markets j capacity and enugy for resale from certain generstmg facilides to other parties, principally non-affiliates FERC Federal Energy Releg Commission l G&R Bonds General and Refundmg Mortgage Bonds issued and issuable by MP&L and NOPSI j l Grand Gulf 1 Unit No. I of the Grand Gulf Steam Electric Cs.ng Station l i l Grand Gulf 2 Unit No. 2 of the Grand Gulf Steam Electric Generatmg Station ; GSU Gulf States Utilities Company (including wholly owned subsidiaries - Varibus _; Corporation, GSG&T, Inc., Prudential Oil and Gas, Inc., and Southern Gulf : Railway Company) KWH- Kilowatt-Hour (s) LP&L Louisiana Power & Light Company LPSC Louisiana Public Service Commission __ . _ _ .._________ _ _ _ _ _ E
ENTERGY CORPORATION AND SUBSIDIARIES DEFINITIONS -(Concluded) Abbreviation or Acronym Term Merger The combination transaction, <=mmmated on December 31,1993, by which GSU became a subsidiary of Entergy Corporation and Entergy Corporation became a Delaw2re corporation MP&L Mississippi Power & Light Company MPSC Mississippi Public Service Commission 1991 NOPSI Settlement Agreement, retroactive to October 4,1991, among NOPSI, the Council, the Alliance for Affordable Energy, Inc., and others that settled certain Grand Gulf 1 prudence issues and pendmg litigation related to the resolution (including the Determmations and Order referred to therem) adopted by the Council on February 4,1988, disallowing NOPSI's recovery of $135 million of previously deferred Grand Gulf 1-related costs NOPSI New Orleans Public Sersice Lx. PUCT Public Utility Commission of Texas Rate Cap The level of GSU's retail electric base rates in effect at December 31,1993, for the Louisiana retail jurisdiction, and the level in effect prior to the Texas Cities Rate Settlement for the Texas retail jurisdiction, that may not be exceeded for the Eve years following December 31,1993 River Bend River Bend Steam Electric Generating Station (nuclear), owned 70% by GSU SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the Financial Accounting Standards Board SFAS 106 SFAS No.106, " Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS No.109, " Accounting for Income Taxes" System Agreement Agreement, effective January 1,1983, as amended, among the System operatmg companies relating to the shanng of generating capacity and other power resources System Energy System Energy Resources, Inc. System Fuels System Fuels, Inc. System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively System or Entergy Entergy Corporation and its various direct and indirect subsidiaries Waterford3 Unit No. 3 of the Waterford Steam Electric Generating Station ENTERGY CORPORATION AND SUBSIDIARIES REPORT OF MANAGEMENT ne management of Entergy Corporation has prepared and is responsible for the fina principles. Financial information included elsewhere in this To meet its responsibilities with respect to fmancial information, management maintai system ofinternal accounting controls that is designed to provide reasonable assurance, to the integrity, objectivity, and reliability of the fmancial records, and as to the protection of assets includes communication through written policies and procedures, an employee Code
, and an of Cond orgamzational structure that provides for appropriate division of responsibility and the trauu system is also tested by a comprehensive internal audit program.
The independent public accountants provide an objective assessment of the degr meets its responsibility for faimess of financial reporting. hey regularly evaluate the controls and perfenn such tests and other procedures as they deem necessary to reach fairness of the fmancial statements. Management believes that these policies and procedures provide reasonable assura are carried out with a high standard of business conduct. EDWIN LUPBERGER GERALD D. MCINVALE Chairman and Chief Executive Officer Senior Vice President and Chief Financial Officer l l l l l 1
ENTERGY CORPORATION AND SUBSIDIARIES AUDIT COMMITTEE CHAIRMAN'S LETTER The Entergy Corporation Board of Directors' Audit Committee is comprised of five directors, who are not officers of Entergy Corporation: H. Duke Shackelford (Chairman), Brooke H. Duncan, Kaneaster Hodges, Jr., John N. Palmer, Sr., and Bismark A. Steinhagen (as of December 31,1993). %e committee held four meetings during 1993. He Audit Committee oversees Entergy Corporation's financial reporting process on behalf of Entergy Corporation's Board of Directors. In falfilling its responsibility, the committee recommended to the board, subject to stockholder approval, the selection of Entergy Corporation's independent public accountants (Deloitte & Touche). Also, the committee oversees and coordinates the activities and policies of the subsidiary companies' audit comnuttxs The Audit Committee discussed with Entergy's internal auditors and the independent public accountants the overall scope and specific plans for their respective audits, as well as Entergy Corporation's consolidated financial statements and the adequacy of Entergy Corporation's internal controls. He committee met, together and separately, with Entergy's internal auditors and independent public accountants, without management present, to discuss the results of their audits, their evaluation of Entergy Corporation's internal controls, and the overall quality of Entergy Corporation's financial reporting. He meetmgs also were designed to facilitate and encourage any private communication between the committee and the intemal auditors or independent public accountants. H. DUKE SHACKELFORD Chairman, Audit Committec
INDEPENDENT AUDITORS' REPORT l l To the Shareholders and the Board of Directors of Entergy Corporation We have audited the accompanying consolidated balance sheets of Entergy Corporation and subsidiaries as , of December 31,1993 and 1992, and the related statements of consolidated income, retained cammgs and paid-in ! capital, and cash flows for each of the three years in the period ended December 31, 1993. These fmancial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these fmancial statements based on our audits. We did not audit the fmancial statements of Gulf States Utilities Company (a consolidated subsidiary acquired on December 31, 1993), which statements reflect total assets constituting 31% of consolidated total assets at December 31, 1993. Rose statements were audited by other , auditors whose report (which included explanatory paragraphs regarding the uncertainties discussed in the fourth j f and fifth paragraphs below) has been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulf States Utilities Company, is based solely on the report of such other auditors. i l We conducted our audits in accordance with generally- accepted auditing standards. Those standards l require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements l [ j are free of material misstatement. An audit includes exanunmg, on a test basis, evid-oce supporting the amounts l j and disclosures in the fmancial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the cverall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonabic basis for our opinion. l I l In our opinion, based on our audits and the report of the other auditors, such consolidated financial statements present fairly, in all material respects, the fmancial position of Entergy Corporation and subsidiaries at December 31,1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31,1993 in conformity with generally accepted accounting principles. The Corporation acquired a 70% interest in River Bend Unit I Nuclear Generating Plant (River Bend) through its acquisition of Gulf States Utilities Company on December 31,1993. As discussed in Note 2 to the consolidated fmancial statements, the net amount of capitalized costs for River Bend exceed those costs currently being recovered through rates. At December 31,1993, approximately $747 million is not currently being recovered l through rates. If current regulatory and court orders are not modified, a write-off of all or a portion of such costs may be required. Additionally, as discussed in Note 2 to the consolidated fmancial statements, other rate-related i contingencies exist which may result in a refund of revenues previously collected. He extent cf such write-off of capitalized River Bend costs or refund of revenues previously collected, if any, will not be determined until appropriate rate proceedmgs and court appeals have been concluded. Accordingly, the accompanying consolidated fmancial statements do not include any adjustments that might result from the outcome of these uncertainties. i l l As discussed in Note 8 to the consolida'ed financial statements, civil actions have been initiated agamst Gulf States Utilities Company to, among other things, recover the co-owner's investment in River Bend and to annul the related joint ownership participation and operating agreement. He ultimate outcome of these proceedmgs, including their impact on Gulf States Utilities Company, cannot presently be determmed Accordingly, the accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. As discussed in Note I to the consolidated financial statements, certain of the Corporation's subsidiaries changed their method of accounting for revenues in 1993 and, as discussed in Notes 3 and 10 to the consolidated financial statements, in 1993 the Ccrporation changed its methods of accounting for income taxes and postretirement benefits other than pensions, respectively. DELOfITE & TOUCHE New Orleans, Louisiana Febmary 11,1994
i ENTERGY CORPORATION AND SUBSIDIARIES ] CONSOLIDATED BALANCE SHEETS ASSETS ; December 31, 1993 1992 (In Thousands) Utility Plant (Note 1): Electric $20,848,844 $13,765,029 Plant acquisition adjustment - GSU (Note 11) 380,117 ~ -
- Electric plant under leases (Note 9) .663,024 662,400 -
Property under capital leases - ciectric 175,276 100,945 Natural gas 156,452 110,399 Steam products . 75,689 . Cci.e Goinworkinprogress $33,112 309,552 Nuclear fuel under capital leases (Note 9) 329,433 233,616 : Nuclear fuel 17,760 20,683 j Total 23,179,707 15,202,624-l 7.157,981 4,462,693 - Less - accumulated deprm=han and amortization Utility plant - net 16,021,726 10,739,931 Other Property and Investments: Decommissioning trust funds 172,960 127,323 Other 183,597 76,558 Total 356,557 203,881 Current Assets: Cash and cash equivalents (Note 1): Cash 27,345 6,975 Temporary cash investments - at cost, which appron==ta= market $36,404 372,817 Total cash and cash equivalents 563,749 379,792 : Other ww-y investments - at cost, which j spproxiinates market - 17,012 i Special deposits 36,612 18,739 l Notes receivable 17,710 -19,778 i Accounts receivable: Customer (less allourm for doubtful accounts of
$8.8 million in 1993 and $6.2 million in 1992) 315,796 194,980 Other 81,931 43,006 Accrued unbilled revenues (Note 1) 257,321 57,716-Fuel inventory - at average cost and LIFO 110,204 85,595
' Materials and supplies - at average cost 360,353 287,407 Rate deferrals (Note 2) 333,311 186,391 Prepayrnents and other 98,144 74,168 Total 2,175,131- 1,364,584 .;
Deferred Debits and Other Assets Rate deferrels (Note 2) . 1,876,051 1,485,598 SFAS 109 regulatory asset - net (Note 3) 1,385,824. - Long-term receivables 228,030 15,739 Unamoruzed loss on mulid debt 210,698- 91,825 Other 622,680 337,979 Total 4,323,283 1,931,141 TOTAL $22,876,697 $14,239,537 See Notes to Consolidated Financial Statements.
ENTERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 1993 1992 (In Thousands) Capitalization: Common stock, S.01 par value in 1993 and $5 par value in 1992: authorized 500,000,000 shares; issued and outstanding 231,219,737 shares in 1993; issued 175,137,392 shares in 1992 (Note 5) $2,312 $875,687 Paid-in capital 4,223,682 1,327,589 Retained earmngs (Note 7) 2,310,082 2,062,188 Iess - treasury stock (1,943 shares in 1992)(Note 5) - 54 Total common shareholders' equity 6,536,076 4,265,410 Subsidiary's preference stock (Note 5) 150,000 - Subsidiaries' preferred stock (Note 5): Without sinking fund 550,955 414,511 With sinking fund 349,053 304,049 Long-term debt (Notes 6 and 9) 7,355,962 5,149,344 Total 14,942,046 10,133,314 Other Noncurrent Liabilities: Obligations under capital leases (Note 9) 322,867 177,112 ' 270,318 140,292 Other (Note 8) Total 593,185 317,404 Current tiabilities: Currently maturing long-term debt (Note 6) 322,010 133,805 Notes payable (Note 4) 43,667 667 , Accounts payable 413,727 313,054 Customer deposits 127,524- 100,496 Taxes accrued 118,267 128,172 Accumulated deferred income taxes (Note 3) 44,637 43,265 Interest accrued 210,894 152,136 Dividends declared 13,404 15,172 . Gas contract settlements - liability to customers - 55,998 l Deferred revenue - gas supplierjudgment proceeds 14,632 42,256 l Deferred fuel cost 4,528 16,128 ! Obligations under capitalleases (Note 9) 194,015 157,448 l Other 240,471 90.119 i Total 1,747,776 1,248,746 Deferred Credits: Accumulated deferred income taxes (Note 3) 3,858,337 1,612,947 Accumulated deferred investment tax credits (Note 3) 793,375 553,506 Deferred revenue - gas supplierjudgment proceeds - 14,846 j Other 941,978 358,774 ! Total 5,593,690 2,540,073 Commitments and Contingencies (Notes 2,8, and 9) TOTAL $22,876,697 $14.239,537 See Notes to Consolidated Financial Statements. l I ENTERGY CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS For the Years Ended Dweenber 31, 1993 1992 1991 (la Thousands) Operstang Acuvities:
$551,930 5437,637 $482,032 Net income Noncash items included in not income:
Cumulative effect of a change in accounting principle (93.841) 200,532 109,153 (7.342) Change in rate deferrals' excess capacity net 443,550 424,958 398,864 Depreciation and decornmissioning 17,669 118,562 194,830 Deferred income taxes and investroent tax credits Allowance for equity funds used during (8,049) (7,355) (7,921) constructaon (42,470) (38,646) (36,310) ; Amortization of deferred revenues 21,576 ' 20,832 (24,911) Provision for estimated losses and reserves I Gain on sale of property net
- (19,612) -
l Changes in working capital: (40,682) (19,150) 5,655 Receivabler (1,161) 20,008 (37,917) l Fuelinventory (9,167) (54,559) 1,302 Accounts payable (32,761) 28,561 41,085 Taxes accrued (758) (10,845) (19,830) l Interest accrued 18,821
$1,100 (12,428)
Other working capital accounts (56,027) (56,066) (56,098) i Refunds to customers gas contract settlement (20,402) (20,8%) (23,193) J Decommissioning trust contributions 94,092 (43,185) (13,619) Other 1,074,387 831,226 % I,935 f Net cash flow provided by operating acuvities l Investing Activities: ; Merger with GSU cash paid (250,000) - - 261,349 - - Merger with OSU cash acquired ($12.235) (438,845) (439,087) Construction / capital evenditures 8,049 7,355 7,921 Allowance for equity funds used during constructaon
- 67,985 -
Proceeds received from sale of property , (118,216) (60,359) (66,068) Nuclear fuel purchases 121,526 62,332 47,452 Proceeds from sala' leaseback of nuclear fuel (76,870) (35,189) (10,878) Investment in nonregulatessonutility properties 17.012 114,651 150,580 i Decrease in other temporary investments (549,385) (282,070) (310,080) Net cash flow used in investing activities Financing Activities: Proceeds from the issuance of' 605,000 637,114 - First mortgage bonds 350,000 65,000 - General and refunding mortgage bonds
- 120,999 133,175 Preferred stock 106,070 48,067 68,514 Bank notes and other long-term debt .
Retirement of. I (911,692) (1,009,320) (665,384) First mortgage bonds (99,400) . . I General and refunding mortgage bonds (69,982) (17,412) (7,442) l Bank notes and other long-term debt (20,558) (105,673) (161,640) I Common stock (56,000) (109,369) (85,500) l Redemption of preferred stock (287,483) (256,117) (228,816) j Common stock dividends paid 43,000 - - j Changes in short-term borrowings (341,045) (626,711) (947,093) Net cash flow used in financing activities . (295,238) j Net increase (decrease)in cash and cash equivalents 183,957 (77,555) Cash and cash equivalents at beginning of period 379,792 457,347 752.585 f
$$63,749 $379,792 $457,347 Cash and cash equivalents at end of period SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMAT10N:
Cash paid during the period for:
$485,876 $570,199 $646,872 Interest net of amount capitalized
$159,659 $125,079 $68,278 Income taxes Noncash investing and financing activities:
$126,812 $75,040 $46,073 Capiallease obligations incurred Merger with GSU common stock issued $2,031,101 - -
See Notes to Consolidated Financial Statements. ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES Liquidity is impostant to Entergy due to the capital intensive nature of our business, which requires large
- investments in long-lived assets However, large capital expenditures for the construction of new generatmg capacity are not currently planned The System requires significant capital resources for the periodic maturity of certain series of debt and preferred stock. Net cash flow from operations totaled $1,074 million, $831 million, and
$962 million in 1993,1992, and 1991, respectively. In recent years, this cash flow, supplemented by cash on hand, has been sufficient to meet substantially all investing and financing requirements, including capital expenditures, dividends, and debt / preferred stock maturities. Entergy's ability to fund these capital mquirements with cash from operations results, in part, from our continued efforts to streamline operations and reduce costs as well as collections under our Grand Gulf I rate phase-in plans, which exceed the current cash requirements for Grand Gulf 4 i
1-related costs. (In the mcome statement, these revenue collections are offset by the amortization of previously i deferred costs, therefore, there is no effect on net income.) Further, Entergy Corporation's subsidiaries have the ability to meet future capital requirements through future debt or preferred stock issuances, as discussed .below. i See Note 8, incorporated herein by reference, for additional information on the System's capital and refinancing requirements in 1994 - 1996. Also, in order to take advantage of lower interest and dividend rates, Entergy I Corporation's subsidiaries may continue to refinance high-cost debt and preferred stock prior to maturity. Productive investment of excess funds is necessary to enhance the long-term value of our common stock. In 1993, Entergy Corporation made approximately $77 million in investments in an electric distribution company and a high-voltage transmission system in Argentina. In 1992, Entergy Corporation invested $11 million in a generating facility in Argentina, $12.5 million in an independent power plant in Virginia, 55.5 million in a lighting efficiency services company, and $6.2 million in a company that develops energy management and other technology applications. Entergy Corporation expects to invest approximately $150 million per year in nonregulated and ; nonutility businesses. See "Significant Factors and Known Trends - Nonregulated Investments" for additional information. Certain agreements and restrictions limit the amount of mortgage bonds and preferred stock that can be issued by the System operatmg companies and System Energy. Based on the most restrictive applicable tests as of . Ds.iier 31,1993 (which in certain instances, are impacted by the inclusion of the cumulative effect of the change i in accounting principle for accruing unbilled revenues discussed in Note 1), and an assumed annual interest or dividend rate of 8%, the System operating companies could have issued bonds or preferred stock in the following i amounts, respectively: AP&L - $226 million and $1,075 million; GSU - 5425 million and 50 million; LP&L - i
$92 million and $686 million; MP&L - $219 million and $548 million; and NOPSI - $40 million and $306 million.
System Energy could also have issued $290 million of bonds, but its charter does not presently provide for the issuance of preferred stock. In addition, the System operating companies and System Energy have the conditional ability to issue bonds agamst the retirement of bonds, in some cases without meetmg an earmngs coverage test. I AP&L may also issue preferred stock to refund outstandmg preferred stock without meetmg an earnings coverage - l test. GSU has no limitations on the issuance of preference stock. See Note 4, incorporated herein by reference, for j
- information on the System's short-term borrowings. l Entergy Corporation's current primary capital requirements are to periodically invest in, or make loans to,
- its subsidiaries. Entergy Corporation expects to meet these requirements in 1994 - 1996 with internally generated funds and cash on hand. Further, Entergy Corporation paid $287.5 million of dividends on its common stock in ' ,
1993. Entergy Corporation receives funds through dividend payments from its subsidiaries. During 1993, these ! common stock dividend payments totaled $686.7 million. Certain restrictions may limit the amount of these ! I distributions. See Note 7, incorporated herein by reference, for additional information. See Notes 2 and 8, incorporated herein by reference, regarding River Bend rate appeals and pendmg litigation with Cajun Electric Power Cooperative, Inc. (Cajun). Substantial write offs or charges resulting from adverse rulings in these matters could adversely affect GSU's ability to continue to pay dividends. l a - n, , . -a v -- . ,, ,+ . ,- ~ _ _ . - ,w-
t ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES -(Concluded) t Entergy Corporation has SEC authorization to repurchase shares ofits out*= ding common stock. Market i conditions and board authorization determine the amount of repurchases Entergy Corporation has requested SEC cuthorization for a $300 million bank line of credit, the proceeds of which are expected to be used for common stock repurchases and other optional activities. See Notes 4 and 5, incorporated herein by reference, for addition; information. ! i I i i J t r I p 1 1 i
ENTERGY CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME For the Years Ended December 31 1993 1992 1991 (la Thousands, Except Share Data) Operating Revenues: Electric $4,394,346 $4,043,555 $3,974,478 Natural gas 90,991 72,944 76,951 Total 4,485,337 4.116,499 4,051,429 Operating Expenses: Operation: Fuel for electric generation and fuel-related expenses 859,641 759,470 735,986 Purchased power 278,070 228,679 205,131 Gas purchased for resale 52,592 43,212 49,986 Other 813,555 806,943 823,817 Maintenance 306,666 301,836 282,321 Depreciation and decommissioning 443,550 424,958 398,864 Taxes other than income taxes 199,151 197,895 184,247
!acome taxes (Note 3) 251,163 210,081 243,760 Rate deferrals (Note 2):
Rate deferrals (1,651) (24,176) (56,681) l Amortization of rate deferrals 289,259 209,015 206,468 1 Deferral of previously incurred Grand Gulf 1-related costs - - (90,000) Total 3,491,9 % 3,157,913 2.984,399 , Operating income 993.341 958,586 1,067,030 Other Income: Allowance for equity funds used during construction 8,049 7,355 7,921 Miscellaneous - net 60,068 135,475 122,697 Income taxes (Note 3) (33,640) (46,382) (33,391) Total 34,477 96,448 97,227 j Interest and Other Charges: Interest on long-term debt 488,799 529,668 599,797 Other interest - net ' 9,849
, 29,686 27,245 Allowance for Nrrowed funds used during construction (5,478) (5,094) (7,392)
Preferred diviand requirements of subsidiaries $6,559 63,137 62,575 j Total 569,729 617,397 682.225 Income before Cumulative Effect of a Change in Accounting Principle 458,089 437,637 482,032 f Cumulative Effect to January 1,1993, of Accruing Unbilled Revenues (net ofincome taxes of $57,188) (Note 1) 93,841 - - l Net income $551,930 $437,637 $482,032 Earnings per average common share before cumulative effect of a change in accounting principle $2.62 $2.48 $2.64 Earnings per average common share $3.16 $2.48 $2.64 l Diddends declared per common share (Note 7) $1.65 $1.45 $1.25 Average number of common shares outstanding (Note 5) 174,887,556 176,573,778 182,665,303 j i See Notes to Consolidated Financial Statements. l _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - _ _ _ _ . _ _ _ _ _ j
i ENTERGY CORPORATION AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED RETAINED EARNINGS AND PAID-IN CAPITAL For the Years Ended December 31, 1993 1992 1991 (In Thousands)
$2,062,188 $1,943,298 $1,775,000 Retamed Eanungs, January 1 551,930 437,637 482,032 Add -Net income 2,614,118 2,380,935 2,257,032 Total Deduct-288,342 255,479 228,555 Dividends declared on common stock 13,906 59,187 80,009 Common stock reurements (Note 5) 1,788 4,081 5,170 Capital stock and other expenses 304,036 318,747 313,734 Total
$2,310,082 $2,062,188 $1,943,298 Retamed Earnmgs, December 31 (Note 7) i
$1,327,589 51,357,883 $1,408,640 Paid-in Capital, January 1 Add:
Gain (loss)on reacquisition of (20) (1,323) 35 subsidiaries' preferred stock Issuance of 56,667,726 shares of common stockin the merger with GSU(Note 11) 2,027,325 - Issuance of 174,552,01I shares of common stock at 5.01 par value net of the reurement of 174,552,011 shares of common stock at 55.00 par value (Note 5) 871,015 - - 4,225,909 1,356,560 1,408,675 Total Deduct:
- 4,389 28,127 49,391 Common stock retirements (Note 5)
(2,162) 844 1,401 Capital stock discounts and other expenses 2,227 28,971 50,792 Total 54,223,682 Si,327,589 $1,357,883 . Paid-in Capital, December 31 _ See Notes to Consolidated Financial Statements. l a l l
ENTERGY CORPORATION AND SUBSIDfARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net income Consolidated net income increased in 1993 due prunarily to the one-time recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1, incorporated herein by reference) and its ongoing effects. Effective January 1,1993, AP&L, MP&L, and NOPSI began accruing as revenues the charges for energy delivered to customers but not yet billed. Electric and gas revenues were previously recorded on a cycle-billing basis. This increase was partially offset by the effects ofimplementing SFAS 109 and SFAS 106 (see Notes 3 and 10, respectively, incorporated herein by reference), and the impact in March 1992 of an after-tax gain frc,m the sale of AP&L's Missouri properties. Excluding these items, net income for 1993 would have been $475.9 million and net income for 1992 would have been $418.0 million. This $57.9 million increase is due to increased retail energy sales, improved gas revenues, and decreased interest expense, partially artset by decreased miscellaneous income and by the impact of an August 1993 rate settlement invohing System E.:argy's retum on equity (see Note 2, incorporated herein by reference). Consolidated net income decreased in 1992 due primarily to reduced retail energy sales resulting from mild summer and winter temperatures. His decrease was partially offset by lower nonfuel operation and maintenance expenses (excluding nuclear refueling outage expenses of $87.9 million in 1992 and $61.8 million in 1991) and lower irnerest expense. In addition,1992 net income includes $19.6 million from the gain on the sale of AP&L's' retail properties in Missouri. Significant factors a _xting the results of operations and causing variances between the years 1993 and 1992, and 1992 and 1991, are discussed under " Revenues an.d Sales," " Expenses," and "Other" below. Revenues and Sales See " Selected Financial Data - Five-Year Comparison," incorporated herein by. reference, following the notes, for information on electric operating revenues by source and K%1I sales. Electric operating revenues were higher in 1993 due pnmarily to increased residential and commercial energy sales resulting from a return to more normal weather as compared to milder weather in 1992, increased industrial sales pnmarily in the petrochemical, lumber, and plywood industries, and increased fuel adjustment revenues and collections of previously deferred Grand Gulf 1-related costs, neither of which affects net mcome. ! Dese increases were partially offset by the impact of a System Energy rate settlement.
]
Electric operating revenues were higher in 1992 due pnmarily to an increase in fuel adjustment revenues and collections of previously deferred Grand Gulf I costs, neither of which affccts net income. The increase in fuel ; l adjustment revenues was due to increased gas generation resulting from scheduled nuclear refueling outages. Partially offsetting these higher revenues were decreased retail sales resulting from mild temperatures. 1 Gas operating revenues increased in 1993 due pnmarily to an increase in gas rates and increased fuel adjustment revenues resulting from higher average per unit cost for gas purchased for resale. 1 l I
ENTERGY CORPORATION AND SUBSIDIARIES , MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS-(Concluded) i l P Ernenses . j Fuel for electric generation and fuel-related expenses increased in 1993 due primarily to an :ncrease m generation requirements resulting from increased energy sales as discussed in " Revenues and Sales" above an higher per unit costs for gas used for generation. Purchased power increased in 1993 due primarily to increased; ' power purchased from nonassociated utilities due to changes in generation requirements for AP&L, LP&L, MP&; and NOPSI, resulting primarily from changes in fuel-related costs and increased energy sales. Fuel expense and purchased power increased in 1992 as a result of the nuclear refueling outages. In addition to the increased foss generation AL~ ad in
- Revenues and Sales" above, additional power was purchased from outsule utihties in 199 Gas purchased for resale ir M in 1993 due to a higher average per unit cost for gas youM while it declined [
in 1992 due primarily to a lower average per unit cost. Rate deferrals AM in 1993 and 1992 due to the fact that as of October 1992, Grand Gulf 1-related costs are no longer being deferred. The amortization of rate deferrals increased in 1993 due primarily to the collection of more Grand Gulf 1-related costs from customers in 1993 as compared to 1992. Total mcome taxes increased in 1993 due primarily to lugher pretax income, an increase in the federal mcome tax rate as a result of the Omnibus Budget Ramaciliation Act of 1993, and the implementatian of , SFAS 109, partially offset by the impact of the March 1992 sale of AP&L's Missouri properties i
.l Miscellaneous other income - net decreased in 1993 and increased in 1992 due primarily to the 1992 pretax gain of approximately $33.7 million from the sale of AP&L's retail properties in Missouri. Additionally, decreased interest income contributed to the 1993 decrease. Interest on long-term debt AM in 1993 and 1992 due primarily to the continued refinancing of high-cost debt and debt reduction activities.
l l 2
l 1 l i ENTERGY CORPORATION AND SUBSIDIARIES j 1 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS ! SIGNIFICANT FACTORS AND KNOWN TRENDS Enterry Corporation-GSU Merrer On December 31,1993, Entergy completed the Merger and became one of the nation's largest electric utilities. With GSU as its fifth retail operating company, Entergy gains size, expanded market area, economies of scale, an additional nuclear unit (River Bend), and a mere priceempetitive fuct mix. Entergy estimates $850 million in fuel cost savings and $670 million in operation and maintenance expense savings over the next decade. It is possible that common shareholders may experience some dilution in carmngs in the short term as a result of the Merger. However, Entergy Corporation believes that the Merger will be beneficial to common shareholders over the longer term, both in terms of the strategic benefits and the economics and efficiencies expected to be produced. For further information, see Notes 2 and 11, incorporated herein by reference. Competition Entergy welcomes competition in the electric energy business and believes that a more competitive emironment should benefit our shareholders, customers, and employees. We also recognize that competition presents us with many challenges, and we have identified the following as our major competitive challenges. Retail and Wholesale Rate Issues Increasing competition in the utility industry brings an increased need to stabilize or reduce retail rates. He retail regulatory environment is shifting from traditional rate-base regulation to incentive rate regulation. Incentive rate and performance-based plans encourage efficiencies and productivity while permitting utilities to share in the results, he MPSC has approved a formula rate plan for MP&L, and GSU is implementing shared-savings plans as part of the Merger. In February 1994, the MPSC conducted a general review of MP&L's current rates and in March 1994, the MPSC issued a final order adopting a formula rate plan for MP&L that will allow for periodic small adjustments in rates based on a comparison of camed to benchmark retums and upon certain performance factors. He order also adopted previously agreed-upon stipulations of 1) a required retum on equity of 11% and 2) certain accounting adjustments that result in a 4.3% ($28.1 million) reduction in MP&L's June 30,1993, test-year operating revenues. He MPSC's order requires MP&L to file rates designed to provide for this reduction in operating revenues for the test year on or before March 18,1994, to become effective for service rendered on or after March 25,1994. See Note 2, incorporated herein by reference, for further information. In connection with the Merger, AP&L and MP&L agreed with their respective regulators not to request any general retail rate increases that would take effect before November 1998, with certain exceptions. NOPSI agreed with the Council to reduce its annual electric base rates by $4.8 million effective for bills rendered on or after November 1,1993, and is operating under electric and gas base rate freezes through October 31,1996. GSU agreed with the LPSC and PUCT to a five-year Rate Cap on retail electric rates, and to pass through to retail customers the fuel savings and a certain percentage of the nonfuel savings created by the Merger. See Note 2, incorporated herein by reference, for further information on Merger-related agreements. GSUs base rates will be reviewed by the LPSC during the first post-Merger cammgs analysis, scheduled , for mid-1994, for reasonableness of its retum on equity. The PUCT will also review GSU's base rates in accordance with its Merger approval plan in mid-1994. Further, LP&L is scheduled for a resiew of its rates and rate structure by the LPSC upon expiration of LP&L's current rate freeze in March 1994. Under the same LPSC order, an approximate $46 million per year increase in LP&L's retail rates will also expire in March 1994. See Note 2, incorporated herein by reference, for additional information. i
ENTERGY CORPORATION AND SUBSILIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS l SIGNIFICANT FACTORS AND KNOWN TR".NDS -(Continued) l l l Retail wheeling, a major industry issue which may require utilities to " wheel" or move power from third parties to their own retail customers, is evohing gradually. As a result, the retail market could become more competitive. In the wholesale rate area, FERC approved in 1992, with certain modifications, the proposal of l AP&L, LP&L, MP&L, NOPSI, and Entergy Power to sell wholesale power at market-based rates and to provide to electne utilities "open access" to the System's transmission system (subject to certain requirements). GSU was later
- added to this filing. Various intervenors in the proceedmg filed petitions for review with the United States Court of Appeals for the District of Columbia Circuit. FERC's order, once it takes effect, will increase marketing oppor* unities for the System, but will also expose the System to the risk ofloss ofload or reduced revenues due to l
competition with alternative suppliers. In light of the rate isrees discussed above, Entergy is aggressively reducing costs to avoid potential earmngs crosions that might re : as well as to successfully compete by becoming a low-cost producer. To help nummize future costs, Entergy anams committed to least cost plannmg. In December 1992, AP&L, LP&L, MP&L, and NOPSI each filed a Least Cost Integrated Resource Plan (Least Cost Plan) with their respective retail regulators, and GSU is currently working with the PUCT regarding integrated resource planning. Integrated resource or least cost planning includes demand-side measures such as customer energy conservation and supply-side measures such as more efficient power plants. Rese measures are designed to delay the building of new power plants for the next 20 years. He System operating companies plan to periodically file least Cost Plans. The Enerev Policy Act of1992 The Energy Policy Act of 1992 (Energy Act) is changing the transmission and distribution of electricity. His act encourages competition and affords us the opportunities, and the risks, as ociated with an open and more competitive market environment. He Energy Act increases competition in the wholesale energy market through the creation of exempt wholesale generators (EWGs). We are competing in this market through our independent power subsidiary, Entergy Power Development Corporation. He Energy Act also gives FERC the authority to order investor-owned utilities to provide transmission access to or for other utilities, including EWGs. In addition, the Energy Act allows utilities to own and operate foreign generation, transmission, and distribution facilities. See "Nonregulated Investments" below for further information. Litiestion and Rerulatory Proceedines See Note 2, incorporated herein by reference, for information on the possibility of material adverse effects on GSU's financial condition as a result of substantial write-offs and/or refunds in connection with outstanding appeals and remands regarding approximately $1.4 billion of abeyed company-wide River Bend plant costs and approximately $187 million of Texas retailjurisdiction deferred River Bend operating and carrying costs. See Note 2, incorporated herein by reference, for information with respect to possible write-offs and refunds by System Energy which may result from a decision issued by FERC. See Note 8, incorporated herein by reference, for information on pending litigation with Cajun conceming Cajun's ownership interest in River Bend and the possible material adverse effects on GSU's financial condition in the event that GSU is ultimately unsuccessful in this litigation. l l \ i
- 4. am-.4 . Jl 8- ~ ,Ca4-- - - .++<b- e - - + = - - h-- 4 4 ^au,+- J- - +p e m.h -- nare-- e-= = ' -
h l ENTERGY CORPORATION AND SUBSIDIARIES MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS -(Concluded) Nonreru!sted Investments l Entergy continues to seek new opporturdties to expand its electric energy business, including expansion into f related nonutility businesses. These opportunities include new domestic ventures such as our subsichary, Entergy Systems and Service, Inc. (Entergy SASI), the region's only full-service provider of energy-efficient lighting and related services; established ventures in Argentina; and planned investments in South America and Chma. "Ihese : nonregulated businesses reduced consolidated na mcome by approximately $24 million in 1993. Entergy l Corporation expects to invest approximately $150 million per year in nonregulated business opportumties. Entergy ; may fmance any such expansion with cash on hand. Further, shareholder and/or regulatory approvals may be l required for such acquisitions to take place. For information on Entergy Corporation's investments in Argannna, l see " Management's Financial Discussion and Analysis - Liquidity and Capital Resources," incorpo.e4 herem by : reference. l ANO Matters Leaks in certain steam generator tubes at ANO 2 were discovered and repaired durmg outages in March ; and September 1992. During a mid-cycle outage in May 1993, a scheduled special mspection of centain staun generator tubing was conducted by Entergy Operations and additional repairs were rnada ne operations and '
'.".o-power output of ANO 2 have not been adversely affected by these repairs and AP&L's budgmed l expenditures were adequate to cover the cost c,f such repairs. Entergy Operations is takmg steps at ANO 2 to l i
reduce the number and severity of future tube cracks Entergy Operations met with the Nuclear Farh y Commission (NRC) in August 1993 to discuss such steps along with recent i a& findmgs and meervals [ between future inspections. The NRC concurred with Entergy Operations' proposal to operate ANO 2 with no ! further steam generator inspections until the next refueling outage, which is scheduled for the spring of 1994. I t i I i 1
- 77 - l 1
i i
ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES The accompanying consolidated financial statements include the accounts of Entergy Corporation and its direct and indirect subsidiaries: AP&L, GSU, LP&L, MP&L, NOPSI, System Energy, Entergy Operations, Entergy Power, Entergy Power Development Corporation, Entergy Richmond Power Corporation, Entergy Services, Inc., System Fuels, Entergy Enterprises, Entergy SASI, Entergy S.A., Entergy Argentina S.A., and Entergy Transener S.A. Because the acquisition of GSU was consummated on December 31, 1993, under the purchase method of accounting, GSU is included only in the December 31, 1993, consolidated balance sheet amounts. All references made to Entergy or System as of, and subsequent to, the Merger closing date include amounts and information pertauung to GSU as an Entergy company. All significant intercompany transactions have been eliminated. Entergy Corporation's utility subsidiaries maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications. Revenues and Fuel Costs The System operating companies accrue estimated revenues for energy delivered since the latest billings. However, prior to January 1,1993, AP&L, GSU, MP&L, and NOPSI recognized electric and gas revenues when billed. To provide a better matching of revenues and expenses, effective January 1,1993, AP&L, GSU, MP&L, and NOPSI adopted a change in accounting principle to provide for accrual of estunated unbilled revenues. 'Ibc cumulative effect of this accounting change as of January 1,1993 (excluding GSU), increased net income by $93.8 million, or 50.54 per share. Had this new accounting method been in effect during prior years, net income before the cumulative effect would not have been materially different from that shown in the accompanying fmancial statements. In accordance with an LPSC rate order, GSU recorded a deferred credit for $16.6 million for the January 1,1993, amot.nt of unbilled revenues. The System operating companies' rate schedules (except GSU's Texas rate schedules) include fuel adjustment clauses that allow either current recovery or deferrals of fuel costs until such costs are reflected in the related revenues. GSU's Texas retail rate schedules include a fixed fuel factor approved by the PUCT, which remains the same until changed as part of a general rate case or fuel reconciliation, or until the PUCT orders a reconciliation for any over or under collections of fuel cost. , Utility Plant ; Utility plant is stated at original cost. The original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the utility plant is subject to liens of the subsidiaries' mortgage bond indentures. AFUDC represents the approxunate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases utility plant and increases canungs, it is only realized in cash through depreciation previsions included in rates. The System operating companies' effective composite rates for AFUDC were 10.6% for 1993 and 10.8% for 1992 and 1991. , Utility plant includes the portions of Grand Gulf I and Waterford 3 that were sold and are currently under lease. For financial reporting purposes, these sale and leaseback transactions are ieflected as financing transactions. j l
\
. . - ~ - . . . --. . ..- - -- - - - ._ ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) , Depr==w= is computed on the straight-line basis at rates based on the ei==*~i service lives and costs of removal of the vanous classes of property. Depreciation provisions on average depreciable property approvi=='~' 3.0% in 1993,1992, and 1991. Jointiv-Owned Cc.c. etism Stations Certam Entergy Corporation subsidiaries own undivided sterests in several jointly-owned electnc generatmg facilities and record the investments and --n=~ associated with these stations to the extent of their respective ownership imiea == As of December 31, 1993, the System's investment and accumulated l depreciation in each of these generatmg stations were as follows. l Total Megawatt Accumulated Generatine Stations Fuel Tyne Canability Ownership Investment Deoreciation (In Thousands) Nuclear 1,143 90.00 %
- S3,449,068 $669,666 Grand Gulf Unit 1 Nuclear 931 70.00 % S3,056,464 5545,740 River Bend Coal 1,680 56.50 % $ 543,659 $156,645
!W Units 1 and 2 1,660 57.00 % 5 398,644 $140,731 White Bluff Units 1 and 2 Coal Roy S. Nelson , Unit 6 Coal 550 70.00 % ' S 389,915 $134,877 Unit 3 Coal 540 42.00 % $ 219,911 5 68,150 Big Cajun 2
- Includes System Energy's ownership and leaschold interests in Grand Gulf I Income Taxes ,
Entergy Corporation and its subsidianes file a consolidated federal mcome tax return (excludmg GSU prior to 1994). Income taxes are allocated to the System compames in proportion to their contribution to consohdated taxable mcome. SEC rand h require that no System company pay more taxes than it would have had a separate income tax return been filed. Deferred taxes are recorded for all temporary differences between book and taxable income. Investment tax credits are deferred and amortized based upon the average useful life of the related property in accordance with rate treatment. As discussed in Note 3, effective January 1,1993, Entergy changed its accounting for income taxes to conform with SFAS 109. l Rescauired Debt The premiums and costs ===~-i='~i with reacquired debt are being amortized over the life of the related new issuances, in accuidi w with r='an=Wg treatment. Cash and Cash Eauivalents Entergy considers all unrestricted highly liquid debt mstruments purchased with an original matunty of - three months or less to be cash equivalents. SFAS 101 SFAS 101 specifies how an enterprise that ceases to meet the criteria for application of SFAS No. 71, ,
" Accounting for Certain Types of Regulation," to all or part ofits operations should report that event in its financial + . - - . . , . , . . - .
ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) statements. GSU discontinued regulatory accounting principles for the wholesale jurisdiction and steam department, and the Louisiana deregulated portion of River Bend, during 1989 and 1991, respectively. Fair Value Disclosures The estimated fair value amounts of fmancial instruments have been determined by Entergy, using available market information and appropriate valuation methodologies. However, considerable judgment is required in developing the estunates of fair value. Therefore, estunates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. In addition, gains or losses realized on financial instruments may be reflected in future rates and not accrue to the benefit of stockholders. Entergy considers the carrying amounts of fmancial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. In addition, Entergy does not presently expect that performance ofits obligations will be required in connection with certam off-balance sheet commitments and guarantees considered fmancial instruments. Due to this factor, and because of the related party nature of these commitments and guarantees, determination of fair value is not considered practicable. See Notes 5,6, and 8 for additional fair value disclosure. NOTE 2. RATE AND REGULATORY MATTERS River Bend in May 1988, the PUCT granted GSU a permanent increase in annual revenues of $59.9 million resulting , from the inclusion in rate base of approximately $1.6 billion of company-wide River Bend plant investment and j approximately $182 million of related Texas retail jurisdiction deferred River Bend costs (Allowed Deferrals). In 1 addition, the PUCT disallowed as imprudent $63.5 million of company-wide River Bend plant costs and placed in i abeyance, with no finding of prudency, approximately $1.4 billion of company-wide River Bend plant investment and approximately $157 million of Texas retailjurisdiction deferred River Bend operating and carrying costs. He ; PUCT affirmed that the ultimate rate treatment of such amounts would be subject to future demonstration of the prudency of such costs. GSU and intervening parties appealed this order (Rate Appeal) and GSU filed a separate rate case asking that the abeyed River Bend plant costs be found prudent (Separate Rate Case). Intervening parties filed suit in district coun to prohibit the Separate Rate Case. He district court's decision was ultimately appealed ; to the Texas Supreme Court which ruled in 1990 that the prudence of the purported abeyed costs could not be l relitigated in a separate rate proceedmg. Further, the Texas Supreme Court's decision stated that all issues relating to the merits of the original order of the PUCT, including the prudence of all River Bend-related costs, should be j addressed in the Rate Appeal. In October 1991, the district court in the Rate Appeal issued an order holding that, while it was clear the PUCT made an error in assuming it could set aside $1.4 billion of the total costs of River Bend and consider them ! in a later proceeding, the PUCT, nevertheless, found that GSU had not met its burden of proof related to the amounts placed in abeyance. The court also ruled the Allowed Deferrals should not be included in rate base under a 1991 decision regarding El Paso Electric Company's similar deferred costs (El Paso Case). He court further stated that the PUCT erred in reducing GSU's deferred costs by $1.50 for each $1.00 of revenue collected under the interim rate increases authorized in 1987 and 1988. The court remanded the case to the PUCT with instructions as to the proper handling of the Allowed Deferrals. GSU's motion for rehearing was denied, and in December 1991, GSU filed an appeal of the October 1991 district court order. He PUCT also appealed the October 1991 district court order, which served to supersede the district court's judgment, rendering it unenforceable under Texas law. ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) In August 1992, the court of appeals in the El Paso Case handed down its second opinion on rehearing modifying its previous opinion on deferred accounting. He coun's second opinion concluded that the PUCT may lawfully defer operating and maintenance costs and subsequently include them in rate base, but that the Public Utility Regulatory Act prohibits such rate base treatment for deferred carrying costs. De court stated, however, its opinion would not preclude the recovery of deferred carrymg costs. He August 1992 court of appeals opinion was appealed to the Texas Supreme Court where arguments were heard in September 1993. He matter is pendmg. In September 1993, the Texas nird District Court of Appeals (the nird District Coun) remanded the October 1991 district court decision to the PUCT "to reexamme the record evidence to whatever extent necessary to render a final order supported by substantial evidence and not inconsistent with our opinion." ne hird District Court specifically addressed the PUCTs treatment of certain costs, stating that the PUCTs order was not based on substantial evidence. He Bird District Coun also applied its most recent ruling in the El Paso Case to the deferred costs associated with River Bend. However, the hird District Court cautioned the PUCT to confme its deliberations to the evidence addressed in the original rate case. Certain parties to the case have indicated their position that, on remand, the PUCT may change its original order only with respect to matters specifically discussed by the Third District Court which, if allowed, would increase GSU's allowed River Bend investment, net of accumulated depreciation and related taxes, by approxunately $48 million as of December 31,1993. GSU believes that under the Bird District Coun's decision, the PUCT would be free to reconsider any aspect of its order concerning the abeyed $1.4 billion River Bend investment. GSU has filed a motion for reheanng asking the Third District Court to modify its order so as to permit the PUCT to take additional evidence on remand. %e PUCT and other parties have also moved for rehearing on various grounds. The Third District Court has not yet ruled on any of these motions. As of December 31,1993, the River Bend plant costs disallowed for retail r*=Wg purposes in Texas, and the River Bend plant costs held in abeyance and the related cost deferrals totaled (net of taxes) approximately $14 million, $300 million (both net of depreciation), and $171 million, respectively. Allowed Defenals were , approximately $95 million, net of taxes and amortization, as of December 31,1993. GSU estunates it has collected approxunately $139 million of revenues as of December 31, 1993, as a result of the originally ordered rate treatment of these deferred costs. However, if the PUCT adopts the most recent decision in the El Paso Case, the possible refunds approximate $28 million as a result of the inclusion of deferred carrying costs in rate base for the period July 1988 through December 1990. However, if the PUCT reverses its decision to reduce GSU's deferred costs by $1.50 for each S1.00 of twenue collected under the interim rate increases authorized in 1987 and 1988, the potential refund of amounts described above could be reduced by an amount ranging from $7 million to $19 million. No assurance can be given as to the timing or outcome of the remands or appeals described above. Pending i further developments in these cases, GSU has made no write-offs for the River Bend-related costs. Management l believes, based on advice from Clark, Romas & Winters, a Professional Corporation, legal counsel of record in the 1 Rate Appeal, that it is reasonably possib!c that the case will be remanded to the PUCT, and the PUCT will be allowed to rule on the prudence of the abeyed River Bend plant costs. Rate Caps imposed by the PUCTs regulatory approval of the Merger could result in GSU being unable to use the full amount of a favorable decision to immediately increase rates; however, a favorable decision could permit some inc rases and/or limit or prevent decreases during the period the Rate Caps are in effect. At this time, management and legal counsel are unable to predict the amount, if any, of the abeyed and previously disallowed River Bend plant costs that ultimately may be disallowed by the PUCT. A net of tax write-off as of December 31,1993, of up to $314 million could be required based on the PUCTs ultimate ruling. In prior proceedmgs, the PUCT has held that the original cost of nuclear power plants will be included in rates to the extent those costs were prudently incurred. Based upon the PUCTs prior decisions, management believes that its River Bend construction costs were prudently incurred and that it is reasonably possible that it will i 1
ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) recover in rate base, or otherwise through means such as a deregulated asset plan, all or substantially all of the abeyed River Bend plant costs. However, management also recogmzes that it is reasonably possible that not all of the abeyed River Bend plant costs may ultimately be recovered. As part of its direct case in the Separate Rate Case, GSU filed a cost reconciliation study prepared by Sandlin Associates, management consultants with expertise in the cost analysis of nuclear power plants, which supports the reasonableness of the River Bend costs held in abeyance by the PUCT. His reconciliation study deternuned that approximately 82% of the River Bend cost increase above the amount included by the PUCT in rate base was a result of changes in federal nuclear safety requirements and provided other support for the remamder of the abeyed amounts. Here have been four other rate proceedmgs in Texas involving nuclear power plants. Investment in the plants ultimately disallowed ranged from 0% to 15%. Each case was unique, and the disallowances in each were made on a case-by-case basis for different reasons. Appeals of most, if not all, of these PUCT decisions are currently pendmg. He following factors support management's position that a loss contingency requiring accrual has not occurred, and its belief that all, or substantially all, of the abeyed plant costs will ultimately be recovered:
- 1. He $1.4 billion of abeyed River Bend plant costs have never been mied imprudent and disallowxd by the PUCT.
- 2. Sandlin Associates' analysis which supports the prudence of substantially all of the abeyed construction costs.
- 3. Historical inclusion by the PUCT of prudent construction costs in rate base.
- 4. He analysis of GSUs internal legal staff, which has considerable experience in Texas rate case litigation.
Additionally, management believes, based on advice from Clark, Thomas & Winters, a Professional Corporation, legal counsel of record in the Rate Appeal, that it is probable that the deferred costs will be allowed. However, assuming the August 1992 court of appeals' opinion in the El Paso Case is upheld and applied to GSU and the deferred River Bend costs currently held in abeyance are not allowed to be recovered in rates as allowable costs, a net of tax write-off of up to $171 million could be required. In addition, future revenues based upon the deferred costs previously allowed in rate base could also be lost and no assurance can be given as to whether or not refunds (up to $28 million as of December 31,1993) of revenue received based upon such deferred costs presiously recorded will be required. See Note 1I for the accounting treatment of preacquisition contingencies, including a River Bend write-down. htercer-Related Rate Acreements In November 1993, Entergy Corporation, AP&L, MP&L, and NOPSI entered into separate settlement agreements whereby the APSC, MPSC, and Council agreed to withdraw from the SEC prWing related to the Merger. In retum, among other things, AP&L, MP&L, and NOPSI agreed that their retail ratepayers would be protected from (1) increases in the cost of capital resulting from risks associated with the Merger, (2) recovery of j l any portion of the acquisition premium or trnnemtinnal costs associated with the Merger, (3) certain direct l allocations of costs associated with GSUs River Bend nuclear unit, and (4) any losses of GSU resulting from resolution of litigation in connection with its ownership of River Bend. AP&L and MP&L agreed not to request any general retail rate increase that would take effect before November 1998, except, among other things, for
ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) increases associated with the Least Cost Plan, recovery of certain Grand Gulf 1-related costs, recovery of certain taxes, and force majeure (defmed to include, among other things, war, natural catastrophes, and high inflation), and in the case of AP&L, excess capacity costs and costs related to the adoption of SFAS 106 that were previously deferred. MP&L also agreed that retail base rates under its proposed formula rate plan would not be increased above November 1,1993, levels for a period of five years begnuung November 9,1993, (described below). NOPSI was required to reduce its annual electric base rates by $4.8 million effective for bills rendered on or af!ct November 1,1993, and to expense its SFAS 106 costs. Further, NOPSI's SFAS 106 expenses through l October 31,1996, will be allowed by the Council for purposes of evaluatmg the appropriateness of NOPSTs rates. He Council also agreed not to seek to disallow the first $3.5 million of costs incurred through October 31,1993, in connection with the Ieast Cost Plan. The LPSC and the PUCT approved separate regulatory proposals that include the following elements: (1) a five-year Rate Cap on GSU's retail electric base rates in the respective states, except for force majeure (defined to include, among other things, war, natural catastrophes, and high inflation); (2) a prosision for passing through to retail customers in the respective states the jurisdictional portion of the fuel savings created by the Merger; and (3) a mechanism for tracking nonfuel operation and maintenance savings created by the Merger. The LPSC regulatory plan provides that such nonfuel savings will be shared 60% by the shareholder and 40% by ratepayers during the eight years following the Merger. He LPSC plan requires regulatory filings each year by the end of May through 2001. He PUCT regulatory plan provides that such savings will be shared equally by the shareholder and ratepayers, except that the shareholder's portion will be reduced by $2.6 million per year on a total company basis in years four through eight. The PUCT plan also requires a series of regulatory filings, currently anticipated to be in June 1994, and February 1996,1998, and 2001, to ensure that ratepa>trs' share of such savings be reflected in rates on a timely basis and requires Entergy Corporation to hold GSU's Texas retail customers harmless from the effects of the removal by FERC of a 40% cap on the amount of fuel savings GSU may be required to transfer to other Entergy operating companies under the FERC tracking mechanism (see below). On January 14, 1994, Entergy Corporation filed a request for rehearmg of FERC's December 15, 1993, order appro5ing the Merger requestmg that FERC restore the 40% cap provision in the fuel cost protection mechanin. He matter is pending. FERC approved certain rate schedule changes to integrate GSU into the Syoun Agreement. Certain commitments were adopted to provide reasonable assurance that the ratepayers of AT AL, LP&L, MP&L, and NOPSI will not be allocated higher costs, including, among other thmgs, (1) a trackmg mechanism to protect AP&L, LP&L, MP&L, and NOPSI from certain unexpected increases in fuel costs, (2) the distribution of profits from power sales contracts entered into prior to the Merger, (3) a methodology to estimate the cost of capital in future FERC proceedmgs, and (4) a stipulation that AP&L, LP&L, MP&L, and NOPSI will be insulated from certain direct effects on capacity equahmion payments should GSU, due to a finding of imprudent GSU management prior to the Merger, be required to purchase Cajun's 30% share in River Bend (see Note 8). Incentive Rate Plan in July 1993, the MPSC ordered MP&L to file a formulary incentive rate plan designed to allow for periodic small adjustments in rates based upon a comparison of earned to benchmark returns and upon performance factors incorporated in the plan. In November 1993, MP&L filed a formula rate plan (Proposed Plan) with the MPSC to become effective on March 1,1994, with any initial adjustment to base rates in June 1994. Under the Proposed Plan, a formula would be established under which MP&L's camed rate of return would be calculated automatically every 12 months and compared to a benchmark rate of return, which would be calculated under a separate formula within the Proposed Plan. If MP&L's earned rate of return falls within a bandwidth around the benchmark rate of return, there would be no adjustment in rates. If MP&L's cammgs are above the bandwidth, the Proposed Plan would automatically reduce MP&L's base rates. Altematively, if MP&L's earmngs are below the bandwidth, the Proposed Plan would automatically increase MP&L's base ratcs (subject to the five-year cap ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STMEMENTS -(Continued) described above under " Merger-Related Rate Agreements"). The reduction or increase in base rates would be an amount representing 50% of the difference between the earned rate of retum and the nearest limit of the bandwidth. In no event would the annual adjustment in rates exceed the lesser of 2% of MP&L's aggregate retail revenues, or $14.5 million. Under the Proposed Plan, the benchmark rate of return, and consequently the bandwidth, would be adjusted slightly upward or downward based upon MP&L's performance on three performance factors: customer reliability, customer satisfaction, and customer price. Subsequently, the MPSC conducted a general review of MP&L's current rates and later issued a final order adopting the Proposed Plan and previously agreed-upon stipulations of 1) a required retum on equity of 11% and
- 2) certain accounting adjustments that result in a 4.3% ($28.1 million) reduction in MP&L's June 30,1993, test-year base revenues. He MPSC's order requires MP&L to file rates designed to proside for this reduction in operating revenues for the test year on or before March 18,1994, to become effective for service rendered on or after March 25,1994.
LPSC Investiention in response to a prehnunary icport of the LPSC indicating that the rates of return on equity of several electric utilities subject to the LPSC's judsdiction may be too high, GSU provided the LPSC with information GSU believes supports the current rate level. In September 1993, the LPSC deferred review of GSU's base rates until the first post-Merger canungs analysis is fi;ed in accordance with the LPSC Merger approval (scheduled for mid-1994). Recogmzmg that LP&L is subject to a rate freeze until March 1994, the LPSC requested LP&L to explain its "relatively high cost of debt" compared to other electric utilities subject to LPSC jurisdiction. L?&L responded to this request, and in an August 1993 report to the LPSC, the LPSC's legal consultants acknowledged LP&L's rationale for its cost of debt in comparison to two other utilities subject to the LPSC's jurisdiction. Further, the legal consultants suggested that certain aspects of the LP&L cost of debt could be taken up in any rate proceedmg after the expiration of LP&L's rate freeze in March 1994. In October 1993, the LPSC approved a schedule to conduct a review of LP&L's rates and rate structure upon the expiration of LP&L's current rate freeze FERC Audit In December 1990, FERC Division of Audits issued a report for System Energy for the years 1986 through 1988. The report recommended that System Energy (1) write off, and not recover in rates, approximately 595 million of Grand Gulf I costs included in utility plant related to certain System income tax allocatior procedures alleged to be inconsistent with FERC's accounting requirements, and (2) compute refunds for the years 1987 to date to correct for resulting overcollections from AP&L, LP&L, MP&L, and NOPSI. In August 1992, FERC issued an opinion and order (August 4 Order) which found that System Energy overstated its Grand Gulf I utility plant account by approximately $95 million as indicated in FERC's report. He order required System Energy to make adjusting accounting entries and refunds, with interest, to AP&L, LP&L, MP&L, and NOPSI within 90 days from the date of the order. System Energy filed a request for rehearing, and in October 1992, FERC issued an order allowing additional time for its consideration of the request. In addition, it deferred System Energy's refund obligation until 30 days after FERC issues an order on reheanng. Assuming AP&L, LP&L, MP&L, and NOPSI are required to refund or credit to their customers all of the System Energy refimd (except for those portions attributable to AP&L's and LP&L's retamed share of Grand Gulf I costs), implementation of the August 4 Order would result in a reduction in Entergy's consolidated net income of approximately $146.4 million as of December 31, 1993. However, this reduction could be partia!!y ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) l l offset by- (1)the write-off by AP&L, LP&L, MP&L, and NOPSI of unamortized balances of corresponding l deferred credits (approumately $66.7 million as of December 31,1993), and (2) any recovery from ratepayers of deferred credits that have been previously amortized and passed on to ratepayers (approximately $24.4 million as of , l December 31,1993). He amount of such recovery would depend on the associated retail rate treatment System Energy believes that its consolidated income tax accennng procedures and related rate treatment are in compliance with SEC and FERC requirements and is vigorously contestmg this issue. He ultimate resolution of this matter cannot be predicted. If the August 4 Order is implemented, System Energy needs the consent of certain banks to temporarily waive the fixed charge coverage and equity ratio covenants in the letters of credit and reimbursement agreement related to the Grand Gulf I sale and leaseback transaction (see Notes 6 and 9). System Energy has obtamed the consent of the banks to waive these covenants, for the 12-month period begmnmg with the earlier of the write off or l the first refund, if the August 4 Order is implemented prior to December 31,1994. He waiver is conditioned upon System Energy not paying any common stock dividends to Entergy Corporation until the equity ratio covenant is once again met. Absent a waiver, System Energy's failure to perform these covenants could cause a draw under the letters of credit and/or early ternunation of the letters of credit. If the letters of credit were not replaced in a timely manner, a default or early temunation of System Energy's leases could result. Texas Cities Rate Settlemec+ In June 1993, 13 cities within 3Us Texas service area instituted an investigation to determme whether GSUs current rates were justified. In October 1993, the general counsel of the PUCT instituted an inquiry into the reasonableness of GSUs rates. In November 1993, a settlement agreement was filed with the PUCT which provides for an initial reduction in GSUs annual retail base revenues in Texas of appr=im*1y $22.5 million effective for electric usage on or after November 1,1993, and a second reduction of $20 million to be effective September 1994. Further, the settlement provided for GSU to reduce rates with a $20 million one-time bill credit in December 1993, and to refund approxunately $3 million to Texas retail customers on bills rendered in December 1993. The cities' rate inquiries had been settled earlier on the same terms. In November 1993, in association with the settlement of the above-described rates inquiries, GSU entered into a settlement covering issues related to a March 1991 non-ur=hn settlement in another proceedmg. Under this settlement, a $30 million rate increase approved by the PUCT in March 1991 became final, and the PUCTs treatment of GSUs federal tax expense was settled, elimimHng the possibility of refunds associated with amounts collected resulting from the disputed tax calculation. In December 1993, a large industrial customer of GSU announced its intention to oppose the settlement of the PUCT rate inquiry. He customer's opposition does not affect the cities' rate settlement. He customer's opposition requires the PUCT to conduct a heanng concemmg GSUs rates charged in areas outside the corporate limits of the cities in its Texas service territory to determme whether the settlement's rates are just and reasonable. A hearing has been set for July 8,1994. GSU believes that the PUCT will ultimately approve the settlement, but no assurance can be pmvided in this regard. Rate Deferrals He System operatmg companies have various rate moderation or phase-in plans that reduced the immediate effect of Grand Gulf 1, River Bend, and Waterford 3 costs on ratepayers. Under these plans, certain costs are either retamed permanently (and not recovered from ratepayers), deferred in early years and collected in later years, or recovered currently from customers. Rese plans vary in the proportions of costs each company retams, defers, or recovers and in the length of the deferral / recovery periods. Only those costs retained permanently
ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) and not recovered through rates or through sales to third parties result in a reduction of net income. The carrying charges associated with unamortized deferrals are either deferred or recovered currently from customers. The 1991 NOPSI Settlement provided for a fmalized phase-in plan for the increased recovery of NOPSI's Grand Gulf I-related costs over a 10-year period and for a five-year base rate freeze (subject to certain exceptions) with respect to non. Grand Gulf I clectric rates. In 1991, NOPSI recorded on its balance sheet a $90 million I deferred asset of previously incurred but unrecovered Grand Gulf 1-related costs, with a corresponding pretax gain on the income statement. His gain increased 1991 consolidated net income by $48.6 million after taxes. l GSU deferred approxunately $369 million of River Bend operatmg costs, purchased power costs, and accrued carrying charges pursuant to a 1986 PUCT accounting order. Approxunately $182 million of these costs are being amortized over a 20-year period and the remaming $187 million are not being amortized pending the ultima:e outcome of the Rate Appeal. As of December 31, 1993, the unamortized balance of these costs was $330.3 million. Further, GSU deferred approxunately $400 million of similar costs pursuant to a 1986 LPSC accounting order. These costs, of which approxunately $160.4 million are unamortized as of December 31,1993, are being amortized over a 10-year period. Previous rate orders of the LPSC have been appealed, and pendmg resolution of various appellate proceedmgs, GSU has made no write-off for the disallowance of $30.6 million of deferred revenue requirement, related to GSI.fs louisiana phase-in plan, recorded for the period December 1987 through February 1988. AP&L's permanently retamed share of Grand Gulf I costs (stated as a percentage of System Energy's 90% owned and leased share of Grand Gulf 1) ranges from 5.67% in 1989 to 7.92% in 1994 and all succeedmg years of the unit's commercial operation. In the event AP&L is not able to sell its retamed share to third parties, it may sell such energy to its retail customers at a price equal to its avoided energy cost, which is currently less than AP&L's cost of such energy. LP&L permanently absorbs 18% ofits 14% (approximately 2.52%) FERC-allocated share of Grand Gulf 1-related costs. LP&L is able to recover througti the fuel adjustment clause 4.6 cents per KWH (currently 2.55 cents per KWH through May 1994) for the energy related to its retained portion of these costs. Alternatively, LP&L may sell such energy to nonaffiliated parties at prices above the fuel adjustment clause recovery amount, subject to LPSC approval. For the year ended December 31,1993, System Energy's billings for Grand Gulf 1-related costs totaled approxunately $650 million. A deregulated asset plan representing an unregulated portion (approximately 22%) of River Bend (plant costs, generation, revenues, and expenses) was established pursuant to a January 1992 LPSC order. He plan allows GSU to sell such generation to Louisiana retail customers at 4.6 cents per KWH or off-system at higher prices with certam sinring provisions for such incremental revenue. FERC Settlements In September 1991, FERC approved a settlement among AP&L, LP&L, MP&L, and NOPSI and various state and local regulatory authorities which (1) required credits from System Energy to AP&L, LP&L, MP&L, and NOPSI of approximately $48 million, (2) increased System Energy's decommissioning collections, and (3) reduced the allowed rate of retum on common equity under the System Agreement and for System Energy from 14% to 13% As a result of the settlement,1991 consolidated net income was reduced by approximately $30 million. Pursuant to a subsequent settlement in another proceedmg, the allowed rate of retum was further reduced to 11% effective November 3,1992. Refunds from this settlement reduced 1993 consolidated revenues and net income by approximately $27.2 million and $16.8 million, respectively. ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) l NOTE 3. INCOME TAXES Effective January 1,1993, the System adopted SFAS 109 (exclu*ng GSU which recorded the adoption effective January 1,1990). This new standard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that deferred tax balances be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 requires that regulated enterprises recognize adjustments resulting from implementation as regulatory assets or liabilities if it is probable that such , amounts will be recovered from or returned to customers in future rates. A substantial majority of the adjustments required by SFAS 109 was recorded to deferred tax balance sheet accounts with offsetting adjustments to regulatory assets and liabilities. He cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. As a result of the adoption of SFAS 109,1993 net income and earmngs per share were decreased by $13.2 million and $0.08 per share, respectively, and assets and liabilities were increased by 5822.7 million and $835.9 million, respectively. Income tax expense consisted of the following: For the Years Ended December 31. 1993 1992 1991 (In Thousands) Current: Federal $236,513 $ 99,808 S 64,111 State 30.618 23.596 13.158 Total 267.131 123.494 77.269 Deferred - net: Reclassification due to net operating loss carryforward (17,131) 35,969 (22,516) Rate deferrals - net (88,651) (54,079) (3,248) Gas contract settlement 9,513 15,180 15,342 Liberalized depreciation 116,513 107,976 116,266 Unbilled revenue 56,315 ~ (18,902) 6,633 Alternative muumum tax (10,270) 6,577 16,019 Bond reacquisition cost 17,958 11,496 (1,256) Nuclear refueling and maintenance (7,929) 9,740 484 Decontanunation and decommissioning fund 27,303 - - Other 15.035 (1.595) (6.465) Total 118.656 112.362 121.259 Investment tax credit adjustments - net (43.796) 20.607 78.623 Recorded income tax expense $341991 $256.463 $277.151 Charged to operations $251,163 5210,081 $243,760 Charged to other income 33,640 46,382 33,391 Charged to cumulative effect 57.188 - - Recorded income tax expense 341,991 256,463 277,151 Income taxes applied against the debt component of AFUDC - 696 886 Total income taxes $341.991 $257.159 $278.037 ENTERGY CORPORATION AND S~UBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Total income taxes differ from the amounts computed by applying the statutory federal income tax rate to income before taxes. The reasons for the differences were: For the Years Ended December 31 1993 1992 1991
% of % of % of Pretax Pretax Pretar Amount income Amount Income Amount income (Dollars in Thousands)
$332,555 35.0 $257,461 34.0 $279,395 34.0 Computed at statutory rate Increases (reductions) in tax resulting from:
(7,063) (0.7) (6,537) (0.9) (7,318) (0.9) Amortization of excess deferred income taxes State income taxes net of federal income 30,160 3.2 26,057 3.5 23,741 2.9 tax effect (25,911) (2.7) (26,885) (3.6) (22,470) (2.7) Amortization ofinvestment tax credits 5,925 0.6 4,527 0.6 5,693 0.7 Depreciation SFAS 109 adjustment 9,547 1.0 - - Other - net (3.222) (0.4) 1.840 _ql (1.890) (0.2) Recorded income tax expense 341,991 36.0 256,463 33.9 277,151 33.8 Income taxes applied against debt component ofAFUDC - - 696 0.I 886 __QJ
$341.991 36.0 $257.159 34.0 $278.037 33.9 Totalincome taxes Significant components of net deferred tax liabilities as of December 31.1993, were (in thousands):
Deferred tax liabilities: Net regulatory assets $(1,676,161) Plant related basis differences (2,945,933) Rate deferrals (767,124) Other (167.478) Total $(5.556.696) R;frged tax assets: Sale and leaseback $ 241,391 Accumulated deferred investment tax credit 330,852 Alternative nummum tax credit 138,063 Removal cost 92,618 Standard coal plant 30,165 NOL carryforwards 307,737 Pension related items 24,879 Unbilled revenues 23,587 Investment tax credit carryforwards 314,862 Other 149.568 Total $ 1.653.722 Net deferred tax liabilities $(3.902.974)
i ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) l i As of December 31,1993, Entergy had federal net operating loss (NOL) carryforwards of $790.3 million l and state NOL carryforwards of $561.4 million related to GSU operations. Investment tax credit (ITC) and other credit carryforwards as of December 31,1993, amounted to $357.4 million. The ITC carnforwards include the ' 35% reduction required by the Tax Reform Act of 1986 and may be applied aramt federal income tax liabilities and, if not utilized, will expire in 1995 through 2005. It is currently anticipated that approxunately $15.2 million l will expire unutilized. A valuation allowance has been provided for that amount. Entergy's consolidated tax allocation reflects ITC carryforwards as of December 31,1993. The allocation i does not reflect any NOL carryforwards for the System. However, due to the current method of allocating taxes between subsidiaries, some companies have the tax effect of NOL carnforwards recorded on their separate company books. Tbc altemative muumum tax (AMT) credit canyforwards as of December 31,1993, were S138.1 million. This AMT credit can be carried forward indefinitely and will reduce the System's federal income tax liability in the future. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized AP&L, LP&L, MP&L, NOPSI, and System Energy to effect short-temi l borrowings up to an aggregate of SS 18 million, subject to increase to as much as $865 million (subject to individual authorizations for each company) after further SEC approval. These authorizations are effective through November 30,1994. Short-term borrowings by MP&L and NOPSI are also limited by the terms of their respective G&R Bond indentures to amounts not exceedmg the greater of 10% of capitahration or 50% of Grand Gulf I rate deferrals available to support the issuance of G&R Bonds. As of December 31,1993, AP&L, GSU, LP&L, and MP&L had unused lines of credit for short-term l borrowings of $197.6 million from banks within their service territories. Included in this amount for GSU was a ! S100 million bank credit agreement which expired on Marca 2,1994. In addition, AP&L, LP&L, MP&L, NOPSI, l System Energy, Entergy Operations, Entergy Services, Inc., and System Fuels can borrow from each other and from Entergy Corporation through the System money pool, an intra-System borrowing arrangement designed to , reduce the System's dependence on external short-term borrowings (Money Pool). A filing was made with the SEC l on January 4,1994, requesting authorization for GSU to participate in the Money Pool and enter into new bank i lines of credit and commercial paper arrangements. The filing requested a borrowing authorization of $125 million, ; subject to increase to a maxunum amount of $455 million after further SEC approval. j Entergy Corporation has a short-term line of credit, expiring September 17,1994, for $43 million (all of which was outstandmg as of December 31, 1993). Entergy Corporation has requested SEC approval for a l S300 million three-year bank line of credit. System Fuels has financing agreements totaling 565 million (none of which was outstandmg as of December 31, 1993). These are restricted as to use, and are secured by fuel inventories and certain accounts receivable from the sales of these inventories. j l i 1 1 I
o 1 ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) NOTE 5. PREFERRED, PREFERENCE, AND COMMON STOCK f l he number of shares and dollar value of the System operatmg companies' (excluding GSU in 1992)
- preferred and preference stxk was:
l As of December 31. Share Call Price Per l Authorized and Total Share as of Dollar Value December 31, Outstandine 1993 1992 1993 1992 1993 (Dollars in Thousands) Preferred Stock Without sinking fund: Cumulative, $100 par value 1,201,715 1,070,106 $120,172 $107,011 $102.50 to $108.00 4.16% - 5.56% Series 2,262,829 1,380,000 226,283 138,000 $101.80 to $103.78 6.08% - 8.56% Series ' 425,000 75,000 42,500 7,500 $104.06 to S104.64 9.16% - 11.48% Series Cumulative, $25 par value 3,880,000 3,880,000 97,000 97,000 $26.56 8.00% - 9.68% Series Cumulative, $0.01 par value 2,000,000 2,000,000 50,000 50,000 -
$2.40 Series (t)(2) 600.000 600.000 15.000 15.000 -
$1.96 Series (1)(2)
Total without sinking fund 10.369.544 9.005.106 M $414.511 With sinkmg fund: Cumulative, $100 par value 1,835,000 $212,654 $183,500 $100,00 to S106.75 7.00% - 9.76% Series 2,126,539 67,700 137,700 6,770 13,770 $104.09 to $106.00 10.60% - 12.92% Series 49,495 79,495 4,950 7,950 $107.72 15.44% - 16.16% Series Adjustable,7.10% - 7.15% as of December 31,1993 553,500 - 55,350 - $100.00 to $103.00 Cumulative, $25 par value 2,311,666 2,931,666 57,791 73,291 $26.34 to $27.37 l 9.92% - 12.64% Series 461.537 1.021.537 11.538 25.538 526.64 to $28.22 1 13.12% - 15.20% Series Total with sinkmg fund 5.570.437 6.005.398 $349.053 $304 049 l Preference Stock Cumulative, without par value 7% Series (1)(2) 6.000.000 - g S - - (1) De total dollar value represents the involuntary liquidation value of $25 per share. (2) Rese series are not redeemable as of December 31,1993. De fair value of the System operating companies' (excluding GSU in 1992) preferred and preference stock j with sinking fund was estimated to be approximately $526.2 million and $333.6 million as of December 31,1993 and 1992, respectively. He fair value was determined using quoted market prices or estimates from nationally recognized investment banking firms. See Note I for additional information on disclosure of fair value of fmancial mstruments. i
=.
i l ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) j l As of December 31,1993, the System operating companies had d,292,023,13,798,915, and 12,400,000 l shares of cumulative, $100, $25, and $0.01 par value preferred stock, respectively, and 14,000,000 shares of preference stock without par value, that were authorized but unissued. On February 4,1994, MP&L amended its charter to authorize 1,500,000 additional shares of $100 par value preferred stock. Changes in the preferred stock of AP&L, LP&L, MP&L, and NOPSI, with and without sinkmg fund, during the last three years were: 1 Number of Shares 1993 1992 1991 Preferred Stock Issuances:
$100 par value - 700,000 350,000
$25 par value - 1,480,000 2,000,000
$0.01 par value - 600,000 2,000,000 Preferred Stock Retirements:
S100 par value (265,000) (589,940) (530,060)
$25 par value (1,180,000) (1,895,160) (1,300,000)
Cash sinking fund requirements for the next five years for preferred stock outstandmg as of December 31,1993, are (in millions): 1994 - $37.6,1995 - $36.1,1996 - $28.1,1997 - $25.9, and 1998 - $15.6. On December 31,1993, Entergy Corporation issued 56,667,726 shares of common stock in connection with the Merger. In addition, Entergy Corporation redeemed 174,552,01I shares of $5.00 par value common stock and reissued 174,552,011 shares of $0.01 par value common stock resulting in an increase in paid-in capital of
$871 million.
Entergy Corporation has SEC authorization to repurchase, through December 31,1994, up to 27.1 million shares ofits outstanding common stock, either on the open market or through negotiated purchases or tender offers. Stock repurchases are made from time to time depending upon market conditions and authorization of the Entergy Corporation board. Under this program, Entergy Corporation repurchased and retired (retumed to authorized but unissued status) 3,671,900 shares and 6,447,900 shares, at a cost of $161.6 million and $105.7 million during 1992 and 1991, respectively. In addition,1,943 shares of treasury stock were purchased during 1992 at a cost of
$54,263. During 1993,627,000 shares of treasury stock were purchased at a cost of $20.6 million. A portion of l these treasury shares were subsequently reissued and in connection with the Merger on December 31,1993, all of the existing balance of 579,274 shares of treasury shares was canceled.
Entergy Corporation has SEC authorization to acquire, through December 31,1994, up to 3,000,000 shares ofits common stock to be held as treasury shares, and to be reissued to meet the requirements of the Stock Plan for Outside Directors (Directors Plan), the Equity Ownership Plan of Entergy Corporation and Subsidiaries (Equity Plan), and certain other stock benefit plans. He Directors Plan awards nonemployee directors a portion of their compensation in the form of a fixed number of shares of Entergy Corporation common stock. Shares awarded under the Directors Plan were 12,550,14,904, and 7,000 during 1993,1992, and 1991, respectively. He Equity Plan grants stock options, restricted shares, and equity awards to key employees of the System companies. Ac costs of awards are charged to income over the period of the grant or restricted period, as appropriate. Amounts charged to compensation expense in 1993 were immaterial. Stock options, which comprise 50% of the shares targeted for distribution under the Equity Plan, are granted at exercise prices not less than market value on the date i of grant. He options are generally exercisable no less than six months or more than 10 years after the date of grant. 1 ENTERGY CORPORATION AND SUBSIDIARIES , NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) Nonstatutory stock options transactions are summanzed as follows: Ootion Price Number of Ontions Options granted during 1992 29.625 50,000 Options exercised during 1992 29.625 (5,000) Options granted during 1993 34.75 62,500 39.75* 6,107 Options exercised during 1993 29.625 (8.198) , Options remauung as of December 31,1993 105.409 l I
- Options are not currently exercisable at Des. ember 31,1993.
During 1993, Entergy Corporation received SEC approval for the Employee Stock Investment Plan (ESIP) which will become effective in March 1994. Entergy Corporation received SEC authorization to issue new shares or acquire, through March 31,1997, up to 2,000,000 shares ofits common stock to be held as treasury shares, and to be reissued to meet the requirements of the ESIP Under the ESIP, employees may be granted the opportunity to purchase (up to 10% of regular pay) common stock at 85% of the market value on the first or last business day of the plan year, whichever is lower. 'Ihe 1994 plan year will run from April 1,1994, to March 31,1995. i ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) NOTE 6. LONG -TERM DEBT The long-term debt of Entergy Corporation's subsidiaries (excludmg GSU in 1992) as of December 31,1993 and 1992, was: Maturities Interest Rates l From To Ero.n.l To 1993 1992 (In Thousands) First Mortgage Bonds 1993 1998 4-5/8% 14%* S1,354,810 5 990,410 1999 2003 6% 11 % 1,143,520 861,220 2004 2008 6.65 % 10 % 635,000 282,767 2014 2018 9-5/8% 11-3/8 % 90,319 160,319 2019 2024 7% 10-3/8 % 1,083,818 588,550 G&R Bonds 1993 1998 5.95 % 14.95 % " 284,200 383,600 1999 2023 6-5/8% 8.65 % 350,000 - Governmental Obligations "* 1992 2008 6.125 % 10 % 139,009 115,383 2009 2023 5.95 % 12.5 % 1,481,678 963,382 Debentures - Due 1998,9.72% 200,000 - Long-Term DOE Obligation (Note 8) 101,029 97,959 Waterford 3 Lease Obligation, 8.76% (Note 9) 353,600 353,600 Grand Gulflease Obligation, 7.02% (Note 9) 500,000 500,000 Other Long-Term Debt 6,879 21,737 Unamortized Premium and Discount - Net (45.890) (35.778) Total Long-Term Debt 7,677,972 5,283,149 Less Amount Due Within One Year 322.010 133.805 Long-Term Debt Excluding Amount Due Within One Year $ 7.355.962 S5.149.344
* 'Ihe 14% series of $200 milhon is due 11/15/94. All other series are at interest rates within the range of 4-5/8 % - 11.375 %
" The 14.95% series of $20 million is duc 2/1/95. All other series are at interest rates within the range of i
5.95 % - 11.2 %
"* Consists of pollution control bonds and municipal revenue bonds, certain series of which are secured by non-interest bearmg first mortgage bonds The fair value of Entergy Corporation's long-term debt (excluding GSU in 1992), excluding lease obligations and long-term DOE obligations, as of December 31,1993 and 1992, was estunated to be
$7,207.3 million and $4,662.3 million, respectively. The fair values were deternuned using bid prices reported by dealer markets and by nationally recogmzed investment banking Erms.
For the years 1994,1995,1996,1997, and 1998, Entergy Corporation's subsidiaries have leng-term debt maturities (excluding lease obligations) and cash sinking fund requirements in the aggregate of(in millions) S321.4,
$378.4, $558.4, $361.9, and $315.9, respectively. In addition, other sinking fund requirements will be satisfied by
ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) cash or by certification of property additions at the rate of 167% of such requirements. The amounts associated with this provision total approximately $11.2 million for each of the years 1994 through 1998. NOTE 7. DIVIDEND RESTRICTIONS : Various agreemects relating to the long-term debt and preferred stock of Entergy Corporation's subsidiaries restrict the payment of cash dividends or other distributions on their common stock. In addition to these restrictions, the Public Utility Holding Company Act of 1935 prohibits Entergy Corporation's subsidiaries from makmg loans or advances to Entergy Corporation. As of December 31,1993, Entergy Corpontion's subsidiaries had restricted common equity of approximately $5,165.4 million, including $1,167.8 million of restricted retamed cammgs, which were unavailable for distribution to Entergy Corporation. In Febmary 1994, Entergy Corporation received common stock dividend payrnents totaling $198.2 million, including $100 million from GSU. Prior to this, GSU had not paid a common stock dividend since June 1986. l NOTE 8. COMMITMENTS AND CONTINGENCIES 1 Caiun - River Bend GSU has significant business relationships with Cajun, pnmarily co-ownership of River Bend and Big Cajun 2 Unit 3. GSU and Cajun own 70% and 30% of River Bend, respectively, while Big Cajun 2 Unit 3 is owned 42% and 58% by GSU and Cajun, respectively. GSU operates River Bend and Cajun operates Big Cajun 2 Unit 3. In June 1989, Cajun filed a civil action against GSU in the U. S. District Court for the Middle District of Louisiana. Cajun stated in its complaint that the object of the suit is to annul, rescind, termmate, and/or dissolve the Joint Ownership Participation and Operating Agreement entered into on August 28,1979 (Operating Agreement), related to River Bend. Cajun alleges fraud and error by OSU, breach ofits fiduciary duties owed to Cajun, and/or GSU's repudiation, renunciation, abandonment, or dissolution of its core obligations under the Operating Agreement, as well as the lack or failure of cause and/or consideration for Cajun's performance under the Operating Agreement. He suit seeks to recover Cajun's alleged $1.6 billion investment in the unit as damages, plus attorneys' fees, interest, and costs. In March 1992, the district court appointed a mediator to engage in settlement discussions and to schedule settlement conferences between the parties. Discussions with the mediator began in July 1992, however, GSU cannot predict what effect, if any, such discussions will have on the timing or outcome of the case. A trial without a jury is set for April 12,1994, on the portion of the suit by Cajun to rescind the Operating Agreement. Two member cooperatives of Cajun have brought an independent action to declare the River Bena Operating Agreement void, based upon failure to get prior LPSC approval alleged to be necessary. GSU believes the suits are without merit and is contesting them vigorously. No assurance can be given as to the outcome of this litigation. If GSU were ultimately unsuccessful in this litigation and were required to make substantial payments, GSU would probably be unable to make such payments and would probably have to seek relief from its creditors under the Bankruptcy Code. See Note 11 for the accounting treatment of preacquisition contingencies, including a charge resulting from an adverse resolution in the Cajun - River Bend litigation, ENTERGY CORPORATION AND SUBSIDIARIES i NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) In July 1992, Cajun notified GSU that it would fund a limited amount of costs related to the fourth
- refueling outage at River Bend, completed in September 1992. Cajun has also not funded its share of the costs associated with certain additional repairs and improvements at River Bend completed during the refueling outage.
GSU has paid the costs associated with such repairs and improvements without waising any rights agamst Cajun. GSU believes that Cajun is obligated to pay its share of such costs under the terms of the applicable contract. Cajun has filed a suit seeking a declaration that it does not owe such funds and scelang injunctive relief agamst GSU. GSU is contestmg such suit and is reviewing its available legal remedies. In September 1992, GSU received a letter from Cajun alleging that the operstmg and maintenance costs for River Bend are "far in excess of industry averages" and that "it would be imprudent for Cajun to fund these excessive costs." Cajun further stated that until it is satisfied it would fund a maxunum of $700,000 per week under protest for the remamder of 1992. In a December 1992 letter, Cajun stated that it would also withhold costs associated with certain additional repairs, of which the majority will be incurred during the next refueling outage, , currently scheduled for April 1994. GSU believes that Cajun's allegations are without merit and is considering its legal and other remedies available with respect to the underpayments by Cajun. The total resulting from Cajun's failure to fund repair projects, Cajun's fundmg limitation on the fourth refueling outage, and the weekly fundmg limitation by Cajun was $33.3 million as of December 31,1993, compared with a $28.4 million unfunded balance as of December 31,1992. These amounts are reflected in long-term receivables. During 1994, and for the next several years, it is ~ ped hat t Cajun's share of River Bend-related costs will be in the range of $60 million to $70 million per year. Cajun's weak financial condition could have a matenal i adverse effect on GSU, includmg a possible NRC action with respect to the operation of River Bend and a need to bear additional costs associated with the co-owned facilities. If GSU were required to fund Cajun's share of costs, , there can be no assurance that such payments could be recovered. Cajun's weak financial condition could also affect the ultimate collectibility of amounts owed to GSU. Caiun - Transmission Service ! i GSU and Cajun are parties to FERC proceedmgs related to transmission service charge disputes. In . April 1992, FERC issued a final order and in May 1992 GSU and Cajun filed motions for rehearmas which are i pending consideration by FERC. In June 1992, GSU filed a petition for review in the United States Coun of Appeals regarding certain of the issues decided by FERC. In August 1993, the United States Court of Appeals ! rendered an opinion reversing the FERC order regarding the ponion of such disputes relating to the calculations of certain credits and equalization charges under GSU's service schedules with Cajun. 'Ihe opinion re== dad the issues to FERC for further proceedmgs consistent with its opinion. In January 1994, FERC denied GSU's request to collect a surcharge while FERC considers the court's remand GSU interprets the FERC order and the court of appeals' decision to mean that Cajun would owe GSU approximately $85 million as of December 31,1993. GSU further estunates that if it prevads in its May 1992 motion for rehearmg, Cajun would owe GSU approximately SI18 million as of Dw.h 31,1993. If Cajun were to prevail in its May 1992 motion for reheanng to FERC, and if GSU were not to prevad in its May 1992 motion for reheanng to FERC, and if FERC does not implement the coun's remand as GSU conte wis is required, GSU estimates it would owe Cajun approximately $76 million as of December 31, 1993. The above amounts are exclusive of a $7.3 million payment by Cajun on December 31,1990, which the parties agreed to apply to the disputed transmission service charges. GSU and Cajun further agreed that their positions at FERC would remain unaffected by the S7.3 million. Pending FERC's ruling on the May 1992 motions for reheanng, GSU has continued ! to bill Cajun utilizing the historical billing methodology and has booked underpaid transmission charges, including interest, in the amount of $140.8 million an of December 31, 1993. This amount is reflected in long-term receivables and in other deferred credits, with no effect on net income. l
ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) i 1 l Caoital Reauirements and Financing , i Construction expenditures (excluding nuclear fuel) for the years 1994,1995, and 1996 are estimated to total 5586 million, $560 million, and $550 million, respectively. The System will also require $1,362 million during the period 1994-1996 to meet long-term debt and preferred stock maturities and cash sinking fund requirements. The System plans to meet the above requirements primarily with internally generated funds and ca on hand, supplemented by the issuance of debt and preferred stock. Certain System companies may also continue with the acquisition or refinancing of all or a portion of certain outstanding series of preferred stock and long-tenn debt. See Note 12 for information on additional capital requirements related to a February 1994 ice storm. Canital Funds and Availability Agreements l j Entergy Corporation has agreed to arrange for or supply to System Energy sufficient amounts of capital to (1) maintain System Energy's equity capital at not less than 35% of System Energy's total capitahzation (excluding short term debt), and (2) continue commercial operation of Grand Gulf I and enable System Energy to pay its borrowings. In addition, under supplements to the Capital Funds Agreement assigning System Energy's rights as security for specific debt of System Energy, Entergy Corporation has agreed to make cash capital contributions to enable System Energy to make payments on such debt when due. System Energy has entered into various agreements with AP&L, LP&L, MP&L, and NOPSI, whereby AP&L, LP&L, MP&L, and NOPSI are obligated to purchase their respective entitlements of capacity and energy from System Energy's 90% ownership and leasehold interest in Grand Gulf 1, and to make payments that, together with other available funds, are adequate to cover System Energy's operatmg expenses System Energy would have l to secure funds from other sources, including Entergy Corporation's obligations under the Capital Funds Agreement, to cover any shortfalls from payments received from AP&L, LP&L, MP&L, and NOPSI under these j agreements. 1 Lone-Term Contracts Ac System has several long-term contracts to purchase natural gas and low-sulfur coal for use at its generating units. LP&L has a long-term agreement through the year 2031 to purchase energy generated by a hydroelectric facility. If the maxunum percentage (94%) of the energy is made available to LP&L, current j production projections would require estunated payments of approxunately 547 million per year through 1996, i
$54 million in 1997, and a total of $3.5 billion for the years 1998 through 2031. LP&L recovers the cost of purchased energy through its fuel adjustment clause.
In 1988, GSU entered into a joint venture with a pnmary term of 20 years with Conoco, Inc,, Citgo Petroleum Corporation, and Vista Chemical Company (Industrial Participants) whereby GSU's Nelson Units I and 2 were sold to a partnership (NISCO) consisting of the Industrial Participants and GSU. The Industrial Participants are supplying the fuel for the units, while GSU operates the units at the discretion of the Industrial Participants and purchases the electricity produced by the units. GSU is continuing to sell electricity to the Industrial Participants. For the years ended December 31,1993,1992, and 1991, the purchases of electricity from the joint venture totaled $62.6 million, $37.8 million, and 561.3 million, respectively. Nucicar Insurance , He Price-Anderson Act limits public liability for a single nuclear incident to approxunately $9.4 billion as of December 31,1993. The System has protection for this liability through a combination of private insurance (currently $200 million) and an industry assessment program. Under the assessment program, the maxunum l
ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) amount the System would be required to pay for each nuclear incident would be $79.28 million per reactor, payable at a rate of $10 million per licensed reactor per incident per year. As a co-licensee of Grand Gulf I with System Energy, South Mississippi Electric Power Association (SMEPA) would share 10% of this obligation. With respect to River Bend, any assessments pertammg to this program are subject to the 70/30% ownership interest between GSU and Cajun. 'Ihe System has five licensed reactors. In addition, the System participates in a private insurance program which provides coverage for worker tort claims filed for bodily injury caused by radiation exposure. "Ihe program provides for a maxunum assessment of approxunately $15.5 million for the System's five nuclear units, in , the event losses exceed accumulated reserve funds. AP&L, GSU, LP&L, and System Energy are also members of certain insurance programs that provide coverage for property damage, includmg ?--- hadon and premature '++ 2:=ionmg expense, to members' nuclear generatmg plants. As of December 31,1993, AP&L, GSU, LP&L, and System Energy each were insured agamst such losses up to $2.7 billion, with $250 million of this amount designated to cover any shortfall in the NRC required bmmissiomng trust fundmg In addition, AP&L, GSU, LP&L, MP&L, and NOPSI are members of an insurance program that covers certain replacement power and business interruption costs mcurred due to prolonged nuclear unit outages. Under the property damage and replacement power / business interruption insurance . programs, these System companies could be subject to assessments iflosses exceed the accumulated funds available to the insurers. As of December 31,1993, the maxunum amounts of such possible assessments were: AP&L -
$28.14 million; GSU - $15.9 million; LP&L - $24.34 million; MP&L - 50.63 million; NOPSI- 50.34 nulhon, and System Energy - $21.89 million. Under its aywt with System Energy, SMEPA would share.in System Energy's obligation. Cajun shares approximately S4.02 million of GSU's obligation
'Ihe amount of property insurance carried by the System exceeds the NRC's minimum requirement for nuclear power plant licensees of $1.06 billion per site. NRC regulations provide that the proceeds of this insurance must be used, first, to place and maintain the reactor in a safe and stable condition and, second, to complete decontammation operations. Only after proceeds are dedicated for such use and regulatory approval is secured, would any remammg proceeds be made available for the benefit of plant owners or their creditors.
Soent Nuclear Fuel and Decc '=='ea:..r Costs AP&L, GSU, LP&L, and System Energy provide for estunated future disposal costs for spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. 'Ihe affected System companies entered into contracts with the Department of Energy (DOE), whereby the DOE will fumish disposal service at a cost of one mill per net KWH generated and sold after April 7,1983, plus a one-time fee for generation prior to that date. AP&L, the only System company that generated electricity with nuclear fuel prior to that date, elected to pay the one-tune fee, plus accrued interest, no earlier than 1998, and has recorded a liability as of December 31,1993, of approximately
$101.0 million. 'Ihe fees payable to the DOE may be adjusted in the future to assure full recovery. 'Ihe System considers all costs incurred or to be incurred, except accrued interest, for the disposal of spent nuclear fuel to be proper components of nuclear fuel expense, and provisions to recover such costs have been or will be made in applications to regulatory authorities.
Due to delays of the DOE repository program for the acceptance of spent nuclear fuel, it is uncertain when shipments of spent fuel from the System's nuclear units will commence In the meantime, the affected companies are responsible for spent fuel storage. Current on-site spent fuel storage capacity at ANO, River Bend, Waterford 3, and Grand Gulf 1 is estunated to be sufficient until 1995,2003,2000, and 2004, respectively. "Ihereafter, the affected companies will provide additional storage. 'Ihe initial cost of providing the additional on-site spent fuel storage capability required at ANO, River Bend, Waterford 3, and Grand Gulf 1 is approximately $5 million to
$10 million per unit. In addition, approximately $3 million to SS million per unit will be required every two to three years subsequent to 1995 for ANO and every four to five years subsequent to 2003,2000, and 2004 for River ,
i ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) Bend, Waterford 3, and Grand Gulf 1, respectively, until the DOE's repository begms accepting such units' spent i fuel. Decommissioning costs for ANO, River Bend, Waterford 3, and Grand Gulf I were estunated to be approumately $606.8 million (based on a 1992 update to the original cost study), $141.0 million (based on a 1985 ast study), $203,0 million (based on a 1988 update to the original cost study), and $248.7 million (based on a 1989 cost study), respectively. AP&L and GSU are authorized to recover through rates amounts that, when added to estimated investment income, should be sufficient to meet the above estimated decommissioning costs for ANO and k ver Bend. However, GSU did a 1991 update to the cost study which indicated decomnussioning costs for River Bend may be approxunately $279.8 million. He results of the 1991 update have not yet been added into GSU's rates and used as a basis for fundmg During the first quaster of 1994, AP&L expects to prepare and file with the APSC an interim update of the ANO cost study, which will likely reflect significant increases in costs of low-level radioactive waste disposal. %e LPSC authorized LP&L to recover $4.0 million annually through 1993, based on the 1988 study update. LPAL will begin fundmg $4.8 million in 1994 in anticipation of a 1994 study update and a related LPSC review and determmation of appropriate fundmg levels. System Energy is currently recovering in rates amounts sufficient to fund $198.0 million (in 1989 dollars) ofits decommissioning costs, and an updated cost study is scheduled to be completed by mid-1994. AP&L, GSU, LP&L, and System Energy regularly review and update estimated decomnussioning costs, and applications will be made to the appropriate regulatory authorities to reflect in rates any future change in projected decommissioning costs. The amounts recovered in rates are deposited in external trust funds which have a market value of $193.1 million and $138.5 million (excluding GSU in 1992) as of December 31,1993 and 1992, respectively. The accumulated knmmissioning liability has been recorded in accumulated depreciation for AP&L, GSU, and LP&L, and in other deferred credits for System Energy, in the amounts of $119.2 million, $18.1 million, $22.1 million, and $24 8 million, respectively, as of December 31, 1993. Decommissioning expense amountmg to $19.9 million was recorded in 1993. He actual decommissioning costs may vary from the above ~ times because of regulatory requirements, changes in tr.chnology, and increased costs of labor, materials, and equipment, and management believes that actual decommissioning costs are likely to be higher than the amounts presented above. The Energy Act has a provision that assesses domestic nuclear utilities with fees for the dennt=ineion and decomnussioning of the DOE's past uranium enrichment operations. He decontamination and dxnmmissioning assessments will be used to set up a fund into which contributions from utilities and the federal govemment will be placed. AP&L's, GSU's, LP&L's, and System Energy's annual assessments, which will be adjusted annually for inflation, are approxunately $3.3 million,50.6 million, $1.2 million, and $1.3 million (in 1993 dollars), respectively, for approumately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortized The cumulative liability of $87.4 million as of December 31,1993, is recorded in other current liabilities and other noncurrent liabilities and is offset in the consolidated financial statements by a regulatory asset, recorded as a deferred debit.
ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) NOTE 9. LEASES General As of December 31,1993, the System had capital leases and noncancelable operating leases (excluding , nuclear fuel leases and the sale and leaseback transactions discussed below) with muumum lease payments as follows: Capital Operating Year Leases Leases (In Thousands) 1994 S 33,780 $ 43,337 1995 33,880 42,527 1996 29,490 39,235 1997 24,654 20,820 . 1998 24,654 22,532 Years thereafter 160.903 180.651 Minimum lease payments 307,361 $349.102 Less: Amount representing interest 121.708 Present value of net nummum lease payments $185.653 Rental expense for capital and operat' 'ses (excluding nuclear fuel leases and the sale and leaseback transactions) amounted to approximately 562.7 ,on, $75.5 million, and $73.8 million in 1993,1992, and 1991, respectively. Nuclear Fuel Leases AP&L, GSU, LP&L, and System Energy have arrangements to lease nuclear fuel in an aggregate amount up to $455 million as of December 31,1993. The lessors finance their acquisitions of nuclear fuel through credit agreements and the issuance of notes. If a lessor cannot anange financing upon maturity of its borrowings, the lessee must purchase nuclear fuel in an amount sufficient to enable the lessor to retire such borrowings. Lease payments are based on nuclear fuel use. Nuclear fuel lease expense for AP&L, LP&L, and System l Energy of $145.8 million, $158.4 million, and $185.6 million (including interest of $20.5 million, $25.6 million, j and S32.7 million) was charged to operations in 1993,1992, and 1991, respectively. Sale and Lessebsek Transsetions In 1988 and 1989, System Energy and LP&L, respectively, sold and leased back portions of their l ownership interests in Grand Gulf I and Waterford 3, for 26- and 28-year lease terms, respectively. Both ! companies have options to termmate the leases, to repurchase the sold interests, or to renew the leases at the end of i their terms. l Under System Energy's sale and leaseback arrangements, letters of credit are required to be maintained to secure certain amounts payable, for the benefit of equity investors, by System Energy under the leases. He letters of credit currently maintained are effective until January 1997. It is expected that the letters of credit will either be renewed, extended, or replaced prior to expiration. On January 11, 1994, System Energy nre nw~i the debt portion of the sale and leaseback arrangements. He new secured lease obligation bonds of $356 million, 7.43% ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) series due 2011 and $79 million, 8.2% series due 2014 will be indirectly securext by liens on, and a security interest in, certain ownership interests and the respective leases relating to Grand Gulf 1. If LP&L does not exercise its option to repurchase the lease interests in Waterford 3 in September 1994, LP&L will be required to provide collateral to secure the equity portion of certain ofits obligations under the lease. His collateral would be either a letter of credit or a new series of first mortgage bonds issued by LP&L. As of December 31,1993, System Energy and LP&L had future muumum lease payments (reflecting implicit rates of 7.02% after the above refinancing and 8.76%, respectively) as follows: System Enerry LP&L (In Thousands) 1994 $ 17,423* $ 32,568 42,464 32,569 1995 42,753 35,165 1996 42,753 39,805 1997 42,753 41,447 1998 Years thereafter 845.573 726.744 Total 51.033.719 $ 908.298
- An additional $24 million payment was made in January 1994 prior to the rdnancing of the debt portion of the sale / leaseback arrangements.
NOTE 10. POSTRETIREMENT BENEFITS Pension Plans
%c System companies have various postretirement benefit plans covermg substantially all of their employees. He pension plans are noncontributory and provide pension benefits that are based on emplo>tes' credited service and compensation during the final years before retirement. Entergy Corporation and its subsidiaries fund pension costs in accordance with contribution guidelines established by the Employee Retirement income Security Act of 1974, as amend A. and the Intemal Revenue Code of 1986, as amenAaA Re assets of the !
plans include common and preferred stocks, fixed income securities, interest in a money martet fund, and insurance contracts.
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l ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) Total 1993,1992, and 1991 pension cost of Entergy Corporation and its subsidianes, including amounts capitalized, included the followmg components: For the Years Ended Ds;.T.',er 31. 1993 1992 1991' , (In Thousands) Service cost - benefits earned during the period 521,760 $ 18,784 5 16,393 - 53,371 50,225 44,367 :
' Interest cost on projected benefit obligation Actual return on plan assets (81,708) (43,772) '(120,705) 27,261 (8,243)- 70,760 [
Net amortization and deferral Other
- - 2.888 l Net pension cost flgd)3 3,M21 $ 13.703 The funded status of Entergy's various pension plans as of D ds 31,1993 and 1992 (excladmg GSU f in 1992), was: .
1993 1992 l (In Thousands) . ; Actuarial present value of accumulated pension plan obligation: Vested S 821,292 5552,437 Nonvested 17.867 2.999 , Accumulated benefit obligation S 839.159 }J,14))4 l Plan assets at fair value 51,059,715 5647,120 , Projected benefit obligation 1.041.104 666.626 ; Plan assets in excess of(less than) projected benefit obligation 18,611 (19,506) Unrecogmzed prior service cost 20,288 21,723 -! Unr i=A transition asset (61,561) (68,914) l Unramani=d net loss (gain) 32.634 (13.473) ; Accrued pension asset (liability) S 9.972 ' S (80.170) ; The significant actuanal assumptions used in computing the information above for 1993,1992, and 1991 (only 1993 with respect to GSU's plan), were as follows: weighted average discount rate,7.5% for 1993 and 8.25% for 1992 and 1991 (7.5% for GSU); weighted average rate ofincrease in future 9 <-i-- =F= levels,5.6% (5.0% for GSU); and ~p-M long-term rate of return on plan assets, 8.5% (8.5% for GSU).' Transition assets of the System are being amortized over the greater of the renuumng service period of active participants or 15 years.- Other Post,nire.T.;;; E;;J.3 The System companies also provide certam health care and life insurance benefits for retired employees. Substantially all employees may become eligible for these benefits if they reach retirement age while still working for the System companies. The cost of providing these benefits, recorded on a cash basis, to retirees in 1992 was approximately $13 million. Prior to 1992, the cost of providing these benefits for retirees was not separable from the cost of providing benefits for active employees. Based on the ratio of the number of retired employees to the total number of active and retired employees in 1991, the cost of providing these benefits, recorded on a cash basis, for retirees was approximately $11.8 million.
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ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) Effective January 1,1993, Entergy adopted SFAS 106. The new standard requires a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. The System operating companies continue to fund these benents on a pay-as-you-go basis. At January 1,1993, the actuanally detemiined accumulated postretirement benefit obligation (APBO) camed by retirees and active employces was estimated to be approximately $241.4 million and $128.0 million far Entergy and for GSU, respectively. Such obl%ations are being amonized over a 20-year period beginning b 1993.
"Ihe System operating companies have sought approval, in their respective regulatory jurisdictions, to implement the appropriate accounting requaements related to SFAS 106 for r*maWg purposes. AP&L has received an order permitting deferral, as a regUatory asset, of these costs. MP&L is expensing its SFAS 106 costs, which will be reflected in rates pursuant to an ocar frem the MPSC in connection with MP&L's formulary incentive rate plan (see Note 2). The LPSC ordered GSU and LP&L to use the pay-as-you-go method for ratemakmg purposes for postretirement benefits other than pensions but the LPSC retams the flexibility to examme individual companies' accounting for postretirement benefits to determine if special exceptions to this order are warranted. NOPSI is expensing its SFAS 106 costs. Pursuant to resolutions adopted in November 1993 by the Council related to the Merger, NOPSl's SFAS 106 expenses through October 31,1996, will be allowed by the Council for purposes of evaluating the appropriateness of NOPSI's rates. Pursuant to a ruling by the PUCT applicable to all Texas utilities, including GSU, amounts recorded in compliance with SFAS 106 and included in a rate filing test period, will be recoverable in rates (at the time of the next general rate case), and postretirement benefits amounts allowed in rates must then be funded by the utility. The System's net income in 1993 (excluding GSU) was decreased by approximately $9 million as a result of adopting SFAS 106.
Total 1993 postretirement benefit cost of Entergy Corporation and its subsidiaries (excluding GSU), including amounts capitalized and deferred, included the following components (in thousands): Senice cost - benefits earned during the period S 7,751 Interest cost on APBO 19,394 Return on plan assets (71) Amortization of transition obligation 12.071 Net periodic postretirement benefit cost S 39.145 The funded status of Entergy's postretirement plans as of December 31,1993, was (in thousands): Accumulated postretirement benefit obligation: Retirees S 221,562 Other fully eligible participants 68,283 Other active participants 95.854 385,699 Plan assets at fair value 354 Plan assets less than APBO (385,345) Unrecogmzed transition obligation 229,346 Unrecogmzed netloss 28.529 Accrued postretirement benefit liability $(127.470) The assumed health care cost trend rate used in measuring the APBO of the System companies, excluding GSU, was 9.9% for 1994 (10% for GSU), gradually decreasing each successive year until it reaches 5.6% in 2020 (5% for GSU in 2002). A one percentage-point increase in the assumed health care cost trend raic for each year would have increased the APBO of the System companies, excluding GSU, as of December 31,1993, by 8.9%, (13.6% for GSU) and the sum of the senice cost and interest cost by approximately 11.4% (22.7% for GSU). The
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I ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) i assumed discount rate and rate ofincrease in future compensation used in determinmg the APBO were 7.5% (7.5% , for GSU) and 5.5% (5% for GSU), respectively. l NOTE 11. ENTERGY CORPORATION-GSU MERGER On December 31,1993, GSU became a wholly-owned subsidiary of Entergy Corporation and continues to operate as a public. utility under the regulation of the PUCT and the LPSC. As consideration to GSU's I shareholders, Entergy Corporation paid $250 million and issued 56,667,726 shares ofits common stock at a price of $35.8417 per share. In addition, $33.5 nullion of transaction costs were capit=hmi in manartinn with the Merger. The Merger was accounted for under the purchase method of =~=eaa Vanous parties have requested reheanngs and/or are appeahng the approval orders or plans of the SEC, NRC, LPSC, and FERC. ,
+
The Consolidated Balance Sheet of Entergy Corporation as of December 31,1993, includes the accounts of GSU and, therefore, is not directly' comparable to the Consolidated Balance Sheet pr=ntad as' of l December 31,1992. Entergy Corporation recorded an acquisition adjustment in utility plant in the amount of
$380 million representing the excess of the purchase price over the net assets acquired of GSU. The acquisition adjustment will be amoitued on a straight-line basis over a 31-year penod, which approxarnates the remaming average book life of the plant being acquired.
The allocation of the purchase price has been based on prehmmary estimates which may be revised at a later date. The possibility of an adverse result in the litigation relating to Cajun (see Note 8) and the possibility of a write-off relating to Texas River Bend ream =1dag issues (see Note 2) represent preacquisition coutmgencies There may be other contingencies associated with GSU which could also constitute preacquisition e a i=ies but which have not yet been specifically identified as such by Entergy Corporation. During the allocation period (which will not exceed one year after consummation of the transaction), Entergy Corporation will complete its analyses with respect to these contingencies. Upon completion, should Entergy Corporation no longer believe GSU has a reasonable possibility of attauung a favorable ruling in such preacquisition contingencies, any resulting write-offs and/or losses would cause the reduction of the affected noncurrent assets and an inemase of an equal amount in the j acquisition adjustment in Entergy Corporation's consolidated fmancial statements, in andic.cc with the purchase method of accounting for business combinations. In accordance with the purchase method of accounting, the 12-month results of operations for Entergy-Corporation reported in its Statements of Consolidated Income, Cash Flows, and Retained Earmngs do not reflect GSU's results of operations for any period as a result of the December 31,1993, closing date of the Merger. The ; pro forma combined revenues, net income, earnings per common share before extraordmary items and cumulative effect of accounting changes, and earnings per common share of Entergy Corporation presented below give effect to the Merger as ifit had occurred at January 1,1992. This pro forma information is not necessarily indicative of the [ results of operation that would have occurred had the Merger been consum=*~i for the period for which it is being given effect, nor is it necessarily indicative of future operating results. j i l i l l
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i ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) l Year Ended December 31. 1993 1992 (In Thousands, Except Per Share Amounts) Revenues ,
$6,286,999 $5,850,973 Net income $ 595,211 5 521,783 Earmngs per average conunon share before extraordmary items and cumulative effect of accounting changes 5 2.10 $ 2.26 Eanungs per average common share $ 2.57 $ 2.24 NOTE 12. SUBSEQUENT EVENT (UNAUDITED)
In early February 1994, an ice storm left more than 221,000 Entergy customers without electric power across the System's four-state service area. 'Ihe storm was the most severe natural disaster ever to affect the System, causing damage to transmission and distribution lines, equipment, poles, and facilities in certam areas, primarily in Mississippi. A substantial portion of the related costs, which are estunated to be $110 million to $140 million, are expected to be capitalized. The MPSC acknowledged that there is precedent in Mississippi for recovery of certam costs associated with storms and natural disasters and the restoration of service resulting from such events MP&L plans to immedatdy file for rate recovery of the costs related to the ice storm. Estunated construction expenditures (see Note 8) have not yet been updated to reflect the above amounts.
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ENTERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Concluded) NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED) The business of the System is subject to seasonal fluctuations with the peak period occurring during the third quarter. Consolidated operating resul:s for the four quarters of 1993 and 1992 were: Operating Operating Net Earnings Revenues Income Income ner Share (In Thousands, Except Per Share Amounts) 1993: S 926,412 $192,743 SIS 1,154 50.86 First Quarter (1)
$1,070,102 $260,574 5130,860 50.75 Second Quarter
$1,410,951 $359,938 S233,430 $1.34 Third Quarter
$1,077,872 5180,086 S 36,486 $0.21 Fourth Quarter 1992:
S 916,467 $211,679 $ 95,277 50.54 First Quarter (2) S 958,121 $220,141 S 82,102 $0.46 Second Quarter
$1,237,894 $340,361 $204,578 S1.16 Third Quarter
$1,004,017 $186,405 5 55,680 50.32 Fourth Quarter (1) 'Ihe first quarter of 1993 reflects a nonrecurring increase in net income of $93.8 million, net of taxes of
$57.2 million, and a $0.54 increase in earnmgs per share, due to the recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1). Beginning with the second quarter, the remaining quarters are not generally comparable to prior year quarters because of the ongoing effects of the accounting change.
(2) The first quarter of 1992 reflects a nonrecurring increase in net income of $19.6 million, net of tax, and a 50.11 increase in cammgs per share, due to the AP&L sale of retail properties in Missouri.
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I ENTERGY CORPORATION AND SUBSIDIARIES SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1993 1992 1991 1990 1989 (In Thousands, Except Per Share Amounts) Operating revenues S 4,485,337 S 4,116,499 5 4,051,429 5 3,982,062 $ 3,724,004 Income (loss) before cumulative effect of a change in accounting principle S 458,089 $ 437,637 5 482,032 S 478,318 $ (472,585) Earmngs (loss) per share before cumulative effect of a change in accounting principle 5 2.62 S 2.48 $ 2.64 $ 2.44 5 (2.31) Dividends declared per share $ 1.65 $ 1.45 $ 1.25 S 1.05 $ 0.90 Book value per share, year-end (2) $ 28.27 5 24.35 S 23.46 $ 22.18 S 20.62 Total assets (2) $ 22,876,697 $ 14,239,537 5 14,383,102 5 14,831,394 $ 14,715,241 Long-term obligations (l)(2) S 8,177,882 5 5,630,505 5 5,801,364 5 6,395,951 S 6,711,509 (1) Includes long-term debt (excluding currently maturing debt), preferred and preference stock with sinkmg fund, and noncurrent capital lease obligations. (2) 1993 amounts include the effects of the Merger in accordance with the purchase method of accounting for combinations (see Note 11). See Notes 1,3, and 10 for the effect of the accounting changes in 1993. 1993 1992 1991 1990 1989 (Dollars in Thousands) Electric Operating Revenues: Residential $1,596,480 $1,440,360 $1,463,281 $1,449,768 $1,331,154 Commercial 1,072,583 1,007,420 996,619 988,409 930,345 Industrial 1,199,172 1,097,023 1,068,802 1,051,796 1,021,456 Governmental 136.649 127.753 128.762 124.597 121.912 Total retail 4,004,884 3,672,556 3,657,464 3,614,570 3,404,867 Sales for resale 293,894 252,288 220,347 212,504 177,014 Other 95.568 118.711 96.667 67.045 51.756 Total $4.394.346 $4.043.555 $3.974.478 $3.894.119 $3.633.637 Billed Electric Energy Sales (Millions ofIGVH): Residential 18,946 17,549 18,329 18,174 17,245 Commercial 13,420 12,928 13,164 12,977 12,533 Industrial 24,889 23,610 23,466 22,795 22,396 Governmental 1.887 1.8J9 1.903 1.831 1.833 Total retail 59,142 55,926 56,862 55,777 54,007 Sales for resale 8.291 7.979 7.346 6.292 4.857 Total 67.433 63.905 64.208 62.069 58.864
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'I l Arkansas Power & Light Company /1993 Financial Statements l 8 s -
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ARKANSAS POWER & LIGHT COMPANY DEFINITIONS Certain abbreviations or acronyms used in AP&L's Financial Statements, Notes to Financial Statements, and Management's Financial Discussion and Analysis are defmed below-Abbreviation or Acronym Term AFUDC Allowance for Funds Used During Construction ANO Arkansas Nuclear One Steam Electric Generating Station ANO1 Unit No. I of ANO ANO 2 Unit No. 2 of ANO AP&L Arkansas Power & Light Company APSC Arkansas Public Service Commission DOE United States Department of Energy Entergy or System Entergy Corporation and its various direct and indirect subsidiaries Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy Corporation that has operating responsibility for Grand Gulf 1, Waterford 3, ANO, and River Bend Entergy Power Entergy Power, Inc., a subsidiary of Entergy Corporation that markets capacity and energy for resale from certain generatmg facilities to other parties, principally non-affiliates FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission Grand Gulf Station Grand Gulf Steam Electric Generating Station Grand Gulf 1 Unit No. I of the Grand Gulf Station Grand Gulf 2 Unit No. 2 of the Grand Gulf Station GSU Gulf States Utilities Company (including wholly owned subsidiaries - Varibus Corporation, GSG&T, Inc., Prudential Oil and Gas, Inc., and Southern Gulf Railway Company) Independence Station Independence Steam Electric Generating Station Independence 2 Unit No. 2 of the Independence Station
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ARKANSAS POWER & LIGHT COMPANY DEFINITIONS -(Concluded) Abbreviation or Acronym Term KW11 Kilowatt-Hour (s) LP&L Louisiana Power & Light Company Merger he combination transaction, consummated on December 31,1993, by which GSU became a subsidiary of Entergy Corporation and Entergy Corporation became a Delaware Corporation Money Pool Entergy Money Pool, which allows certam System companies to borrow from, or lend to, certam other System companies MP&L Mississippi Power & Light Company NOPSI New Orleans Public Service Inc. NRC Nuclear Regulatory Comnussion Omnibus Budget Reconciliation Act of 1993 ; OBRA i Revised Settlement Agreement Arkansas Settlement Aym.cs, as modified by the APSC order issued October 6,1988, to bring the Grand Gulf 1-related phase-in plan into compliance with the requirements of SFAS No. 92, " Regulated Enterprises - Accounting for Phase-in Plans" Rrtchie 2 Unit No. 2 of the Ritchie Steam Electric Generating Station l SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the FASB SFAS 106 SFAS No.106, " Employers' Accounting for Postretirement Benefits Other Han Pensions" SFAS 109 SFAS No.109, " Accounting for Income Taxes" System or Entergy Entergy Corporation and its various direct and indirect subsidiaries , Sysan Energy System Energy Resources,Inc. System Fuels System Fuels,Inc. System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively Union Electric Union Electric Company of St. Iouis, Missouri White Bluff Station White Bluff Steam Electric Generating Station
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I ARKANSAS POWER & LIGHT COMPANY REPORT OF MANAGEMENT The management of Arkansas Power & Light Company has prepared and is responsible for the financial statements and related fmancial information included herein. The financial statements are based on generally accepted accounting principles. Financial information included elsewhere in this report is consistent with the fmancial statements. l To meet its responsibilities with respect to financial information, management maintains and enforces a system ofinternal accounting controls that is designed to provide reasonable assurance, on a cost effective basis, as to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. This system includes communication through written policies and procedure , an employee Code of Conduct, and an organizational structure that provides for appropriate division of responsibility and the trammg of personnel. This system is also tested by a comprehensive internal audit pregram. The independent public accountants provide an objective assessment of the degree to which management meets its responsibility for fairness of financial reporting. They regularly evaluate the system of intemal accounting controls and perform such tests and other procedures as they deem nacanary to reach and express an opinion on the fairness of the financial statements. Management believes that these policies and procedures provide reasonable assurance that its operations are carried out with a high standard of business conduct. EDWIN LUPBERGER GERALD D. MCINVALE Chairman and Chnf Executive Officer Senior Vice President and Chief Financial Officer 8 i 4
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i ARKANSAS POWER & LIGIIT COMPANY AUDIT COMMITTEE CHAIRMAN'S LETTER ne Arkansas Power & Light Company Audit Committee of the Board of Directors is comprised of four directors, who are not officers of AP&L: Kaneaster Hodges, Jr. (Chairman), Richard P. Herget, Jr., Dr. Raymond P. Miller, Sr., and Gus B. Walton, Jr. He committee held four meetmgs during 1993. He Audit Committee oversees AP&L's financial reporting process on behalf of the Board of Directors and provides reasonable assurance to the Board that sufficient operatmg, accounting, and financial controls are in existence and are adequately reviewed by programs ofinternal and external audits. The Audit Committee discussed with Entergy's internal auditors and the independent public accountants (Deloitte & Touche) the overall scope and speciSc plans for their respective audits, as well as AP&L's financial statements and the adequacy of AP&L's internal controls. The commrttee met, together and separately, with Entergy's internal auditors and independent public accountants, without management present, to discuss the results of their audits, their evaluation of AP&L's internal controls, and the overall quality of AP&L's financial reporting. He meetmgs also were designed to facilitate and encourage any private communication between the committee and the internal auditors or independent public accountants. KANEASTER HODGES, JR. Chairman, Audit Committee l l l l l 1
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INDEPENDENT AUDITORS' REPORT 4 To the Shareholders and the Board of Directors of Arkansas Power & Light Company We have audited the accompanying balance sheets of Arkansas Power & Light Company (AP&L) as of December 31,1993 and 1992, and the related statements ofincome, retamed earmngs, and cash flows for each of the three years in the period ended December 31,1993. Rese financial statements are the responsibility of AP&L's , management Our responsibility is to express an opinion on these financial statements based on our audits. , We conducted our audits in accordance with generally accW auditing standards Those standards require that we plan and perform the audit to obtain re====hle assurance about whether the financial statements are free of material misstatement. An audit includes e4 *-5, on a test basis, evidence supporting the amounts and disclosures in the financial statements An audit also includes assessing the me=> *ia: principles used and , significant estunates made by maamgamard, as well as evaluatmg the overall financial statement presentation We l t believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all matenal respects, the financial position of i t AP&L at December 31,1993 and 1992, and the results of its operations and its cash flows for each of the three ! years in the period ended December 31,1993 in confonnity with generally accepted accounting principles. t As discussed in Note I to the financial statements, AP&L changed its method of secei *ing for revenues in f 1993 and, as discussed in Notes 3 and 10 to the financial statements, in 1993 AP&L changed its methods of l accounting for income taxes and powdum.est benefits other than pensions, respectively. j i i DELOITTE & TOUCHE New Orleans, Louisiana ; February 11,1994 i 9-l l I i 5 l 3 I i
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ARKANSAS POWER & LIGHT COMPANY BALANCE SHEETS ASSETS December 31, 1993 1992 (In Thousands) Utility Plant (Notes 1 and 2):
$4,098,355 $4,002,350 Electric 62,139 67,840 Property under capital leases (Note 9)
Construction work in progress 197,005 174,909 93.606 102,435 Nuclear fuel under capital lease (Note 9) 4,451,105 4,347,534 Total less - accumulated depreciation and amortization 1,604,318 1,512,919 2.846,787 2,834,615 - Utility plant - net Other Property and Investments lavestment in = Mary companies - at equity (Note 8) 11,232 11,232 Decommissioning trust fund (Note 8) 108,192 91,075 Other - at cost (less accumulated depreciation) 4,257 3,498 123,681 105,805 Total Current Assets 1,825 - Cash Accounts remivable: Customer (less allowance for doubtful accounts of 65,641 75,087
$2.1 million in 1993 and $1.6 million in 1992)
Aeaw' companies (Note 11) 18,312 32,238 20,817 6,881 Otner 83,378 - Accrued unbilled revenues (Note 1) 51,920 52,093 Fuelinventory - at average cost 81,398 91,000 Materials and supplies - at average cost 92,592 69,536 Rate deferrals (Note 2) 9,115 8,395 Deferred exass capacity (Note 2) 28,303 35,918 Prepayments and other 453,301 371,148 Total Deferred Debits: 475,387 574,040 Rate defermis(Note 2) Deferred excess capacity (Note 2) 28,465 38,300 SFAS 109 regulatory asset - net (Note 3) 234,015 - Unamortized loss on resquired debt 60,169 23,262 112,300 91,641 Other (Note 8) . 910,336 727,243 Total
$4,334,105 $4,038,811 TOTAL See Notes to Financial Statements.
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ARKANSAS POWER & LIGHT COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, 1993 1992 (la Thousands) Capitalization: Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 1993 and 1992 $470 $470 Paid-in capital 590,844 590,838 Retained earnings (Note 7) 448,811 420,691 Total common shareholder's equity 1,040,125 1,011,999 Preferred stock (Note 5): Without sinking fund 176,350 176,350 With sinking fund 70,027 85,527 Long-term debt (Note 6) 1,313,315 1,260,947 Total 2,599,817 2,534,823 Other Noncurrent Liabilities: Obligations under capital leases (Note 9) 94,861 107,114 59,750 86,020 Other (Note 8) Total 154,611 193,134 Current Liabilities: Currently maturing long-term debt (Note 6) 3,020 17,900 Notes payable: Associated companies (Note 4) 21,395 4,000 Other 667 667 Accounts payable: Associated companies (Note 11) 45,177 36,757 Other 93,611 81,423 Customer deposits 15,241 14,926 Taxes accrued 43,013 64,9 % Accumulated deferred incorne taxes (Note 3) 32,367 20,904 Interest accrued 31,410 31,209 Dividends declared 5,049 5,534 Nuclear refueling reserve 3,070 3,050 Co-owner advances (Note 1) 39,435 31,005 Deferred fuelcost(Note 1) 16,130 19,553 Obligations under capitalleases (Note 9) 60,883 63,162 Other 29,789 25,842 Total 440,257 420,928 Deferred Credits: Accumulated deferred income taxes (Note 3) 876,618 618,416 i Accumulated deferred investment tax credits (Note 3) 154,723 165,296 Other 108.079 106.214 Total ___ 1,139,420 889,926 Commitments and Contingencies (Notes 2, 8, and 9) TOTAL $4,334.105 $4,038,811 See Notes to Financial Statements.
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ARKANSAS POWER & LIGHT COMPANY STATEMENTS OF CASIf FLOWS For the Years Ended December 31, 1993 1992 1991 (In Thousands) Operating Actisities:
$205,297 $130,529 $143,451 Net income Noncash items included in net income:
Cumulative effect of a change in accounting principle (50,187) - - Change in rate deferrals / excess capacity - net (Note 2) 84,712 60,344 16,936 Depreciation and decommissioning 135,530 132,459 128,410 (6,%5) (820) 9,448 Deferred income taxes and investment tax credits Allowance for equity funds used during construction (3,627) (4,173) (4,508) 1,%3 (21,670) 7,786 Provision for estimated losses and reserves Gain on sale of property - net
- (19,612) -
Changes in working capital: 7,385 (22,281) 10,948 Receivables Fuelinventory 173 17,039 (37,142) Accounts payable 20,608 (5,393) (4,528) (21,983) (23,492) 2,514 Taxes accrued Interest accrued 201 (8,041) (154) Other working capital accounts 26,486 5,249 2,506 Decommissioning trust contributions (11,491) (13,255) (13,765) (41,826) (2,736) (284) Other Net cash flow provided by operating activities 346,276 224,147 , 261,618 investing Actisities: Construction expenditures (176,540) (179,320) (156,734) Proceeds received from sale of property (Note 2) - 67,985 - Allowance for equity funds used during construction 3,627 4,173 4,508 Nuclear fuel purchases (29,156) (34,238) (32,900) 29,156 34,238 33,058 Proceeds from sale / leaseback of nuclear fuel Net cash flow used in investing actisities (172,913) (107,162) (152,068) Financing Actisities: Proceeds from issuance of: First mortgage bonds 445,000 148,114 -
- 14,222 48,175 Preferred stock Other long-term debt 48,070 3,973 18,607 Retirement of; First mortgage bonds (441,141) (329,019) (35,598)
Other long-term debt (47,700) (1,225) (1,140) Redemption of preferred stock (15,500) (34,388) (14,000) Changes in short-term borrowings 17,395 4,000 - Dividends paid: Common stock (156,300) (75,000) (39,900) (21,362) (23,730) (22,071) Preferred stock Net cash flow used in financtng activities (171,538) (293,053) (45,927) Net increase (decrease) in cash and cash equivalents 1,825 (176,068) 63,623
- 176,068 112,445 Cash and cash equivalents at beginning of period
$1,825 - $176,068 l Cash and cash equivalents at end of period SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for: Interest - net of amount capitalized $103,826 $114,791 $124,220
$66,366 $60,987 $36,396 Income taxes Noncash imesting and financing actisities:
$48,513 $37,351 $36,619 Capitallease obligations incurred See Notes to Financial Statements.
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ARKANSAS POWER & LIGIIT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES Liquidity is important to AP&L due to the capital intensive nature of our business, which requires large investments in long-lived assets. However, large capital expenditures for the construction of new generating capacity are not currently planned AP&L requires significant capital resources for the periodic maturity of certain series of debt and preferred stock. Net cash flow from operations totaled $346 million, $224 million, and $262 million in 1993,1992, and 1991, respectively. The increase in AP&L's 1993 cash flow from operations resulted pnmarily from increased electricity sales and increased collections under the phase-in plan, as discussed below. In recent years, this cash flow, supplemented by issuances of debt and proceeds from the sale of retail properties in Missouri, has been sufficient to meet substantially all investing and financing requirements, including capital expenditures, dividends, and debt / preferred stock maturities. AP&L's ability to fund these capital requirements results, in part, from our continued efforts to streamhne operations and reduce costs, as well as ccilections under our Grand Gulf I rate phase-in plan which exceed the current cash requirements for Grand Gulf 1-related costs. (In the income statement, these revenue collections are offset by the amortization of presiously deferred costs, therefore, there is no effect on net income.) See Note 2, incorporated herein by reference, for additional information on AP&L's rate phase-in plan. See Note 8, incorporated herein by reference, for additional information on AP&L's capital and refinancing requirements in 1994 - 1996. Further, in order to take advantage of lower interest and dividend rates, AP&L may continue to refinance high-cost debt and preferred stock prior to maturity. Earmngs coverage tests (which are impacted by the inclusion of the cumulative effect of the change in accounting principle for accruing unbilled revenues discussed in Note 1) and bondable property additions limit the amount of first mortgage bonds and preferred stock that AP&L can issue. Based on the most restrictive applicable tests as of December 31,1993, and an assumed annual interest or dividend rate of 8%, AP&L could have issued $226 million of additional first mortgage bonds or $1,075 million of additional preferred stock. AP&L has the conditional ability to issue first mortgage bonds and preferred stock against the retirement of first mortgage bonds and preferred stock, respectively, in some cases, without satisfying an canungs coverage test. See Notes 5 and 6, incorporated herein by reference, for information on AP&L's 6mncing activities and Note 4, incorporated herein by reference, for information on AP&L's short-term borrowings and lines of credit.
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ARKANSAS POWER & LIGHT COMPANY STATEMENTS OFINCOME For the Years Ended December 31, 1993 1992 1991 (in Thousands)
$1,591,568 $1,521,129 $1,528,270 Operating Revenues (Notes 1,2, and 1!):
Operstmg Expenses: Operation (Note 11): Fuel for electric generation and fuel-related ' 257,983 242,040 268,699 expenses 349,718 417,099 378,069 Purchased power 294,103 285,740 298,584 Other 109,724 118,540 108,398 Maintenance (Note 11) 135,530 132,459 128,410 Depreciation and decommissioning 28,626 26,709 23, % 8 Taxes other than income taxes 18,746 4,058 22,958 Income taxes (Note 3) 160,916 114,711 80,666 Amortization of rate defenals (Note 2) 1.355,346 1,341,356 1,308,852 Total , 236,222 179,773 219,418 Operating Income Other Income , Allowance for equity funds used during 3,627 4,173 4,508 construction 64,884 113,842 82,733 Miscellaneous - net (Note 2) (32,451) (46,531) (30,908) Income taxes (Note 3) 36,060 71,484 56,333 Total Interest Charges: 107.771 120,318 133,854 Interest on long-term debt 11,819 3,666 2,415 Other interest - net Allowance for borrowed funds used during (2,418) (3,256) (3,969) construction 117,172 120,728 132,300 Total Income before Cumulative Effect of a Change 155,110 130,529 143,451 in Accounting Principle ( Cumulative Effect to January 1,1993, of Acenung Unbilled Revenues (net ofincome taxes of
$31,140)(Note 1) 50,187 - -
205,297 130,529 143,451 Net income 20,877 23,202 22,870 Preferred Stock Dividend Requirements
$184,420 $107,327 $120,581 Earmngs Applicable to Common Stock See Notes to Financial Statements.
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ARKANSAS POWER & LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1993 1992 1991 (In Thousands) Retained Earmngs, January 1 $420,691 $388,364 $307,683 Add: , l Net income 205,297 130,529 143,451 Total 625,988 518,893 451,134 Deduct: Divulenda declared: Preferred stock 20,877 23,202 22,870 Common stock 156,300 75,000 39,900 Total 177,177 98,202 62.770 t Retained Earmngs, December 31 (Note 7) 5448,811 5420,691 $388,364 See Notes to Financial Statements. f l 1 i 1 l
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i l 1 I 1 ARKANSAS POWER & LIGIIT COMPANY MANAGEMENT'S FINANCIAL DISCUSSICN AND ANALYSIS RESULTS OF OPERATIONS Net income Net income increased in 1993 due prunarily to the one-time recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1, incorporated herein by reference) and its ongoing effects, partially offset by the effect of implementing SFAS 109 (see Note 3, incorporated herein by reference) and by the impact in March 1992 of an after-tax gain from the sale of AP&L's retail properties in Missouri. Effective January 1,1993, AP&L began accruing as revenues the charges for energy delivered to customers but not yet billed. Electric revenues were previously recorded on a cycle-billing basis. Excluding the above mentioned items, net income for 1993 would have been $157.7 million and net income for 1992 would have been $110.9 million increase of $46.8 million is due prunarily to increased retail energy sales. Net income decreased in 1992 due primarily to decreased operating revenues and slight increases in maintenance expense, taxes other than income taxes, depreciation and decommissioning expense, and the retained share of Grand Gulf 1-related costs. These decreases in net income were partially offset by the $19.6 million after-tax gain from the sale of AP&L's retail properties in Missouri in March 1992 and a decrease in interest expense. Significant factors affecting the results of operations and causing vanances between the years 1993 and 1992, and 1992 and 1991, are discussed under " Revenues and Sales", " Expenses", and "Other" below. Revenues and Sales See " Selected Financial Data - Five-Year Comparison," incorporated herein by reference, following the notes, for information on operating revenues by source and KWH sales. Electric operating revenues were higher in 1993 due to an increase in residential and commercial energy sales resulting from a retum to more normal weather as compared to milder weather in 1992. Industrial sales increased primarily in the lumber / plywood and petroleum / natural gas pipeline industries. Additionally, electric revenues increased as a result of increased collections of previously deferred Grand Gulf 1-related costs, which does not impact net income. Electric operating revenues were lower in 1992 due primarily to decreased retail revenues resulting from milder temperatures and the loss of the Missouri retail customers. This decrease was partially offset by increased revenues from sales for resale due to the addition of Union Electric as a wholesale customer resulting from the Missouri property sale. Total energy sales were lower in 1992 due primarily to decreased retail sales as discussed above and decreased sales for resale to associated companies resulting from changes in generation availability and icquirements among AP&L, LP&L, MP&L, and NOPSI. Ernenses Fuel for electric generation and fuel-related expenses increased in 1993 due primarily to an increase in generation requirements resulting primarily from increased retail energy sales and increased fuel costs as discussed in " Revenues and Sales" above. Purchased power decreased in 1993 due primarily to energy demands being met by increased nuclear generation. I l l
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)
l
ARKANSAS POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS , RESULTS OF OPERATIONS -(Concluded) { Scheduled refueling outages at both ANO 1 and ANO 2 during 1992, and an unscheduled outage at ANO 2 from March 1992 to May 1992, contributed to the decrease in fuel for electric generation and fuel-related c:-r-:Em , and the corresponding increase in purchased power in 1992. Lower energy sales in 1992 also contributed to decreased fuel expenses The amortuation of rate deferrals increased in 1993 and 1992 due to increased amortuation of previously . : deferred Grand Gulf 1-related costs pursuant to the step-up provisions of AP&L's phase-in plan. Total income taxes increased in 1993 due primarily to higher pretax income, an increase in the federal i income tax rate as a result of OBRA, and the effect ofimplementing SFAS 109. W Other Miscellaneous other income - net decreased in 1993 and increased in 1992 due primarily to the impact of i the pretax gain on the 1992 sale of AP&L's retail properties in Missouri. j Interest on long-term debt decreased in 1993 due pnmarily to the continued refinancing of highe debt. i Other interest - net was higher in 1993 as AP&L began recording d+:9. ; =sioning interest expense on its decommissioning trust fund, His expense has no effect on net income, as d+:--;- Innioning trust fund carmngs are , recorded in miscellaneous other income - net. 5 6
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ARKANSAS POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Comoetition AP&L welcomes competition in the. electric energy business and believes that a more competitive emironment should benefit our customers, employees, and shareholders of Entergy Corporation. We also recognize that competition presents us with many challenges, and we have identified the following as our major competitive challenges: Retail and Wholesale RateIssues increasing competition in the utility industry brings an increased need to stabilize or reduce retail rates In connection with the Merger, AP&L agreed with its retail regulator not to request any general rate increases that would take effect before November 1998, with certain exceptions. See Note 2, incorporated herein by reference, for further information. Retail wheeling, a major industry issue which may require utilities to " wheel" or move power from third parties to their own retail customers, is evohing gradually. As a result, the retail market could become more competitive. In the wholesale rate area, FERC approved in 1992, with certain modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power to sell wholesale power at market-based rates and to provide to electric utilities "open access" to the System's transmission system (subject to certain requirements). GSU was later added to this filing. Various intervenors in the proceedmg filed petitions for resiew with the United States Court of Appeals for the District of Columbia Circuit. FERC's order, once it takes effect, will increase marketing opportunities for AP&L, but will also expose AP&L to the risk of loss of load or reduced revenues due to competition with alternative suppliers. In light of the rate issues discussed above, AP&L is aggressively reducing costs to avoid potential cammgs crosions that might result as well as to successfully compete by becoming a low-cost producer. To help imnmuze future costs, AP&L remams committed to least cost planning. In December 1992, AP&L filed a Least Cost Integrated Resource Plan (Inst Cost Plan) with its retail regulator. Least cost planning includes demand-side measures such as customer energy conservation and supply-side measures such as more efficient power plants. Dese measures are designed to delay the building of new power plants for the next 20 years. AP&L plans to periodically file revised Least Cost Plans. lhe Enern Poliev Act of1992 He Energy Policy Act of 1992 (Energy Act) is changing the transmission and distribution of electricity. This act encourages competition and affords us the opportunities, and the risks, associated with an open and more competitive market environment. He Energy Act increases competition in the wholesale energy market through the creation of exempt wholesale generators (EWGs). The Energy Act also gives FERC the authority to order investor-owned utilities to provide transmission access to or for other utilities, includmg EWGs.
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ARKANSAS POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS -(Concluded) ANO Matters Leaks in certain steam generator tubes at ANO 2 were discovered and repaired during outages in March and September 1992. During a mid-cycle outage in May 1993, a scheduled special inspection of certain steam generator tubing was conducted by Entergy Operations and additional repairs were made. The operations and power output of ANO 2 have not been adversely affected by these repairs and AP&L's budgeted maintenance expenditures were adequate to cover the cost of such repairs. Entergy Operations is taking steps at ANO 2 to reduce the number and severity of future tube cracks. Entergy Operations met with the NRC in August 1993 to discuss such steps along with recent inspection findings and intervals between future inspections. 'Ihe NRC concurred with Entergy Operations' proposal to operate ANO 2 with no further steam generator inspections until the next refueling outage, which is scheduled for the spring of 1994. 7 4 1 k I b
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l l ARKANSAS POWER & LIGIIT COMPANY NOTES TO FINANCIAL STATEMENTS NOTE 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES AP&L maintains accounts in accordance with FERC and other regulatory guidelines. Certain pretiously reported amounts have been reclassified to conform to current classifications. Revenues and Fuel Costs Prior to January 1,1993, AP&L recorded revenues when billed to its customers with no accrual for energy delivered but not yet billed. To provide a better matching of revenues and expenses, effective January 1,1993, The AP&L adopted a change in accounting principle to provide for accrual of acimataA unbilled revenues. cumulative effect of this accounting change as of January 1,1993, increased net income by $50.2 million. Had this new accounting method been in effect during prior years, net income before the cumulative effect would not have been materially different from that shown in the accompanying financial statements. Substantially all of AP&L's rate schedules include fuel adjustment clauses that allow either current recovery or deferrals of fuel costs until such costs are reflected in the related revenues. The fuel adjustment clause provides, as an incentive with respect to ANO, for over or under-recovery of the cost of replacement energy in excess of the cost of equal amounts of nuclear energy when the units are not down for refueling. Utility Plant Utility plant is stated at original cost. The original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Maintenance, repairs, and minor ( replacement costs are charged to operating expenses. Substantially all of AP&L's utility plant is subject to the lien ofits mortgage and deed of trust. AFUDC represents the approxunate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases utility plant and increases cammgs, it is only realized in cash through depreciation provisions included in rates. AP&L's effective composite rates for AFUDC were 10.3%,10.5%, and 10.7% for 1993,1992, and 1991, respectively. I Depreciation is computed on the straight-line basis at rates based on the estunated service lives and costs of removal of the various classes of property. Depreciation provisions on average depreciable property approximated 3.4% in 1993,1992, and 1991. Jointiv-Owned Generatine Stations AP&L is a co-owner in two coal-fueled, two-unit generating stations, the White Bluff Station and the Independence Station. AP&L is the agent for the respective co-owners and operates the stations. AP&L records its investment and expenses associated with these generating stations to the extent of its ownership interests. As of December 31,1993, AP&L's investment and accumulated depreciation in these generating stations were as follows: Total Megswett Accumulated Canability Ownershio Investment Deoreciation Generatine Stations (In Thousands) 57.00 % $398,644 $140,731 White Bluff; Units 1 and 2 946 263 31.50 % $116,511 S 35,797 Independence: Unit 1 15.75 % $ 29,163 $ 8,043 Common Facilities
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ARKANSAS POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) Income Taxes AP&L, its parent, and affiliates (excluding GSU prior to 1994) file a consolidated federal income tax return. Income taxes are allocated to AP&L in proportion to its contribution to consolidated taxable income. SEC l regulations require that no System company pay more taxes than it would have had a separate income tax return been filed. Deferred taxes are recorded for all temporary differences between book and taxable income. Investment tax credits are deferred and amortized based upon the average useful life of the related property in accordance with rate treatment. As discussed in Note 3, effective January 1,1993, AP&L changed its accounting for income taxes to conform with SFAS 109. Reacquired Debt l The premiums and costs associated with reacquired debt are being amortized'over the life of the related
]'
new issuances, in accordance with ratemakmg treatment. Cash and Cash Eauivalents 1 AP&L considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Fair Value Disclosure l The estimated fair value amounts of fmancial instruments have been deternuned by AP&L, using available market information and appropriate valuation methodologies. However, considerable judgment is required in developing the estunates of fair value. Therefore, estunates are not necessarily indicative of the amounts that AP&L could realize in a current market exchange. In addition, gains or losses reahzed on financial instruments may be reflected in future rates and not accrue to the benefit of stockholders. AP&L considers the carrying amounts of financial instruments classified as current assets and liabilities to be a reasonable esumate of their fair value because of the short maturity of these instruments. In addition, AP&L does not presently expect that performance ofits obligations will be required in connection with certain off-balance sheet commitments and guarantees considered financial instruments. Due to this factor, and because of the related party nature of these commitments and guarantees, deternunation of fair value is not considered practicable. See Notes 5,6, and 8 for additional fair value disclosure. NOTE 2. RATE AND REGULATORY MATTERS
.l Rate Aareement In November 1993, AP&L and the APSC entered into a settlement a s wr.cr.t whereby the APSC agreed to withdraw its request for heanng and its objections in the SEC prWN related to the Merger. In return, AP&L agreed, among other thmgs, (a) that it will not request any general retail rate increase that would take effect before November 3,1998, except, among other things, for increases associated with the Least Cost Plan, recovery of-l-
certain Grand Gulf 1-related costs, excess capacity costs and costs related to the adoption of SFAS 106 that were previously deferred, recovery of certam taxes, and force majeure (defined to include, among other thmgs, war, natural catastrophes, and high inflation); and (b) that its retail ratepayers would be protected from (1) increases in l its cost of capital resulting from risks associated with the Merger, (2) recovery of any portion of the acquisition i l premium or transactional costs associated with the Merger, (3) certain direct allocations of costs associated with
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l j m__________ _______________._________._____________________________;
ARKANSAS POWER & LIGIIT COMPANY l NOTES TO FINANCI AL STATEMENTS - (Continued) GSU's River Bend nuclear urut, and (4) any losses of GSU resulting from resolution oflitigation in connection with its onership of River Bend. l Arkansas - Revised Settlement Arreement Pursuant to the terms of the Revised Settlement Agreement, AP&L (1) permanently retams a portion ofits Grand Gulf 1-related costs (Retamed Share), ranging from 5.67% (stated as a percentage of System Energy's share i of Grand Gulf 1) in 1989 to 7.92% in 1994 and all succeedmg years of commercial operation of the unit; (2) recovers currently a portion of such costs, ranging from 17.86% in 1989 to 28.08% in 1994 and thereafter; and (3) deferred a portion of such costs for future recovery (Deferred Balance). AP&L is permitted to currently recover i I carrying charges on the unrecovered portion of the Deferred Balance. For the year ended December 31, 1993,
$234 million was billed to AP&L by System Energy.
AP&L has the right under the Revised Settlement Agreement to sell capacity and energy available from its Retamed Share to third parties, which shall not include AP&L's wholesale customers. In the event AP&L is not l able to sell such capacity and energy to such third parties, it has the right to sell the energy available from such i I capacity, and to date a significant portion has been sold, to its retail customers at a price equal to AP&L's avoided eng cost, which is currently less than AP&L's cost of such energy. He Revised Settlement Agreement requires the a portion of the proceeds from sales of Retamed Share capacity and energy to third parties through 1995 be applied to reduce the Deferred Balance. Arkansas - Rate Riders In conjunction with the Revised Settlement Agreement, AP&L was permitted to implement annual updates to the Grand Gulf I rate rider, increasing Arkansas retail rates by approximately 3.1% and 2.6% for the 3 tars 1992 and 1991, respectively. Rese increases reflect scheduled phase-in plan increases adjusted for any prior year over or under-collection. Beginning in lop 3 and continuing for a five year period, rates will remain at the 1992 level, unless adjustments are made for an over or under-collection of Grand Gulf 1-related costs in excess of $10 million. Although it was not required under the terms of the Grand Gulf I rate rider, in 1993 AP&L opted to implement a 0.7% rate refund in 1994 for a cumulative over-recovery amount of $7.3 million. Various other rate riders, which modify non-Grand Gulf I rates under the Revised Settlement Agreement, have been implemented with respect to tax adjustments, depreciation, decommissioning costs, and deferred return on excess capacity (which is being recovered over a 10-year period ending in 1998). Missouri Retsil Occrations in March 1992, AP&L sold its retail properties in Missouri for approxunately $68 million. AP&L's retail properties in Missouri constituted less than 2% ofits total property. The cash receised from the sale, which also included Missouri accounts receivable and material and supplies inventory, was approximately $72 million, which was in excess of book value. He gain on the sale, classified as *Other Income-Miscellaneous" in the 1992 Statement ofIncome, was approximately $33.7 million, which resulted in a $19.6 million increase in net income after taxes. Under the terms of the contract, AP&L's 28,000 Missouri retail customers became Union Electric customers and AP&L's employees in Missouri became Union Electric emplo>tes. He proceeds from this sale were used to redeem all or a portion of certain series of AP&L's outstanding first mortgage bonds at special redemption prices, pursuant to the applicable provisions of AP&L's mortgage and deed of tnist. In addition, AP&L has agreed to sell to Union Electric 120 megawatts of capacity and associated energy for an initial period of 10 years, and beginning on January 1,1995, Union Electric shall also purchase 40 megawatts of peakmg capacity from AP&L.
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ARKANSAS POWER & LIGHT COMPANY :
- NOTES TO FINANCIA L STATEMENTS - (Continued)
NOTE 3. INCOME TAXES l Effective January 1,1993, AP&L adopted SFAS 109. His new standard requires that deferred mcome ! taxes be recorded for all temporary differences and carryforwards, and that deferred tax balances be based on I enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse SFAS 109 [ requires that regulated enterprises rarq=i= adjustments resulting from implementation as regulatory assets or i liabilities ifit is probable that such amounts will be recovered from or retumed to customers in future rates. A j substantial majority of the adjustments required by SFAS 109 was recorded to deferred tax balance sheet accounts with offsetting adjustments to regulatory assets and liabilities. He cumulative effect of the adoption of SFAS 109 ! is included in income tax expense charged to operations. As a result of the adoption of SFAS 109,1993 net income ! was reduced by $2.6 million, assets were increased by $168.2 million, and liabilities were increased by ! $170.8 million. Income tax expense consisted of the following: For the Years Ended D& ...M 31. ! 1993 1992 1991 l (In Thousands) Current: i Federal $47,326 S45,932 $ 34,648 ! State 10.836 11.156 9.770 7 Total 58.162 57.088- 44.418 Dcferred- net: Liberahzed depreciation 7,074 4,929 5,885 Altemative muumum tax (2,227) 6,577 6,249 i Nuclear refueling and maintenance . (2,161) 7,751 (5,001) i l Deferred purchased power costs (35,896) (14,375) (1,868)- Deferred excess capacity costs (4,044) (3,190) (1,609) ; Unbilled revenue 26,847 (2,474) 3,424 ; Bond reacquisition costs 14,706 5,184 765 : Intangible plant 410 1,941 4,514
]
Decontammation and decommissioning fund 16,429 - - i i Other 13.610 (2.853) (1.311) Total 34.74_1 3.490 11.048 I Investment tax credit adjustments - net (10.573) (9.989) (1.600) ) Recorded income tax expense S 82.337 M M 1 Charged to operations S I8,746 $ 4,058 522,958 i Charged to otherincome 32,451 46,531 30,908 Charged to cumulative effect 31.140 - - Recorded income tax expense 82,337 50,589 53,866 Income taxes applied agamst the debt component of AFUDC - 1 94 Totalincome taxes S 82.337 M M
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1 ARKANSAS POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) Total income taxes differ from the amounts computed by applying the statutory federal income tax rate to l income before taxes The reasons for the differences were: For the Years Ended December 31 1993 1992 1991
% of % of % of Pretaz Pretax Pretax Amount income Amount income Amount income (Dollars in Thousands)
Computed at statutory rate $ 100,673 35.0 $ 61,580 34.0 $ 67,088 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 12,119 4.2 7,963 4.4 7,409 3.7 Amortization ofinvestment tax credits (11,702) (4.1) (13,285) (7.4) (11,064) (5.6) Depreciation (3,156) (1.1) (6,755) (3.7) (6,122) (3.1) Reversalof tax contingency (3,771) (1.3) - - - - Flow-through/ permanent differences (7,669) (2.7) (1,407) (0.8) (76) - Other - ne; (4.157) _.(j4) 2.493 1.4 (3.369) _(LI) Recorded income tax expense 82,337 28.6 50,589 27.9 $3,866 27.3 In.:ome taxes applied agamst debt component cfAFUDC - - 1 - 94 - Totalincome taxes S 82.337 28 6 550.590 27 9 $ 53.960 27.3 Significant components of AP&L's net deferred tax liabilities as of December 31,1993, were (in thousands): Deferred tax liabilities: Net regulatory assets $ (294,713) Plant related basis differences (458,023) Rate deferrals (229,714) Bond reacquisition (23,604) Decontamination and dew Jssioning fund (16,429) Other (21.414) Total 5(1.043.897) Deferred tax assets: Alternative nurumum tax credit $ 34,137 Nuclear refueling and maintenance 12,035 Accumulated deferred investment tax credit 60,698 Standard coal plant 9,552 Other 18.490 Total $ 134.912 Net deferred tax liabilities S (908.985) The altemative minimum tax (Ahfr) credit as of December 31,1993, was $34.1 million. This Ahfr credit can be carried forward indefmitely and will reduce AP&L's federal income tax liability in future 3 tars.
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e
ARKANSAS POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized AP&L to effect short-term borrowings up to $125 million, subject to increase to as much as $255 million after further SEC approval. nese authorizations are effective through , November 30,1994. As of December 31,1993, AP&L had unused lines of credit for short-term borrowings of $34 million from banks within its service territory. In addition, AP&L can borrow from the Money Pool, subject to its manmum authorized level of short-term borrowings and the availability of funds. AP&L had $21.4 million in outstanding borrowings under the Money Pool arrangement as of December 31,1993. NOTE 5. PREFERRED STOCK , He number of shares and dollar value of AP&L's preferred stock was: i As of December 31. j Shares Call Price Per i Authorized and Total Share as of Outstandine Dollar Value Decemt er 31, 1993 1992 1993 1992 1993 (Dollars in Thousands) ! Without sinking fund: Cumulative, $100 par vak 4.32% Series 70,000 70,000 $ 7,000 $ 7,000 $103.647 4.72% Series 93,500 93,500 9,350 9,350 $107.000 4.56% Series 75,000 75,000 7,500 7,500 $102.830 4.56% 1965 Series 75,000 75,000 7,500 7,500 S102.500 6.08% Series 100,000 100,000 10,000 10,000 $102.830 7.32% Series 100,000 100,000 10,000 10,000 $103.170 7.80% Series 150,000 150,000 15,000 15,000 S103.250 7.40% Series 200,000 200,000 20,000 20,000 $102.800 7.88% Series 150,000 150,000 15,000 15,000 S103.000 Cumulative,525 par value: i 8.84% Series 400,000 400,000 10,000 10,000 S26.560 l A Cumulative,50.01 par value: S2.40 Series (l)(2) 2,000,000 2,000,000 50,000 50,000 - S1.96 Series (1)(2) 600.000 600.000 15.000 15.000 - Totalwithout sinking fund 4.013.500 4.013.500 $176.350 $176.350 With sinking fund: Cumulative, $100 par ulue: 10.60% Series 20,000 40,000 5 2,000 $ 4,000 $104.090 , 11.04% Series - 40,000 - 4,000 - 8.52% Series 400,000 425,000 40,000 42,500 $106.390 l Cumulative, $25 par value: 9.92% Series 721,085 801,085 18,027 20,027 526.940 , 13.28% Series 400.000 600.000 10.000 15.000 $28.220 Total with sinking fund 1.541.085 1.906.085 $ 70.027 $ 85.527 (1) He total dollar value represents the involuntary liquidation value of $25 per share. (2) Rese series are not redeemable as of December 31,1993.
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F
ARKANSAS POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) The fair value of AP&L's preferred stock with sinkmg fund was estunated to be approxunately $74.7 million and $89.3 million as oiDecember 31,1993 and 1992, respectively. The fair value was determined using quoted market prices or estunates from nationall j recogmzed investment bankmg firms. See Note I for additional information on disclosure of fair value of fmancial instruments. As of December 31,1993, AP&L had 2,296,500,7,478,915, and 12,400,000 shares of cumulative, $100, $25, and $0.01 par value preferred stock, respectively, that were authorized but unissued. Changes in the preferred stock, with and without sinkmg fund, during the last three years were: Number of Shares 1993 1992 1991 Preferred stockissuances:
- 600,000 2,000,000
$0.01 par value Preferred stock retirements:
(85,000) (109,940) (70,060)
$100 par value (280,000) (880,000) (280,000)
$25 par value Cash sinking fund requirements for the next five years for preferred stock rusanAng as of December 31,1993 are (in millions): 1994 - 58.0; 1995 - $3.0; 1996 - $7.0; 1997 - $7.0; and 1998 - $4.5. AP&L has the annual non-cumulative option to redeem, at par, additional amounts of certam series of its outstanding preferred stock. Additionally, AP&L has SEC authorization for the acquisition, through December 31,1995, of up to $150 million of preferred stock.
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ARKANSAS POWER & LIGIIT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) NOTE 6. LONG-TERM DEBT The long-term debt of AP&L as of December 31,1993 and 1992, was: Maturities Interest Rates Erp.,n_1 r TI From To 1993 1992 (In Thousands) First Mortgage Bonds 1993 1998 4-5/8% 8-3/4% $ 100,560 S 116,160 1999 2003 6% 9-3/4% 182,000 217,200 2004 2008 6.65 % 7-1/2% 215,000 175,000 2019 2023 7% 10-3/8 % 448,818 403,550 Govemmental Obligations
- 1995 2008 6.125 % 10 % 83,290 81,708 2009 2021 6-1/8% 11 % 202,193 202,193 Long-Term DOE Obligation (Note 8) 101,029 97,959 Unamortized Premium and Discount - Net (16.551) (14.923)
Total Long-Term Debt 1,316,335 1,278,847 Less Amount Due Within One Year 3.020 17.900 Long-Term Debt Excluding Amount Due Within One Year S1.313.315 $ L260.947 Consists of pollution control bonds, certain series of which are secured by non-interest bearing first mortgage bonds. The fair value of AP&L's long-term debt, excluding long-term DOE obligation, as of December 31,1993 and 1992 was estimated to be $1,250.8 million and $1,286.6 million, respectively. The fair value was determined using quoted market prices or estunates from nationally recogmzed investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. For the years 1994,1995,1996,1997 and 1998, AP&L has long-term debt maturities and cash sinking fund requirements (in millions) of $2.2, $27.4, $28.2, 533.5, and S19.4, respectively. In addition, other sinking fund requirements of approxunately S.9 million annually may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements. AP&L has regulatory authorization for the issuance and sale through December 31,1995, of up to
$600 million of additional first mortgage bonds (of which $270 million remamed available as of December 31,1993). In addition, AP&L has SEC authorization for the acquisition of not more than $350 million of first mortgage bonds (of which $100 million remamed available as of December 31,1993) and $175 million of pollution control revenue bonds and/or solid waste disposal revenue bonds, issued for the benefit of AP&L through December 31,1995.
NOTE 7. DIVIDEND RESTRICTIONS The indenture relating to AP&L's long-term debt and provisions of the Amended and Restated Articles of Incorporation, as amended, relating to AP&L's preferred stock provide for restrictions on the payment of cash dividends or other distributions on common stock. As of December 31,1993, $291.3 million of AP&L's retained
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i l ARKANSAS POWER & LIGIIT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) earnings were restricted agamst the payment of cash dividends or other distributions on common stock. On February 1,1994, AP&L paid Entergy Corporation a $17.9 million cash disidend on common stock. NOTE 8. COMMITMENTS AND CONTINGENCIES Canital Reovirements and Financine Construction expenditures (excluding nuclear fuel) for the years 1994,1995, and 1996 are estimated to total $181 million, $172 million, and $175 million, respectively. AP&L will also require $83 million during the period 1994-1996 to meet long-term debt and preferred stock maturities and sinkmg fund requirements. AP&L plans to meet the above requirements with intemally generated funds and cash on hand, supplemented by the issuance of debt and preferred stock. See Notes 5 and 6 regarding the possible refunding, redemption, purchase or other acquisition of certain outstanding series of preferred stock and long-term debt. See Note 12 for information on additional capital requirements related to a February 1994 ice storm. Unit Power Sales Arreement System Energy has agreed to sell all of its 90% owned and leased share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this agreement are paid in consideration for AP&L's respective entitlement to receive capacity and energy, :.nd are payable irrespective of the quantity of energy delivered so long as the unit remams in commercial operation. The agreement will remain in effect until terminated by the parties and approved by FERC, most likely upon Grand Gulf l's retirement from service. AP&L's monthly obligation for payments under the agreement is approximately $19 million. Availability Arreement AP&L, LP&L, MP&L, and NOPSI are individually obligated to make payments or subordmated advances to System Energy in accordance with stated percentages (AP&L 17.l*4 LP&L 26.9%, MP&L 31.3%, and NOPSI 24.7%) in amounts that when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy's operating expenses. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Payments or advances under the Availability Agreement are only required if funds available to System Energy from all sources are less than the amo,nt required under the Availability Agreement. Since commercial operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments have ever been required. In 1989, the Availability Agreement was am-W to provide that the write-otf of
$900 million of Grand Gulf 2 costs would be amortized for Availability Agreement purposes over a period of 27 years, in order to avoid the need for payments by AP&L, LP&L, MP&L, and NOPSI.
Reallocation Aercement System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation Agreement relating to the sale of capacity and energy from the Grand Gulf Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and obligations with respect to the Grand Gulf Station under the Availability Agreement. FERC's decision allocating a portion of Grand Gulf I capacity and energy to AP&L supersedes the Reallocation Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect AP&L's obligation
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l ARKANSAS POWER & LIGHT COMPANY I NOTES TO FINANCIAL STATEMENTS -(Continued) ; i to System Energy's lenders under the assignments referred to in the precedmg paragraph. AP&L would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual obligations. No payments of any amortization amounts will be required as long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future. System Fuels AP&L has a 35% interest in System Fuels, a jointly owned subsidiary of AP&L, LP&L, MP&L, and NOPSI. The parent companies of System Fuels, including AP&L, agreed to make loans to System Fuels to finance its fuel procurement, delivery, and storage activities. As of December 31,1993, AP&L had approximately
$11 million ofloans outstanding to System Fuels which mature in 2008.
In addition, System Fuels entered into a revolving credit ag.eement with a bank that pro 5 ides $45 million in borrowings to finance System Fuels' nuclear materials and senices inventory. Should Syrtra Fuels default on its obligations under its credit agreement, AP&L, LP&L, and System Energy have agreed to purchase nuclear materials and senices fmanced under the agreement. On April 30,1993, AP&L assumed System Fuels' rights and obligations in connection with System Fuels' coal car leases. He other parent companies of System Fuels have been released from their obligations with respect to the coal car leases. Coal AP&L is a party to a contract with a joint venture for supply of coal from a mine in Wyoming which, based on estimated reserves, is expected to provide the projected requirements of the Independence Station through at least 2014. AP&L has also agreed to purchase, over an approximate 20-year period beginning in 1980, 100 million tons of coal for use at the White Bluff Station, of which approximately 60 million have been purchased as of December 31,1993. Nuclear Insurance The Price-Anderson Act limits public liability for a single nuclear incident to approximately $9.4 billion as of December 31,1993. AP&L has protection for this liability through a combination of private insurance (currently $200 million) and an industry assessment program. Under the assessment program, the maxunum amount that would be required for each nuclear incident would be $79.28 million per reactor, payable at a rate of $10 million per licensed reactor per incident per year. AP&L has two licensed reactors. In addition, the System participates in a private insurance program which provides coverage for worker tort claims filed for bodily injury caused by radiation exposure. AP&L's maximum assessment under the program is an aggregate of approximately $6.2 million in the event losses exceed accumulated reserve funds. AP&L is a member of certain insurance programs that provide coverage for property damage including decontamination and premature decommissioning expense, to members' nuclear generating plants. As of December 31,1993, AP&L was insured against such losses up to $2.7 billion, with $250 million of this amount designated to cover any shortfall in the NRC required decommissioning trust funding. In addition, AP&L is a member of an insurance program that covers certain replacement power and business interruption cost.s incurred due to prolonged nuclear unit outages. Under the property damage and replacement power / business interruption insurance programs, AP&L could be subject to assessments iflosses exceed the accumulated funds available to the
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ARKANSAS POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) insurers. As of December 31,1993, the maxunum amount of such possible assessments to AP&L was $28.14 million. He amount of property insurance presently carried by AP&L exceeds the NRC's muumum requirement for nuclear power plant licensees of $1.06 billion per site. NRC regulations provide that the proceeds of this insurance must be used, first, to place and maintain the reactor in a safe and stable condition and, second, to complete
.lecontammation operations. Only after proceeds are dedicated for such use and regulatory approval is secured, would any remaining proceeds be made available for the benefit of plant owners or their creditors.
Soent Nuclear Fuel and Decommissionine Costs AP&L provides for estunated future disposal costs for spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. AP&L entered into a contract with the D0E, whereby the DOE will furnish disposal service at a cost of one mill per net KWH generated and sold after April 7,1983, plus a one-time fee for generation prior to that date. AP&L clected to pay the one-time fee, plus accrued interest, and has recorded a liability as of December 31,1993, of approxunately $101 million. The fees payable to the DOE may be adjusted in the future to assure full recovery. AP&L considers all corts incurred or to be incurred, except accrued interest, for the disposal of spent nuclear fuel to be proper components of nuclear fuel expense and prosisions to recover such costs have been or will be made in applications to regulatory authorities. Due to delays of the DOE's repository program for the acceptance of spent nuclear fuel, it is uncertain when shipments of spent fuel from AP&L's nuclear units will commence. In the meantime, AP&L is responsible for spent fuel storage. Current on-site spent fuel storage capacity at ANO is estunated to be sufficient until 1995. Thereafter, AP&L will provide additional storage capacity at an estunated initial cost of $5 million to $10 million per unit. In addition, approximately $3 million to 55 million per unit will be required every two to three years subsequent to 1995 until the DOE's repository program begins accepting ANO's spent fuel. AP&L is recovering in rates amounts sufficient to fund decommissioning costs for ANO, based on a 1992 update to the original decommissioning cost study, of approximately $606.8 million (in 1992 dollars). R ese amounts are deposited in external trust funds which have a market value of approximately $124.3 million and
$101.3 million as of December 31,1993 and 1992, respectively. He accumulated decomrresioning liability of $119.2 million as of December 31, 1993, has been recorded in accumulated depreciation.. Decommissioning expense in the amount of $11.0 million was recorded in 1993. During the first quarter of 1994, AP&L expects to file with the APSC an interim update of the ANO cost study which will likely reflect significant increases in costs oflow-level radioactive waste disposal. AP&L regularly reviews and updates its estunates for decommissioning costs and applications will be made to the APSC to reflect in rates future changes in projected cecommissioning costs, he actual decommissioning costs may vary from the above estunates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment, and management believes that actual decommissioning costs are likely to be higher than the amounts presented above.
The Energy Act has a provision that assesses domestic nuclear utilities with fees for the decontammation and decommissioning of the DOE's past uranium enrichment operations. The decontamination and decommissioning assessments will be used to set up a fund into which contributions from utilities and the federal government will be placed. AP&L's annual assessment, which will be adjusted annually for inflation, is approximately $3.3 million (in 1993 dollars) for approximately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortized. He liability of $45.7 million as of December 31,1993 is recorded in other current liabilities and other noncurrent liabilities and is offset in the financial aments by a regulatory asset, recorded as a deferred debit. 134
I l l 1 ARKANSAS POWER & LIGIIT COMPANY l NOTES TO FINANCIAL STATEMENTS - (Continued) l i NOTE 9. LEASES As of December 31,1993, AP&L had capital leases and noncancelable operating leases (excluding the nuclear fuel lease) with nummum lease payments as follows: Capital Operating Leases Leases (In Thousands) 1994 S 13,189 S 17,284 1995 13,544 17,229 1996 11,127 16,068 1997 8,293 10,548 1998 8,293 10,514 Years thereafter 56.989 21.908 Minimum lease payments 111,435 $ 93.551 Less: Amount representing interest (47.674) Present value of net nummum lease payments S 63 16,1 Rental expense for capital and operating leases (excluding the nuc! ear fuel lease) amounted to approximately $23.2 million, $27.4 million, and $26.2 million in 1993,1992, and 1991, respectively. Nuclear Fuel Lease AP&L has an arrangement to lease nuclear fuel in an amount of up to $125 million.. 'Ibe lessor finances its acquisition of nuclear fuel through a credit agreement and the issuance of notes. The credit agreement, which was entered into in 1988, has been extended to December 1996 and the notes have varying remammg maturities of up to 4 years. It is expected that these arrangements will be extended or alternative financing will be secured by the lessor upon the maturity of the current arrangements, based on AP&L's nuclear fuel requirements. If the lessor cannot arrange fmancing upon maturity of its borrowings, AP&L must purchase nuclear fuel in an amount sufficient to enable the lessor to retire such borrowings. Lease payments are based on nuclear fuel use. Nuclear fuel lease expense of $69.7 million, $65.5 million, and $76.9 million (including interest of S10.6 million, $11.6 million, and $14.0 million) was charged to operations in 1993,1992, and 1991, respectively. NOTE 10. POSTRETIREMENT BENEFITS Pension Plan AP&L has a defined benefit pension plan covering substantially all ofits employees. "Ihe pension plan is noncontributory and provides pension benefits that are based on employees' credited senice and average compensation, during the last ten years of employment. AP&L funds pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plan consist pnmarily of common and preferred stocks, fixed income securities, interest in a money market fund, and insurance contracts.
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ARKANSAS POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) Effective June 6,1990, AP&L's nuclear operations employees became employees of Entergy Operations. However, the employees still remam under AP&L's plan and no trknsfers of related pension liabilities and assets have been made. AP&L's 1993,1992, and 1991 pension cost, including amounts capitahzed, included the following components: For the Years Ended December 31. 1993 1992 1991 (In Thousands) S 7,940 $ 6,906 5 6,210 Service cost - benefits camed during the period 21,744 20,512 18,505 Interest cost on projected benefit obligation (31,984) (16,765) (47,707) Actual return on plan assets 10,531 (3,531) 28,377 Net amortization and deferral
- - 915 Other S 8.231 5 7.122 5 6.300 Net pension cost The funded status of AP&L's pension plan as of December 31,1993 and 1992, was:
1993 1992 (In Thousands) Actuarial present value of accumulated pension plan benefits:
$255,955 S228,237 Vested 1.724 1.211 Nonvested
$257.679 S229.468 Accumulated benefit obligation
$288,418 $255,956 Plan assets at fair value 316.255 272.148 Projected benefit obligation (27,837) (16,192)
Plan assets less than projected benefit obligation ' 5,841 6,168 UnrespM prior service cost (18,686) (21,022) Unrecogruzed transition asset 13.242 (5.806) Unrecogmzed net loss (gain)
$ (27.440) $(36<852)
Accrued pensionliability The significant actuanal assumptions used in computing the information above for 1993,1992, and 1991 were as follows: weighted average discount rate,7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in future compensation levels, 5.6%; and expected long-term rate of return on plan assets, 8.5%.
- Transition assets are being amortized over 15 years.
Other Postretirement Benefits AP&L also provides certain health care and life insurance benefits fer retired employees. Substantia employees may become eligible for these benefits if they reach reurement age while still wotting for AP&L. The cost of providing these benefits, recorded on a cash basis, to retirees in 1992 was approximately $3.5 million. Prior to 1992, the cost of providing these benefits for retired employees was not separable from the cost of providir4 benefits for active unployees. Based on the ratio of the number of retired employees to the total number of active and retired employees in 1991, the cost of providing these benefits in 1991, recorded on a cash basis, for retirees was approximately $4.1 million.
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ARKANSAS POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) Effective January 1,1993, AP&L adopted SFAS 106. He new standard requires a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. AP&L continues to fund these benefits on a pay-as-you-go basis. As of January 1,1993, the actuanally determmed accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estunated to be approximately $80.5 million. His obligation is being amortized over a 20-year period begmning in 1993. AP&L has received an order from the APSC permitting deferral, as a regulatory asset, of the increased annual expense associated with these benefits. AP&L's 1993 postretirement benefit cost, including amounts capit=h7M and deferred, included the following components (in thousands): Senice cost - beneSts camed during the period S 2,366 Interest cost on APBO 6,427 Actual return on plan assets (71) Amortization of transition obligation 3.954 Net periodic postretirement benefit cost S12.676 He funded status of AP&L's postretirement plan as of December 31,1993, was (in thousands): Accumulated postretirement benefit obligation: Retirees S 59,906 Other fully eligible participants 8,366 Other active participants _ 25.038 93,310 Plan assets at fair value 354 Plan assets less than APBO (92,956) Unrecognized transition obligation 75,114 Unrecogm7M net loss 8.360 ; Accmed postretirement benefit liability S (9.482) I De assumed health care cost trend rate used in measuring the APBO was 9.9% for 1994, gradually decreasing each successive year until it reaches 5.6% in 2020. A one percentage-point increase in the assumed health care cost trend rate for each year would have increased the APBO as of December 31,1993, by 8.7 % and the sum of the service cost and interest cost by approxunately 11.2%. The nemM dimmt rate and rate of l increase in future compensation used in determining the APBO were 7.5% and 5.5%, respectively. NOTE 11. TRANSACTIONS WITH AFFILIATES AP&L buys electricity from and/or sells electricity to LP&L, MP&L, NOPSI, System Energy, and Entergy Power under rate schedules filed with FERC. In addition, AP&L purchases fuel from System Fuels, ceceives technical and advisory senices from Entergy Senices, Inc. and receives management and operating senices from Entergy Operations. Operating revenues include revenues from sales to affiliates amounting to $181.8 million in 1993, $211.4 million in 1992, and $212.6 million in 1991. Operating expenses include charges from affiliates for fuel costs, purchased power and related charges, management senices, and technical and advisory senices totaling $323.2 million in 1993, S573.4 million in 1992, and $510.1 million in 1991. Operatmg expenses also include
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ARKANSAS POWER & LIGHT COMPANY l NOTES TO FINANCIAL STATEMENTS -(Concluded) $16.8 million in 1993, S47.4 million in 1992, and $33.4 million in 1991 for power purchased from Entergy Power. AP&L pays directly or reimburses Entergy Operations for the costs associated with operating ANO (excluding nuclear fuel), which were approximately $226.3 million in 1993, $292.3 million in 1992, and $248.6 million in 1991. NOTE 12. SUBSEQUENT EVENT (UNAUDITED) In early February 1994, an ice storm left more than 97,000 AP&L custcmers without electric power in its service area. He storm was the most severe natural disaster ever to affect AP&L, causing damage to transmission and distribution lines, equipment, poles, and facilities in certain areas. A substantial portion of the related costs, which are estimated to be $25 million to $35 million, are expected to be capitnhnd Estimated construction expenditures (see Note 8) have not yet been updated to reflect the above amounts NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED) AP&L's business is subject to seasonal fluctuations with the peak period occurring during the third quarter. Operating results for the four quarters of 1993 and 1992 were: Operating Operating Net Revenues Income- income (In Thousands) 1993:
$346,740 $ 36,961 5 66,081 First Quarter (1) 5 34,572
$383,651 5 53,332 Second Quarter 5 81,677
$519,822 5101,484 Third Quarter $ 22,967
$341,355 5 44,445 Fourth Quarter 1992:
$338,996 5 39,402 5 41,725 First Quarter (2) $ 14,052
$347,224 $ 31,239 Second Quarter $ 62,059
$465,130 $ 79,006 hird Quarter 5 12,693
$369,779 5 30,126 Fourth Quarter (1) He first quarter of 1993 reflects a nonrecurring increase in net income of $50.2 million, net of taxes of
$31.1 million, due to the recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1). Begnuung with the second quarter, the remammg quarters are not generally comparable to prior year quarters because of the ongoing effects of the accounting change.
(2) The first quarter of 1992 reflects a nonrecurring increase in net income of $19.6 million, net of tax, due to the sale of retail properties in Missouri (see Note 2). )
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ARKANSAS POWER & LIGHT COMPANY SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON J 1993 1992 1991 1990 1989 (In Thousands) l 1 Operating revenue: $1,591,568 $1,521,129 $1,528,270 S1,481,408 $1,381,871 Income before cumulative effect of a change in I accounting principle S 155,110 S 130,529 S 143,451 S 129,765 S 131,979 Total assets $4,334,105 S4,038,811 $4,192,020 S4,137,938 $4,059,596 Long-term obligations (1) S1,478,203 $1,453,588 $1,670,678 S1,731,212 S1,584,749 (1) Includes long-term debt (excluding currently maturing debt), preferred stock with sinkmg fund, and noncurrent capital lease obligations. See Notes 1, 3, and 10 for the effect of accounting changes in 1993. 1993 1992 1991 1990 1989 (Dollars in Thousands) Operating Revenues: Residential S 528,734 S 476,090 $ 494,375 5 484,359 5 425,568 Commercial 306,742 291,367 289,291 283,971 254,636 Industrial 336,856 325,569 324,632 331,929 307,853 Governmental 16.670 17.700 19.731 19.599 20.990 Total retail 1,189,002 1,110,726 1,128,029 1,119,858 1,009,047 Sales for resale 379,480 385,028 373,735 339,366 345,377 Other 23.086 25.375 26.506 22.184 27.447 Total $1.591.568 $1.521.129 $1.528.270 $1.481.408 $1.381.871 Billed Electric Energy Sales (Millions of KWH): Residential 5,680 5,102 5,564 5,401 5,098 Commercial 4,067 3,841 3,967 3,821 3,644 ) Industrial 5,690 5,509 5,565 5,532 5,513 { Governmental 230 248 290 285 320 Total retail 15,667 14,700 15,386 15,039 14,575 Sales for resale 13.950 15.413 16.087 13.618 12.128 Total 29.617 30.113 31.473 28.657 26.703 I i l
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s Gulf States Utilities Company /1993 Financial Statements i 3 l d 1 i GSU
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I GULF STATES UTILITIES COMPANY DEFINITIONS Certain abbreviations or acronyms used in GSU's Financial Statements, Notes to Financial Statesnents, and l Management's Financial Discussion and Analysis are defined below: ' Abbreviation or Acronym Itan : AFUDC Allowance for Funds Used During Construction AP&L Arkansas Power & Light Cnmanay , Cajun Cajun Electric Power Cooperative, Inc. , DOE United States Department of Energy Entergy or System Entergy Corporation and its various direct and indirect subsidiaries Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy that has operating .i responsibility for Grand Gulf 1, River Bend, Waterford 3, and Arkansas Nuclear One Steam Electric Generatmg Station , FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission GSU Gulf States Utilities Company (including wholly owned subsidiaries - I Varibus Corporation, GSG&T, Inc., Prudential Oil and Gas, Inc., and - ! Southern Gulf Railway Company) i KWH Kilowatt-Hour (s) ! LP&L Louisiana Power & Light Company LPSC Louisiana Public Service Commission ! Money Pool Entergy Money Pool, which allows certain System companies to borrow from, or lend to, certain other System companies MP&L Mississippi Power & Light Company j Merger The combination transaction consumm=wi on December 31,1993, by - which GSU became a subsidiary of Entergy Corporation and Entergy Corporation became a Delaware corporation ; NOPSI New Orleans Public Service Inc.
]
PUCT Public Utility Commission ofTexas
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GULF STATES UTILITIES COMPANY DEFINITIONS -(Concluded) }
' Abbreviation or Acronym ItDR
. Rate Cap The level of retail electric base rates in effect at December 31,1993, for the Louisiana retail jurisdiction, and the level in effect prior to the Texas ,
Cities Rate Settlement for the Texas retail jurisdiction, that may not bc ; ew for the five years followmg December 31,1993 River Bend River Bend Steam Electric Generating Statum (nuclear), owned 70% by GSU ! SEC Securities and Exchange Commission .l SFAS Statement of Financial Accounting Standards promulgated by the FASB l SFAS No.106," Employers' Ac dag for Postretirement Benefits Other SFAS 106
'Ihan Pensions" .:
SFAS 109 SFAS No.109, "Acc=ating for Income Taxes" r System or Entergy Entergy Corporaten and its vanous direct and indirect subsidianes t System Aywrsa Aye.aa, effective January 1,1983, as amended among.the System , operstmg companies relatmg to the shanns of as .=g capacity and other power resources 5 System operstmg companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively i P l I u I
]
a L I
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l GULF STATES UTILITIES COMPANY f REPORT OF MANAGEMENT The management of Gulf States Utilities Company has prepared and is responsible for the financial statements and related financial information included herein. The financial statements are based on generally accepted accounting principles. Financial information included elsewhere in this report is consistent with the financial statements. To meet its responsibilities with respect to financial information, management maintains and enforces a system ofintemal accounting controls that is designed to provide reasonable assurance, on a cost-effective basis, as to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. His system includes communication through written policies and procedures, an employee Code of Conduct, and an organizational structure that provides for appropriate division of responsibility and the trauung of personnel. His system is also tested by a comprehensive intemal audit program. He independent public accountants provide an objective assessment of the degree to which management meets its responsibility for faimess of financial reporting. ney regularly evaluate the system of internal accounting controls and perform such tests and other procedures as they deem necessary to reach and express an opinion on the fairness of the financial statements. Management believes that these policies and procedures provide reasonable assurance that its operations are carried out with a high standard of business conduct. EDWIN LUPBERGER GERALD D. MCINVALE Chairman and Chief Executive Officer Senior Vice President and Chief Financial OfHeer i I I
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i I l i GULF STATES UTILITIES COMPANY 1 1 1 AUDIT COMMITTEE CIIAIRMAN'S LETTER he Gulf States Utilities Company Audit Committee of the Board of Directors is comprised of four directors, who are not officers of GSU: Bismark A. Steinhagen (Chairman-effective January 2,1994), Frank W. Harrison, Jr., M. Bookman Peters, and James E. Taussig, II. The committee held two meetings during 1993. He Audit Committee oversees GSUs fmancial reporting process on behalf of the Board of Directors and provides reasonable assurance to the Board that sufficient operatmg, accounting, and financial controls are in existence and are adequately reviewed by programs ofinternal and external audits. ne Audit Committee discussed with GSUs internal auditors and the todependent public accountants (Coopers & Lybrand) the overall scope and specific plans for their respective audits, as well as GSUs financial statements and the adequacy of GSU's intemal controls. He committee met, together and separately, with GSUs intemal auditors and independent public accountants, without management present, to discuss the results of their audits, their evaluation of GSUs internal controls, and the overall quality of GSUs fmancial reporting. He meetings also were designed to facilitate and encourage any private communication between the committee and the intemal auditors or independent public accountants. BISMARK A. STEINHAGEN Chairman, Audit Committee
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INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directors of Gulf States Utilities Company We have audited the accompanying balance sheets of Gulf States Utilities Company as of December 31,1993 and 1992 and the related statements of income, retained earmngs and paid in capital and cash flows for each of the three years in the period ended December 31, 1993. These fmancial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these fmancial , statements based on our audits. i We conducted our audits in accordance with generally accepted auditing standards. Those standards { require that we plan and perform the audit to obtain reasonable assurance about whether the fmancial statements are free of material misstatement. An audit includes examuung, on a test basis, evidence supporting the amounts 1 and disclosures in the fmancial statements. An audit also includes assessing the accounting principles used and significant estunates made by management, as well as evaluating the overall fmancial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 12 to the fmancial statements, the common stock of the Company was acquired on December 31,1993. In our opinion, the fmancial statements referred to above present fairly, in all material respects, the fmancial position of Gulf States Utilities Company as of December 31,1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31,1993 in conformity with generally accepted accounting principles. As discussed in Note 2 to the fmancial statements, the net amount of capitalized costs for the Company's River Bend Unit I Nuclear Generating Plant (River Bend) exceed those costs currently being recovered through rates. At December 31, 1993, approximately $747 million is not currently being recovered through rates. If current regulatory and court orders are not modified, a write-off of all or a portion of such costs may be required. Additionally, as discussed in Note 2 to the financial statements, other rate-related contingencies exist which may result in a refund of revenues previously collected. The extent of such write-off of River Bend costs or refund of l revenues previously collected, if any, will not be determined until appropriate rate proceedmgs and court appeals l have been concluded. Accordingly, no provision for write-off or refund has been recorded in the accompanying fmancial statements. As discussed in Note 8 to the financial statements, civil actions have been initiated agamst the Company to, among other things, recover the co-owner's investment in River Bend and to annul the River Bend Joint Ownership Participation and Operatmg Agreement. The ultimate outcome of these proceedmgs cannot presently be determined. Accordingly, no provision for any liability that may result from the ultimate resolution of these proceedings has been recorded in the accompanying fmancial statements. As discussed in Note 3 to the fmancial statements, in 1993, the Company adopted Statement of Financial Accounting Standards No.109, " Accounting for Income Taxes", and elected to restate the 1991 and 1992 financial statements for its effects. As discussed in Note 10 to the financial statements, the Company adopted Statement of Financial Accounting Standards No.106, " Employers' Accounting for Postretirement Benefits Other Than Pensions", as of January 1,1993. As discussed in Note I to the fmancial statements, as of January 1,1993, the Company began accruing revenues for energy delivered to customers but not yet billed. As discussed in Note 1 to the fmancial statements, the Company changed its accounting for power plant materials and supplies as of January 1,1992. COOPERS & LYBRAND Houston, Texas February 11,1994
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l GULF STATES UTII.JTIES COMPANY BALANCE SHEE'I5 ASSETS Da== tier 31, 1993 1992 (In Thansands) Utility Plant (Notes 1 and 2):
$6,825,989 $6,770,017 ,
Electric 42,786 41,160 -l Natural gas 75,689 72,292 Steam products , 86,039 87,214 ! Property under capital leases (Note 9) 50,080 32,305 j Construction workin progress Nuclean fuel under capital ienses (Note 9) 94,828 '106,565
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Total - 7,175,411 7,109,553 , IAss - accumulated depreciation and amortazation 2,323,804 2,172,719 ! 4,851,607 4,936,834 Utility plant - net Other Property and Investments ! Decomminaioning trust fund (Note 8) 17,873 14,102 Other - at cost (less ace ==datad depreciation) 29,360 36,225' 47,233 50,327 ; Total Current Assets Cash and cash equivalents (Note 1):
.720 Cash 3,012 Temporary cash investments - at cost, 258,337 197,021 -l which approximatas market '
Totalcash and cash equivalents 261,349 197,741 Accounts receivsble: ! Customer (less allowance for doubtfhi amounts of
$2.4 million in 1993 and $3,0 milhon in 1992) 117,369 124,214 4 18,371 18,405 Other Accrued unbilled revemmes (Note 1) 32,572 - ']
5,883 ' - ; Deferred fuel costs (Note 1) Fuelinventory(Note 1) 23,448 21,159 { Matenals and supplies - at average cost 86,831 ~ - 86,972 i 90,775 85,473 i Rate deferrals (Note 2) 28,425 91,731 -! A~ '-'ad deferred income taxes (Note 3) 48,948 38,314 l Pi.,p.ys ;; and other 713,971 664,009 Total . I Deferred Debits and Other Assets i 638,015 728,790 Rate deferrals (Note 2) - ' SFAS 109 regulatory asset - net (Note 3) 432,411 357,253 Long-term receivables 218,079 191,269 .l
- Unamortazedloss on reacquared debt 70,970 67,074
-193,490 168,891 Other 1,552,965 1,513,277 i Total
$7,165,776 $7.164,447 TOTAL i
i See Notes to Financial Statements
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_ _ _. _ . . _ .- _ _ . _ _ _ . . ~ _ _ __ . __ _ 1 GULF STATES UTILITIES COMPANY BALANCE SifEE15 CAPITALIZATION AND LIABILITIES I December 31, 1993 1992 (la h ds) Capitalization: Common stock, no par value, authonzed 200,000,000 shares; issued and e?' Mag 100 shares at December 31,1993 (Notes 5 and 12) $114,055 $1,200,923 1,152,304 67,316 Paid-in capital 666,401 631,462 Retained earmnas (Notes 3 and 7) : Total common shareholder's equity 1,932,760 1,899,701 150,000 - Preference stock (Note 5) Prefened stock (Note 5): [ Without sinkingihnd 136,444 136,444-101,004 269,387 With sinkingihnd 2,368.639 2,374,458 Long-term debt (Note 6) 4,688,847 4,679,990 Total Other Noncurrent Liabilities: 152,359 154,923 i Obliganons under capital leases (Note 9) 47,107 18,865 Other (Note 8) 199,466 173,788 Total i Current Liabilities: Currently matunng long-term debt 425 160,425 Accounts payable: Associated companies (Note 11) 2,745 - 109,840 101,513 Other Customer deposits 21,958 21,152 22,856 19,092. Taxes accrued
$9,516 62,013 Interest accrued !
Nuclear refueling reserve 22,356 10,083 36,954
~
Deferred fuel cost (Note 1) Obligations under capitallesses (Note 9) . 41,713 51,688 , 97,203 66,534 Other 378,612 529,454 Total Defened Credits: 1,252,295 1,192,182 Am==i='d defened innnme taxes (Note 3) ' 94,455 94,690 A9 =? - 2 defened investment tax credits (Note 3) Defened River Bend finance charges 106,765 131,123 445,336 363,220 l Other 1,898,851 1,781,215 Total Commitments and Contingencies (Notes 2,8, and 9)
$7,165,776 $7,164,447 TOTAL See Notes to Financial Stalwata 1
I
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GULF STATES UTILITIES COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31, l 1993 1992 1991 (la Thousands) Operating Activities: Net income $78,862 5133,848 $112,030 l Noncash items included in net income: Extraordinary items 1,259 9,597 361 Cumulative effect of accounting changes (10,660) (4,032) - - Change in rate deferrals 61,115 52,946 38,236 Depreciation and decommissioning 190,405 188,393 187,936 Deferred income taxes and investment tax credits 41,302 50,238 43,504 Allowance for equity funds used during construction (726) (1,226) (608) Changes in working capital: , 4,373 (12,503) l Receivables 6,879 Fuelinventory (2,289) (4,152) 10,422 Accounts payable 11,072 (1,171) (6,912) Taxes accrued 3,764 (2,634) 753 Interest accrued (2,497) (15,276) 3,211 . Other working capital accounts (9,582) (13,675) 12,602 Decommissioning trust contributions 2,710 5,912 2,315 Purchased power settlement (169,300) (20,797) 12,565 l Other 53,121 (34,816) 29,833 Net cash flow provided by operating activities 255,435 347,528 433,745 Investing Activities: Construction expenditures (115,481) (97,377) (87,470) ' Proceeds received from sale of property - 12,460 - 1 l Allowana: for equity funds used during construction 726 1,226 608 Nuclear fuelpurchases s.'I8) - - Proceeds from sale /le==rhaelr of nuclear fuel 2,) N - - Other property, investments and escrow account a,L1 13,091 10,070 Net cash flow used in investing activities (108,834) (70,600) (76,792) Financing Activities: ! l Proceeds fromissuance of: First mortgage bonds 338,379 1,185,260 - i Preference stock 146,625 - - Other long-term debt 21,440 48,%$ 200,000 Retirement c5: First mortgage bcnds (360,199) (1,067,717) (87,320) Other long-term debt (18,398) (127,161) (245,762) Redemption of preferred and preference stock (174,841) (174,226) - Dividends paid: Preferred and preference stock (35,999) (237,369) (127,398) Net cash flow used in financing activities (82,993) (372,248) (260,480) Net increase (decrease) in cash and cash equivalents 63,608 - (95,320) 96,473 Cash and cash equivalents at beginning of period 197,741 293,061 196,588 l Cash and cash equivalents at end of period $261.349 $197,741 $293,061 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest - net of amount capitalized $197,058 $239,607 $227,306 i Income taxes $15,600 $8,000 $5,700 . Noncash imesting and financing activities: I' C pitallease obligations incuned $17,143 $87,022 513,958 See Notes to Financial Statements.
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GULF STATES UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES I Liquidity is important to GSU due to the capital intensive nature of our business, which requires large investments in long-lived assets However, large capital expenditures for the construction of new generating
-l capacity are not currently planned GSU requires significant capital resources for the periodic maturity of certam series of debt, preferred stock, and preference stock. Net cash flow from operations totaled $255 million, ,
5348 million, and $434 million in 1993,1992, and 1991, respectively. Cash flow from operations in 1993 includes nonrecurring items related to the payment of $169.3 million as a result of the settlement of a purchased power ;
- dispute. In recent years, this cash flow, supplemented by cash on hand, has been sufficie:W.to most substantially al!
investing and financing requirements, including capital expenditures, preferred and preference divulands, and debt / preferred stock maturities. GSUs ability to fund these capital requirements with cash from operations, results ! in part from our continued efforts to reduce costs as well as collecuans under our River Bend rate phase-in plan of i previously deferred amounts. (In the income statement, these revenue collections are offset by the amortization of previously deferred costs, therefore, there is no effect on net income.) See Note 2,' incorporated herein by reference, ' for additional information on GSUs rate phase-in plan. Further, GSU has the ability to meet future capital requirements through future debt and preference stock issuances, as discussed below. See Note 8, irworpmed herein by reference, for additional information on GSUs capital and refinancing requirements in 1994 through ' 1996. Further, in order to take advantage of lower interest and dividend rates, GSU contmues to renn=ce high-cost debt and preferred stock prior to maturity. I In February 1994, GSU paid to Entergy Corporation a $100 million cash dividend on common stock. Prior to the February 1994 dividend payment, GSU had not paid a common dividend since June 1986. Earnings coverage tests (which are impacted by the inclusion of the cumulative effect of the change in , accounting principle for accruing unbilled revenues discussed in Note 1) and bondable property additions limit the ' amount of first mortgage bonds and preferred stock that GSU can issue. Based on the most restrictive applicable tests as of D-nbcr 31,1993, and an assumed annual interest rate of 8%, GSU could have issued $425 million of additional first mortgage bonds As of D= *= 31,1993, GSU was unabl: to issue any additional preferred j stock. There are no limitations on the issuance of preference stock. GSU has the conditional ability to issue first mortgage bonds agamst the retirement of first mortgage bonds without satisfying an earnmas coverage test. See Notes 5 and 6, incorporated herein by reference, for information on GSUs n=% activities and Note 4, incorporated herein by reference, for information on GSUs short-term borrowings and lines of credit. j See Notes 2 and 8 regardmg River Bend rate appeals and litigatson with Cajun. Substantial write-offs or charges resulting from adverse rulings in these matters could adversely affect GSUs ability to continue to pay . dividends and obtain financing, which could in turn affect GSUs liouidity. i 4 i
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l GULF STATES UTILITIES COMPANY STATEMENTS OF INCOME For the Years Ended December 31, 1993 1992 1991 (In Thousands) Operating Revenues (Notes 1 and 2): Electric $1,747,961 $1,694,536 $1,623,959 Natural gas 32,466 28,523 31,858 Steam products 47,193 50,315 46,418 Total 1,827,620 1,773,374 1,702,235 Operating Expenses: Operation: Fuel for electric generation and fuel-related expenses $38,887 471,873 446,543 Purchased power 134,936 136,716 161,374 Gas purchased for resale 20,529 16,563 19,290 Other 324,617 277,385 248,302 Maintenance 144,766 161,080 142,098 Depreciation and decommissioning 190,405 188,393 187,936 Taxes other than income taxes 95,742 91,740 88,402 Income taxes (Note 3) 46.007 38,058 35,084 Amortization of rate deferrals (Note 2) 61,115 52,946 38,236 Total 1,557,004 1,434,754 1,367,265 OperatingIncome 270,616 338,620 334,970 OtherIncome: Allowance for equity funds used during construction 726 1,226 608 Mi-11==n - net 19,996 64,837 49,947 Income taxes (Note 3) (12,009) (17,801) (13,166) Total 8,713 48,262 37,389 Interest Charges: Interest on long-tenn debt 202,235 239,341 234,418 Other interest - net 8,364 9,075 26,038 Allowance for borrowed funds used during construction (731) (947) (488) Total 209,868 247,469 259,968 Income before Extraordinary Items and the Cumulative Effect of Accounting Changes 69,461 139,413 112,391 Extraordinary Items (net ofincome taxes) (Note 1) (1,259) (9,597) (361) Cumulative Effect of Accounting Changes 10,660 4,032 - (net ofincome taxes)(Note 1) Netincome 78,862 133,848 112,030 Preferred and Preference Stock Disidend Requirements 35,581 49,702 63,070 Earnings Applicable to Common Stock $43,281 $84,146 $48,960 See Notes to Financial Statements.
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GULF STATES UTILITIES COMPANY STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL For the Years Ended December 31, 1993 1992 1991 (In Thousands) Retamed Earnings, January 1 (Note 3) $631,462 $667,893 $622,026 78,862 133,848 112,030 Add - Net income 710,324 801,741- 734,056 Total Deduct: Dividends declared: Preferred and preference stock 35,581 158,547 66,163 Preferred and preference stock redemption 8,342 11,732 - 43,923 170,279 66,163 Total Retamed Earmngs, December 31 (Note 7) 5666,401 $631,462 5667,893 Paid-in Capital, January 1 $67,316 $73,993 $22,237 Issuance of 100 shares of no par common stock with a stated value of $114,055 net of the retirement of 114,055,065 shares ofno par common stock (Notes 5 and 12) 1,086,868 - - Issuance of 6,000,000 shares of common stock in the settlement of purchased power dispute
- - 51,775 Loss on reacquisition of ,
preferred and preference stock (1,880) (6,677) (19) Paid-in Capital, December 31 $1,152,304 567,316 $73,993 See Notes to Financial Statements. i
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GULF STATES UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income decreased in 1993 due prunarily to Merger-related charges recorded at year-end. Also contributing to the decrease was a rate refund and one-time credit resulting from a November 1993 rate settlement (see Note 2, incorporated herein by reference), the effect of implementing SFAS 106 (see Note 10, incorporated herein by reference), and the impact in 1992 of reducing a purchased power settlement liability. He decrease in net income was partially offset by the one-time recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1, incorporated herein by reference) and its ongoing effects Effective January 1,1993, GSU began accruing as revenues the charges for energy delivered to customers but not yet billed. Electric and gas revenues were previously recorded on a cycle-billing basis. Excluding the above mentioned items, net income for 1993 would have been $139.2 million and net income for 1992 would have been $109.6 million. - His increase of $29.6 million is due primarily to increased retail energy sales and decreased interest expense Net income increased in 1992 due pnmarily to increased revenues, reduced interest charges, and reductions . to a previously recorded purchased power settlement liability. l Significant factors affecting the results of operations and causing vanances between the > tars 1993 and 1992, and 1992 and 1991 are discussed under " Revenues and Sales," " Expenses," and "Other" below. Revenues and Sstes Operating revenues were higher in 1993 due primarily to increased residential and commercial energy sales resulting primarily from a return to more normal weather as compared to milder weather in 1992, and increased fuel adjustment revenues and collections of previously deferred River Bend costs, neither of which affects net income. nese increases were partially offset by a refund and one-time credit to Texas retail customers resulting from a rate settlement. Operating revenues were higher in 1992 due prunarily to increased fuel adjustment revenues and increased I collections of previously deferred River Bend costs and, to a lesser extent, to increased energy sales, primarily l industrial. Also contributing to the 1992 increase was the fact that revenues were lower in 1991 due in part to a j
$24.1 million refund provision ordered by the LPSC.
See " Selected Financial Data - Five-Year Comparison," incorporated herein by reference, following the notes, for information on operating revenues by source and K%H sales. EKDenses Fuel for electric generation and fuel-related expenses increased in 1993 due primarily to a higher average per unit cost for gas resulting from increased gas prices in 1993 and increased generation, primarily River Bend. Fuel expense in 1992 increased due to higher average fuel cost, offset partially by reduced generation resulting from . a scheduled refueling outage at River Bend in the first half of 1992. Purchased power expense decreased in 1992, despite increased purchases, due to the conclusion in June 1991 of capacity costs associated with the buyback of a portion of Cajun's share of River Bend generation. 1 154 -
i l l GULF STATES UTILITIES COMPANY i MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS l RESULTS OF OPERATIONS -(Concluded) i Other operatmg exgres increased in 1993 due pnmarily to 552.3 million of Merger-related charges for l fmancial investment advisor fees and early retirement and other severance plan provisions. Charges for other ! postemployment bene 6ts increased resulting from the adoption of SFAS 106. i I Other operatmg and maintenance expenses increased in 1992 due to costs in excess of the normal eighteen month outage accrual resulting from an ** refueling outage at River Bend from March to September. j Further, amoruzation of rate deferrals increased in 1993 and 1992 due to increased amortization of amounts in accordance with the River Bend phase-in plan. i Qlhtt i Other miscellaneous income decreased in 1993 and increased in 1992 due primarily to the 1992 effect of I reducing a liability relating to a purchased power ="le In wh with the settlement, the liability was ; based upon the price of GSU common stock as of the November 1991 settlement and was subsequently reduced as ; the price of GSU common stock increased. Interest expense declined in 1993 and 1992 as a result of the continued 1 refinancing of high-cost debt during 1993,1992, and 1991, i I I t
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l GULF STATES UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Enterry Corporation-GSU Mercer On December 31,1993, Entergy Corporation completed the Merger with GSU. For further information, see Note 12, incorporated herein by reference. Competition GSU welcomes competition in the electric energy business and believes that a more competitive environment should benefit our customers, employees, and shareholders of Entergy Corporation. We also recognize that competition presents us with many challenges, and we have identified the fcilowing as our major competitive challenges: Retail and Wholesale Rate Issues increasing competition in the utility industry brings an increased need to stabilize or reduce rates. In connection with the Merger, GSU agreed with the LPSC and PUCT to a five-year Rate Cap on retail electric rates, and to pass through to retail customers the fuel savings and a certain percentage of the nonfuel savings created by the Merger. GSU's base rates will be reviewed by the LPSC during the first post-Merger earnmgs analysis, scheduled for mid-1994, for reasonableness of its return on equity. The PUCT will review GSU's base rates in accordance with its Merger approval plan in mid-1994 also. For further information on Merger-related rate agreements, see Note 2, beorporated herein by reference. Cogeneration projects developed or considered by certain industrial customers over the last several years have resulted in GSU developing and securmg approval of rates lower than the rates previously approved by the PUCT and LPSC for such industrial customers. Such rates are designed to retain such customers, and to compete for and develop new loads, and do not presently recover GSU's full cost of senice. The pricing agreements at non-full cost of service based rates fully recover all related costs but provide only a mmunal return. Substantially all of such pricing agreements expire no later than 1997. During 1993, KWH sales to industrial customers at less than full cost of senice, which make up approximately 26% of the total industrial class, increased 8% Sales to the remaining industrial customers decreased 3% Retail wheeling, a major industry issue which may require utilities to " wheel" or move power from third parties to their own retail customers, is evohing gradually. As a result, the retail market could become more competitive. In the wholesale rate area, FERC approved in 1992, with certain modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power, Inc. to sell wholesale power at market-based rates and to proside to electric utilities "open access" to the System's transmission system (subject to certain requirements). GSU w2s later added to this filing. Various intervenors in the proceedmg filed petitions for resiew with the United States Court of Appeals for the District of Columbia Circuit. FERC's order, once it takes effect, will increase marketing opportunities for GSU, but will also expose GSU to the risk ofloss ofload or reduced revenues due to competition with alternative suppliers.
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GULF STATES UTILITIES COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS -(Concluded) In light of these rate issues, GSU is aggressively reducing costs to avoid potential earnmgs crosions that might result as well as to successfully compete by becoming a low-cost producer. To muunuze future costs, GSU is currently working with the PUCT regarding integrated resource planning. Integrated resource plannmg, or least cost planning, includes demand-side measures such as customer energy conservation and supply-side measures such as more efficient power plants. nese measures are designed to delay the building of new power plants for the next 20 years. De Enerav Policy Act of 1992 he Energy Policy Act of 1992 (Energy Act) is changing the tmnsmission and distribution of electricity. This act encourages competition and affords us the opportunities, and the risks, associated with an open and more competitive market environment. He Energy Act increases competition in the wholesale energy market through the creation of exempt wholesale generators (EWGs). The Energy Act also gives FERC the authority to order investor-owned utilities to provide transmission access to or for other utilities, including EWGs. Deregulated Portion of River Bend As of December 31,1993, GSU has not recovered a significant amount ofits investment or received any retum associated with the portion of Riser Bend included in the deregulated asset plan in Louisiana and the portion of River Bend placed in abeyance as part of the Texas rate order which went into effect in July 1988. See Note 2, incorporated herein by reference, for further information. Future earnmgs will continue to be limited as long as the limited recovery of the investment and lack of return continues. For the year ended December 31,1993, GSU recorded revenues resulting from the sale of electricity from the deregulated asset plan of approxunately $35.3 million. Operations and maintenance expenses, including fuel, were approximately $33.3 million, and depreciation expense associated with the deregulated asset plan investment was approximately $16.8 million for the year ended December 31,1993. For the year ended December 31,1993, GSU recorded nonfuel revenue of $31.5 million (included in the 535.3 million of total deregulated asset plan revenue discussed above) which, absent the deregulated asset plan, would not have been realized. He operations and maintenance expenses and depreciation expense allocated to the deregulated asset plan as detailed above, however, would have been incurred at River Bend with or without the deregulated asset plan. Future impact of the deregulated asset plan on GSUs results of operations and fmancial position will depend on River Bend's future operating costs, the unit's efficiency and availability, and the future market for energy over the remining life of the unit. GSU anticipates based on current estunates of the factors discussed above, that future revenues from the deregulated asset plan will fully recover all related costs. Litiention and Rerulstory Proceedines See Note 2, incorporated herein by reference, for information on the possibility of material adverse effects on GSU's fmancial condition resulting from substantial write-offs and/or refunds in connection with outstanding appeals and remands regarding approximately $1.4 billion of abeyed River Bend plant costs and approximately
$187 million of Texas retail jurisdiction deferred River Bend operating and carrying costs. See Note 8, incorporated herein by reference, for information regarding litigation with Cajun conceming Cajun's ownership interest in River Bend and the possible material adverse effects on GSUs financial condition in the event that GSU is ultimately unsuccessful in this litigation, including a possible filing under the bankruptcy laws.
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GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS NOTE 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES GSU maintains accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications. Revenues and Fuel Costs Prior to January 1,1993, GSU recograzed electric and gas revenues when billed. To proside a better rnatchino of revenues and expenses, effective January 1,1993, GSU adopted a change in accountmg principle to provide for accrual of the nonfuel portion of estunated unbilled revenues. The cumulative effect of this accounting change as of January 1,1993 for the Texas retailjurisdiction, wholesale jurisdiction, and gas department increased 1993 net income by $10.7 million, net of related income taxes of $6.9 million. Had this new accounting method been in effect during prior years, net income before the cumv.ative effect would not have been materially different from that shown in the accompanying financial statements. In the Louisiana retail jurisdiction, the LPSC issued a rate order, effective March 1,1991, which required GSU to defer the initial effect when and if GSU changed its accounting for unbilled revenue. The amount of unbilled revenues in the louisiana jurisdiction was $16.6 million at January 1,1993. Because of the LPSC rate order, GSU recorded a deferred credit of $16.6 million. There was no cumulative effect of the change recorded in operations. If the LPSC order were to be revised, the net incoine effect would be $10.1 million, net of related income taxes of $6.5 million. Changes in unbilled revenues in the Louisiana retail jurisdiction subsequent to January 1,1993 have been recorded in operations. GSUs wholesale and Louisiana retail rate schedules include fuel adjustment clauses that allow deferral of fuel costs until such costs are reflected in the related revenues. GSU's Texas retail rate schedules include a fixed fuel factor approved by the PUCT, which remams the same until changed as part of a general rate case or fuel reconciliation, or until the PUCT orders a reconciliation for any over or under collections of fuel costs. Reconcilable fuel and purchased power costs in excess of those included in base rates or recovered through fuel adjustment clauses are deferred (or accrued) until such costs are billed (or credited) to customers. Utility Plant Utility plant is stated at original .:ost. He original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is .harged to accumulated depreciation. Maint=nm, repairs, and minor replacement costs are charged to operatirg expenses. Substantially all of GSU's utility plant is subject to the lien of its mortgage indenture. AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases utility plant and earmngs, only recovery of prudently incurred costs are realized in cash through depreciation provisions included in rates allowed by regulators. GSU's AFUDC rates were as follows: January 1,1991 - March 31,1991 11.50 % April 1,1991 - March 31,1992 11.75 % April 1,1992 - March 31,1993 10.75 % April 1,1993 - December 31,1993 10.50 %
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GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) l l Depreciation is computed on the straight-line basis at rates based on the estunated service lives and cost of removal of the various classes of property. Depreciation provisions on average depreciable property approxunated 2.7% in 1993,1992, and 1991. Jointiv-Owned Facilities As of December 31, 1993, GSU owned undivided interests in three jointly-owned electric generating facilities as detailed below: 1 I Total ] Fuel Megawatt Accumulated j Csonbility Ownershio Investment Generatine Stations Tys Deoreciation (In Thousands) River Bend Unit 1 Nuclear 931 70 % $3,056,464 $545,740 Roy S. Nelson Unit 6 Coal 550 70 % $ 389,915 5134,877 Big Cajun 2 Unit 3 Coal 540 42 % $ 219,911 5 68,150 GSU's share of operations and maintenance expense related te the jointly-owned units is included in operating expenses. See Note 8 for information regarding unpaid amounts by Cajun for their share of River Bend costs. l Lncome Taxes l GSU and its subsidiaries file a consolidated federal income tax return. Income taxes are allocated to GSU in proportion to its contribution to the consolidated taxable income subject to the limitations for recognition of net operating loss carryforwards and investment tax credits. Deferred taxes are recorded for all temporary differences between book and taxable income. Investment tax credits are deferred and amoruzed based upon the average useful { life of the related property in accordance with rate treatment. I Inventories GSU's fuel inventories are comprised of fuel oil and natural gas, valued at weighted average cost, and coal, valued at last-in, first-out cost. Accountine for Power Plant Materials and Sucolies During the first quarter of 1992, accounting procedures were changed to include in inventory, power plant materials and supplies previously expensed or capitalized as plant in service. GSU believed this change provided a better matching of costs with related revenues. The change resulted from recommenAntions during audits by FERC and the LPSC, in addition to a general change in industry practice. De pro forma effect of retroactive application on any period prior to 1992 was not determmable as, prior to this change, GSU did not perform the physical inventory counts necessary to determme inventory balances in prior periods. He effect of the change was to increase materials and supplies by $76.6 million, of which S41.1 million associated with GSU's Te;as and Louisiana retail jurisdictions was deferred, and to decrease amounts previously capitahzed, primarily plant in service, by $29 million. Amounts deferred for the Louisiana retail jurisdiction are currently being amortized to income over approximately seven years, through February 1998, while amounts deferred for the Texas retail jurisdiction will be amortized to income in future years. He cumulative effect of this accounting change as of January 1,1992, which relates to the operations on which GSU has discontmued regulatory accounting principles, amounted to $6.5 million before the related income tax effect of $2.5 million.
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5 J GULF STATES UTILITIES COMPANY s NOTES TO FINANCIAL STATEMENTS -(Continued) Rencauired Debt ne premiums and costs associated with reacquired debt are amortized over the life of the related new issuances for the portions of the business accounted for in accordance with generally accepted accounting principles for regulated enterprises. During 1992, GSU extinguished over $1 billion of long-term debt through refinancings. A loss of $81.8 million was recorded associated with the extinguished debt of which $67.2 million of the loss was deferred,
- representing the portion of GSU's operations allocable to the Texas and Louisiana retail jurisdictions, and began to amortize that amount over the life of the new debt sold to retire the existing debt. A loss of $9.6 million, net of -
related income taxes of $5.0 million, was charged to income in 1992 as an extraordmary item. Further, refmancings oflong-term debt during 1993 resulted in an extraordmary loss of $1.3 million, net of S.7 million of related taxes. Cash and Cash Eauivalents GSU considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. SFAS 101 SFAS No.101, " Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71," specifies how an enterprise that ceases to meet the criteria for application of SFAS No. 71,
" Accounting for the Effects of Certain Types of Regulation," to all or part ofits operations shouti report that event in its financial statements. GSU discontinued regulatory accounting principles for the wholesale jurisdiction and steam department, and the Louisiana deregulated portion of River Bend, during 1989 and 1991, respectively.
Fair Value Disclosure ne esumated fair value of GSU's significant financial instruments have been determmed using available market information and appropriate valuation methodologies. However, considerable judgment is required in developing the estunates of fair value. Herefore, estunates are not necessarily indicative of the amounts that GSU could realize in a current market exchange. In addition, gains or losses realized on financial instruments may be reflected in future rates and not accrue to the benefit of stockholders. GSU considers the carrying amounts of financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. See Notes 5,6, and 8 for additional fair value disclosure. NOTE 2. RATE AND REGULATORY MATTERS River Bend In May 1988, the PUCT granted GSU a permanent increase in annual revenues of $59.9 million resulting from the inclusion in rate base of approximately $1.6 billion of company-wide River Bend plant investment and approximately $182 million of related Texas retailjurisdiction deferred River Bend costs (Allowed Deferrals). In addition, the PUCT disallowed as imprudent $63.5 million of company-wide River Bend plant costs and placed in abeyance, with no finding of prudency, approximately $1.4 billion of company-wide River Bend plant investment
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GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) j i and approximately $157 million of Texas retailjurisdiction deferred River Bend operstmg and carrymg costs. The l PUCT affirmed that the ultimate rate treatment of such amounts would be subject to future demonstration of the prudency of such costs. GSU and intervening panies appealed this order (Rate Appeal) and GSU filed a separate rate case asking that the abeyed River Bend plant costs be found prudent (Separate Rate Case). Intervemng parnes i filed suit in district court to prohibit the Separate Rate Case. The district court's decision was ulumately appealed i to the Texas Supreme Court which ruled in 1990 that the prudence of the purported abeyed costs could not be i relitigated in a separate rate preding Further, the Texas Supreme Court's decision stated that all issues relatmg I to the merits of the original order of the PUCT, including the prudence of all River Bend-related costs, should be addressed in the Rate Appeal. l In October 1991, the district court in the Rate Appeal issued an order holding that, while it was clear the PUCT made an error in assuming it could set aside $1.4 billion of the total costs of River Bend and consider them in a later prMag. the PUCT, nevertheless, found that GSU had not met its burden of proof related to the ! amounts placed in abeyance "Ihe court also ruled that the Allowed Deferrals should not be included in rate base t under a 1991 decision regarding El Paso Electric Company's sinular deferred costs (El Paso Case). 'Ihe coun further stated that the PUCT erred in reducing GSU's deferred costs by $1.50 for each $1.00 of revenue collected under the mterun rate increases authorized in 1987 and 1988. The court renundad the case to the PUCT with i mstructions as to the proper handling of the Allowed Deferrals. GSU's motion for rehearms was denied,and in i December 1991, GSU filed an appeal of the October 1991 district court order. The PUCT also appealed the ! October 1991 district court order, which served to supersede the district court's judgment, readsrmg it unenforceable under Texas law. ! In August 1992, the court of appeals in the El Paso Case handad down its second opinion on rehearms modtfymg its previous opinion on deferred accounting. The court's second opinion concluded that the PUCT may j lawfully defer operatmg and maintenance costs and subsequently include them in rate base, but that the Public j Utility Regulatory Act prohibits such rate base treatment for deferred carrying costs. The court stated, however, its opinion would not preclude the recovery of deferred carrying costs. The August 1992 court of appeals opinion was : appealed to the Texas Supreme Court where arguments were heard in September 1993. The matter is paading i In September 1993, the Texas 1hird District Court of Appeals (the Third District Court) remanded the . October 1991 district court decision to the PUCT "to reexanune the record evidence to #wcr extent necessary to { render a fmal order supported by substantial evidence and not inconsistent with our opinian " The Third Distnct l Court specifically addressed the PUCTs treatment of certain costs, statmg that the UCTs order was not based on ! substantial evidence The T1urd Distnct Court also applied its most recesat ruhng in the El Paso Case to the ! deferred costs W=i with River Bend. However, the Third District Court cautioned the PUCT to confine its i deliberations to the evidence addressed in the original rate case. Certain parties to the case have indicated their position that, on romand, the PUCT may change its original order only with respect to matters specifically discussed ; by the Third District Court which, if allowed, would increase GSU's allowed River Bend investment, net of i accumulated depreciation and related taxes, by approximately $48 million as of December 31,1993. GSU believes , that under the Third District Court's decision, the PUCT would be free to reconsider any aspect of its order ; conceming the abeyed $1.4 billion River Bend investment. GSU has filed a motion for rehearmg asking the Third - l District Court to modify its order so as to pennit the PUCT to take additional evidence on remand The PUCT and i other parties have also moved for reheanng on various grounds. The lhtrd Distnct Court has not yet ruled on any l of these motions.' : As of December 31,1993, the River Bend plant costs disallowed for retail ratemakmg purposes in Texas, and the River Bend plant costs held in abeyance and the related cost deferrals totaled (net of taxes) approximately j
$14 million, $300 million (both net of depreciation), and $171 million, respectively. Allowed Deferrals were 1 approximately $95 million, net of taxes and amortization, as of December 31,1993. GSU estimates it has collected '!
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l l GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) approximately $139 million of revenues as of December 31, 1993, as a result of the originally ordered rate treatment of these deferred costs. However, if the PUCT adopts the most recent decision in the El Paso Case, the possible refunds approximate $28 million as a result of the inclusion of deferred carrying costs in rate base for the period July 1988 through December 1990. However, if the PUCT reverses its decision to reduce GSU's deferred costs by $1.50 for each $1.00 of revenue collected under the interim rate increases authorized in 1987 and 1988, the potential refund of amounts described above could be reduced by an amount ranging from $7 mi!! ion to $19 million. No assurance can be given as to the timing or outcome of the remands or appeals described above. Pending further developments in these cases, GSU has made no write-offs for the River Bend-related costs. Management believes, based on advice from Clark, Romas & Winters, a Professional Corporation, legal counsel of record in the Rate Appeal, that it is reasonably possible that the case will be remanded to the PUCT, and the PUCT will be allowed to rule on the prudence of the abeyed River Bend plant costs. Rate Caps imposed by the PUCTs regulatory approval of the Merger could result in GSU being unable to use the full amount of a favorable decision to immediately increase rates; however, a favorable decision could permit some increases and/or limit or prevent decreases during the period the Rate Caps are in effect. At this time, management and legal counsel are unable to predict the amount, if any, of the abeyed and previously disallowed River Bend plant costs that ultimately may be disallowed by the PUCT. A net of tax write-off as of December 31,1993, of up to $314 million could be required based on the PUCTs ultimate ruling. In prior proceedmgs, the PUCT has held that the original cost of nuclear power plants will be included in rates to the extent those costs were prudently incurred. Based upon the PUCTs prior decisions, management believes that its River Bend construction costs were prudently incurred and that it is reasonably possible that it will recover in rate base, or otherwise through means such as a deregulated asset plan, all or substantially all of the abeyed River Bend plant costs. However, management also recognizes that it is reasonably possible that not all of the abeyed River Bend plant costs may ultimately be recovered. As part of its direct case in the Separate Rate Case, GSU filed a cost reconciliation study prepared by Sandlin Associates, management consultants with expenise in the cost analysis of nuclear power plants, which supports the reasonableness of the River Bend costs held in abeyance by the PUCT. This reconciliation study determined that approximately 82% of the River Bend cost increate above the amount included by the PUCT in rate base was a result of changes in federal nuclear safety requirements and provided other support for the remamder of the abeyed amounts. Here have been four other rate proceedings in Texas involving nuclear power plants. Investment in the plants ultimately disallowed ranged from 0% to 15% Each case was unique, and the disallowances in each were made on a case-by-case basis for different reasons. Appeals of most, if not all, of these PUCT decisions are currently pending.
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GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) The following factors support management's position that a loss U-: =5=y requinns accrual has not occurred, and its belief that all, or substantially all, of the abeyed plant costs will ultunately be recovered,
- 1. The $1.4 billion of abeyed River Bend plant costs have never been ruled imprudent and disallowed by the PUCT.
- 2. Sandlin Associates' analysis which supports the prudence of substantially all of the abeyed construction costs.
- 3. Historical inclusion by the PUCT of prudent construction costs in rate base. ;
- 4. 'Ihe analysis of GSU's internal legal staff, which has considerable experience in Texas rate case l litigation. )
I Additionally, management believes, based on advice from Clark, 'Ihomas & Winters, a Professional Corporation, legal counsel of record in the Rate Appeal, that it is probable that the deferred costs will be allowed. However, assuming the August 1992 court of appeals' opinion in the El Paso Case is upheld and applied to GSU .I and the deferred River Bend costs currently held in abeyance are not allowed to be recovered in rates as allowable l costs, a net of tax write-off of up to $171 million could be reqmred In addition, future revenues based upon the I deferred costs previously allowed is rate base could also be lost and no assurance can be given as to whether or not ) i refunds (up to $28 million as of December 31,1993) of revenue received based upon such deferred costs prevmusly recorded will be required. See Note 12 for the accounting treatment of preacquisitie e-: -5=b=, includmg a River Bend wnte-down. Mermer-Related Rate Anreements The LPSC and the PUCT approved separate regulatory proposals that include the following elements (1)a five-year Rate Cap on GSU's retail electric base rates in the respective states, except for force majeure (defmed to include, among other things, war, natural catastrophes, and high inflation); (2) a provision for passing through to retail customers in the respective states the juriuMHam! portion of the fuel savings created by the ' Merger; and (3) a rnehanism for trackmg nonfuel operation and mairennam savings created by the Merger. 'Ihe LPSC regulatory plan provides that such nonfuel savings will be shared 60% by the shareholder and 40% by ratepayers during the eight years followmg the Merger. 'Ihe LPSC plan regeres regulatory filings each year by the end of May through 2001. 'Ihe PUCT regulatory plan provides that such savings will be shared equally by the shareholder and ratepayers, except that the shareholder's portion will be reduced by $2.6 million per year on a total . company basis in years four through eight. 'Ihe PUCT plan also requires a senes of regulato:y fihngs currently anticipated to be in June 1994, and February 1996,1998, and 2001, to ensure that ratepayers' share of such savings be reflected in rates on a timely basis and requires Entergy Corporation to hold GSU's Texas retail customers harmless from the effects of the removal by FERC of a 40 % cap on the amount of fuel' savings GSU may be required to transfer to other Eatergy operatmg companies under the FERC trackmg mechanism (see below). On January 14, 1994, Entergy Corporation filed a request for reheanng of FERC's December 15,1993, order approving the Merger r~= ting that FERC restore the 40 % cap provision in the fuel cost protection mechanism. The matter is p-iing FERC approved certain rate schedule changes to integrate GSU into the System As..s. Certain L commitments were adopted to provide reasonable assurance that the ratepayers of AP&L, LP&L, MP&L, and NOPSI will not be allocated higher costs, including, among other thmgs- (1) a tracking F+4==% to protect AP&L, LP&L, MP&L, and NOPSI from certain unexpected increases in fuel costs; (2) the distribution of profits from power sales contracts entered into prior to the Merger; (3) a methodology to estimate the cost of capital in future FERC proceedmgs; and (4) a stipulation that AP&L, LP&L, MP&L, and NOPSI will be insulated from
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1 i
. - - _ - _ - - - __----________-__--________-_______--___-_--__-_--_.___-_N
GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) certain direct effects on capacity equalization payments should GSU, due to a findmg of imprudent GSU management prior to the Merger, be required to purchase Cajun's 30% share in River Bend (see Note 8). Texas - Fuel Reconciliation in January 1992, GSU applied with the PUCT for a new fixed fuel factor and requested a fmal reconciliation of fuel and purchased power costs incurred between December 1,1986 and September 30, 1991. GSU proposed to recover net underrecoveries and interest (including underrecoveries related to Nelson Industrial Steam Company (NISCO), discussed below) over a twelve month period. In April 1993, the presiding PUCT admmistrative law judge (ALJ) issued a report which concluded that GSU incurred approxunately $117 million of nonreimbursable fuel costs on a company-wide basis (approxunately $50 million on a Texas retail jurisdictional basis) during the reconciliation period. Included in the nonreimbursable fuel costs were payments above GSUs avoided cost rate for power purchased from NISCO. He PUCT ordered in 1986 that the purchased power costs from NISCO in excess of GSUs avoided costs be disallowed. The PUCT disallowance resulted in approxunately $12 million to $15 million of unrecovered purchased power costs on an annual basis, which GSU continued to expense as the costs were incurred. In Apnl 1991, the Texas Supreme Court, in the appeal of such order, ordered the PUCT to a!!ow GSU to recover purchased power payments in excess of its avoided cost in future proceedmgs, if GSU established to the PUCTs satisfaction that the payments were reasonable and necessary expenses. In June 1993, the PUCT, in the fuel reconciliation case, concluded that the purchased power payments made to NISCO in excess of GSU's avoided cost were not reasonably incurred. As a result of the order, GSU recorded additional fuel expenses (induding interest) of $2.8 million for non-NISCO related items. He PUCTs l order resulted in no additional expenses related to the NISCO issue, or for overcollections related to the fixed fuel factor, as those charges were expensed by GSU as they were incurred. He PUCT concluded that GSU had over-collected its fuel costs in Texas and ordered GSU to refund approxunately $33.8 million to its Texas retail customers, including approximately $7.5 million ofinterest. ne PUCT reduced GSUs fixed fuel factor in Texas from about 2.1 cents per KWH to approxunately 1.84 cents per KWH. GSU had requested a new fixed fuel factor of about 2.02 cents per KWH. Based on current sales forecasts, adoption of the PUCTs raw mded fixed fuel factor would reduce GSUs revenues by approximately $34 million annually. In October 1993, GSU appealed the PUCTs order to the Travis County District Court. No assurance can be given as to the timing or outcome of the appeal. Tuss Cities Rate Settlement in the state of Texas, incorporated cities have original jurisdiction over GSUs rates and services within their boundaries, while the PUCT has appellate jerisdiction over intramunicipal rates and original jurisdiction over unincorporated areas. l In June 1993,13 cities within GSUs Texas service area instituted an investigation to determine whether f ' GSUs current rates were justified. In October 1993, the general counsel of the PUCT instituted an inquiry into the reasonableness of GSUs rates. In November 1993, a settlement agreement was filed with the PUCT which provides for an initial reduction in annual retail base revenues in Texas of approximately $22.5 million effective for electric usage on or after November 1,1993, and a second reduction of $20 million to be effective September 1994. Further, the settlement provided for GSU to reduce rates with a $20 million one-time bill credit in December 1993, and to refund approximately $3 million to Texas retail customers on bills rendered in December 1993. The cities rate inquiries had been settled earlier on the same terms. l
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GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) In November 1993, in association with the settlement of the above-described rate inquiries, GSU entered into a settlement covering issues related to a March 1991 non-unammous settlement in another proceedmg. Under this settlement, a $30 million rate increase approved by the PUCT in March 1991, became fmal and the PUCTs treatment of GSUs federal tax expense was settled, eliminating the possibility of refunds associated with amounts collected resulting from the disputed tax calculation. In December 1993, a large industrial customer of GSU announced its intention to oppose the settlement of the PUCT rate inquiry. The customer's opposition does not affect the cities' rate settlement. The customer's opposition requires the PUCT to conduct a hearing concerning GSUs rates charged in areas outside the corporate limits of the cities in its Texas service territory to determme whether the settlement's rates are just and reasonable. A hearing has been set for July 8,1994. GSU believes that the PUCT will ultimately approve the settlement, but no assurance can be provided in this regard Louisian_g Previous rate orders of the LPSC have been appealed, and pendmg resolution of various appellate proceedmgs, GSU has made no write-off for the disallowance of $30.6 million of deferred revenue requirement that GSU recorded for the period December 16,1987 through February 18,1988. Deregulated Asset Plan A deregulated asset plan representing an unregulated portion (approximately 22%) of River Bend (plant costs, generation, revenues, and expenses) was established pursuant to a January 1992 LPSC order. H e plan allows GSU to sell such generation to Louisiana retail customers at 4.6 cents per KWH or off-system at higher prices with certain sharing provisions for such incremental revenue. LPSC Return on Eauity Review In the June 1993 open session, a prelimmary report was made comparing the authorized and actual earned rates of return for electric and gas utilities subject to the LPSC's jurisdiction. The prelimmary report indicated that several electric utilities, including GSU, may be over-earmng based on current estimated costs of equity. The LPSC requested those utilities to file responses indicating whether they agreed with the preliminary report, and to provide their reasons if they did not agree. GSU provided the LPSC with information that GSU believes supports the current rate level. He LPSC decided at its September 7,1993 open session to defer review of CSUs base rates until the first post-Merger eammgs analysis, scheduled for mid-1994. LPSC Fuel Cost Review In November 1993, the LPSC ordered a review of GSUs fuel costs. He LPSC stated that fuel costs for the period October 1988 through September 1991 would be reviewed based on the number of outages at River Bend and the findings in the June 1993 PUCT fuel reconciliation case. Hearings are scheduled to begin in March 1994. River Bend Cost Deferrals GSU deferred approximately $369 million of River Bend operating costs, purchased power costs, and accrued canying charges pursuant to a 1986 PUCT accountmg order. Approximately $182 million of these costs are being amortized over a 20-year period, and the remammg $187 million are not being amortized pending the ultimate outcome of the Rate Appeal. As of December 31, 1993, the unamortized balance of these costs was $330.3 million. Further, GSU deferred approximately $400.4 million of similar costs pursuant to a 1986 LPSC
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l I J GULF STATES UTILITIES COMPANY ) NOTES TO FINANCIAL STATEMENTS - (Continued) accounting order. These costs, of which approximately $160.4 million are unamortized as of December 31,1993, i are being amortized over a 10-year period. l In accordance with a phase-in plan approved by the LPSC, GSU deferred $324.7 million ofits River Bend costs related to the period December 1987 through February 1991. GSU has amortized $86.6 million through December 31,1993, and the remamder of $238.1 million will be recovered over approxunately 3.8 years. NOTE 3. INCOME TAXES Effective January 1,1993, GSU adopted SFAS 109. This new stan, lard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that deferred tax batam be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 ' requires that regulated enterprises r== aire adjustments resulting from its implemantation as regulatory assets or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates. A , substantial majority of the adjustments required by SFAS 109 were recorded to deferred tax balance sheet accounts with offsettmg adjustments to regulatory assets and liabilities. GSU recorded the adoption of SFAS 109 by ; restating 1990,1991, and 1992 fmancial statements and including a charge of $96.5 nulhon for the e 1=*ive ' effect of the adoption of SFAS 109 in 1990 primarily for that portion of the operations on which GSU has. discontinued regulatory accounting principles. Detailed below are the effects on GSU's 1992 and 1991 results of operations and financial position as of December 31,1992, resulting from such restatement (in thousands): 1991 As SFAS 1991 Previously No.109 As- , Reoorted Effect Restated lacome before extraordmary items and the cumulative effect of accounting change $ 122,449 5 (10,058) $ 112,391
$ 102,283 $ 9,747 5 112,030 Net income Income applicable to common stock $ 39,213 5 9,747 5 48,960 1992 As SFAS 1992 Previously No.109 As Reoorted Effect Restated l Income before extraordmary items and the cumulative effect of accounting change S 133,787 $ 5,626 -S 139,413 '
r
$ 128,157 5 5,691 S 133,848 l Net income
! Income applicable to common stock 'S 78,455 5 5,691 5 ~ 84,146 Balance at Balance at December 31, December 31, i 1992 As SFAS 1992 Previously No.109 As Reoorted Effect Restated S 6,858,494 5305,953 $7,164,447 Total assets Total capitalization and liabilities (excluding retamed cammgs) $ 6,153,859 $379,126 $6,532,985 , Retamed earmngs S 704,635 $(73,173) $ 631,462 L , l. l
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p
- l. , , .- ..
~- . . _ - , . ..
l GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) Income taxes differ from the amounts computed by applying the statutory federal moome tax rate to income before taxes. 'Ihe reasons for these differences were (1992 and 1991 restated for the effects of SFAS 109): For the Years Ended December 31. 1992 1991 i 1993
% of % of % of ,
Pretar Pretar Pretar Amount Income Amount Income Amount lataalt (Dollars in Thousands) Computed at statutory rate S 50,101 35.0 563,662 34.0 $ 54,415 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal mcome tax effect 1,332 0.9 3,573 1.9 3,444 2.2 Rate deferrals -net 6,193 4.3 5,439 2.9 5,481 3.4 Depreciation (11,343) (7.9) (15,479) (8.3) (12,302) (7.7) , Impact of change in tax rate 5,179 3.6 - - - - Book expenses not deducted for tax 15,134 10.6 142 0.1 187 0.1 ' Amortization ofinvestment tax credits (4,435) (3.1) (4,356) (2.3) (4,308) (2.7) Other - net 2.123 _Li 413 __gl 1.098 _QJ Totalincome taxes S 64.284 44.9 M gM 3 B i F F 4 l
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GULF STATES UTILITIES COMPANY i NOTES TO FINANCIAL STATEMENTS - (Continued) , Income tax expense (1992 and 1991 restated for the effects of SFAS 109) consisted of the followmg-For the Years Ended December 31. 1993 1992 1991 (In Thousands) ; Current
$ 16,714 $ 5,621 $ 4,746 Federal -
State-16.714 5.621 4.746 Total Deferred - net - 37,951 24,287 26,041 Libera!ized depreciation Nuclear unit cancellation costs, net of amortization (2,930) (3,107) (2,954) 7,689 (669) (4,652) . Fuel and purchased power costs (accrued) (12,387) 3,449 (5,216) E-a= deferred for tax purposes , (8,357) 12,349 60,333 Tax net operating loss carryforward (24,458) (21,238) (15,347) Rate deferrals -net Unbilled revenues 4,999 2.889 . 813 , (2,102) 2,328 (14,614) i Income deferred for book purposes 3,793 4,416 (8,209) - leuisiana provision for rate refund (22,183) (8,197) (5,595) l Alternative muumum tax credit Ioss on debt extinguishment, net of amortization 1,398 22,314 - State tax refund deferred for fmancial reporting - - 6,478- + 66,753 6,562 8,088 l Purchased power settlement (3.689) 4.590 2.411 Other : 46.477 49.973 47.577 - Total 1.093 (2.200) (4.308) Investment tax credit adjustments - net Recorded income tax expense $ 64.284 M $ 48.015 i
$ 46,007 $ 38,058 $ 35,084 l Charged to operations 12,009 17,801 13,166 Charged to otherincome Charged to extraordmaryitems (671) (4,943) (235) i J
Charged to cumulative effect of accounting changes 6.939 2.478 - S 64.284 $ 53.394 $ 48.015 Totalincome taxes i, 168 -
- - = - -. __ _ _ _ _ _ _ _ _ _ _ _ __ __ _
i GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) Significant components of net deferred tax liabilities, as restated for the effects of SFAS 109, as of December 31,1993 and 1992, were (in thousands): i 1993 1992 Deferred tax liabilities: Net regulatory assets S (529,706) $ (453,064) l Plant related basis differences (1,023,446) (981,915) !~ Rate deferrals - net (169,689) (194,147) Debt reacquisition loss (24,140) (22,805) Other (25.871) (29.799) ' Total 5(1.772.852) $(1.681.730) { Deferred tax assets: Net operatmg loss carryforwards S 307,737 5 294,100 Investment tax credit carryfonvard 176,032 181,560 Valuation allowance-investment tax credit can> forward (15,213) - l Unbilled rever.ue 12,243 17,242 Southern Company settlement - 66,753 Plant related basis differences 25,007 22,868 Alternative nummum tax credit 39,860 17,453 Other 164.135 162.863 709,801 762,839 Investment tax credit carryforwards reserved (160.819) (181.560) Total 548.982 581.279 5 5 Net deferred tax liability S(1.223.870) S(1.100.451) As of December 31, 1993, for tax purposes, GSU had federal tax loss carryforwards of approxunately
$790 million, state tax loss canyforwards of approxunately $561 million, and investment tax (lTC) and other credit carryforwards of approxunately $179 million which will be used to reduce acome tax payments in future years and, if not used, will expire through the year 2008. It is currently anticipated that approxunately $15.2 million of . ;
ITC canyforwards will expire unutilized as a result oflimitatens arising from the Merger. A valuatmo allowance has been provided for that amount. 'Ihe alternative muumum tax credit, which can be carried forward mdefinitely to reduce GSU's future federal income tax liability, was $40 million as of D ss 31,' 1993. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS As of December 31,1993, GSU had agreements with banks and bankmg institutmas wiuch provided for short-term lines of credit totaling $113.4 million. Included in the total short-term lines of credit was a $100 million l bank credit agreement which expired on March 2,1994. GSU had no outraamag borrowmss under these arrangements as of December 31,1993. A filing has been made with the SEC requestmg authorization for GSU to participate in the Money Pool, an ! intra-system borrowing arrangement designed to reduce the System's We on external short-term borrowings, 1 and to enter into new bank lines of credit and commercial paper arrangements. The filing requested a borrowing i authorization of $125 million with reservation of jurisdiction over additional amounts up to a maxunum of
$455 million.
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GULF STATES UTILITIES COMPANY NOTES TO FINANCI AL STATEMENTS - (Continued) NOTE 5. PREFERRED, PREFERENCE, AND COMMON STOCK He number of shares and dollar value of GSITs preferred and preference stock was: Call Price As of December 31 Per Share as Shares Outstandine Total Dollar Value of December 1993 1992 1993 1992 31.1993 (Dollars in Thousands) Preference Stock Authorized 20,000,000 shares, without par value, cumulative 6.000.000 - S 150.000 S - (1) 7% Series (2) Preferred Stock i Authorized 6,000,000 shares, $100 par l value, cumulative I Without sinking fund: 51,173 51,173 S 5,117 5 5,117 $108.00 4.40% Series 5,830 5,830 583 583 $105.00 4.50% Series 1,655 1,655 166 166 S103.00 l 4.40% - 1949 Series 9,745 9,745 975 975 $102.82 4.20% Series 14,804 14,804 1,480 1,480 $103.75 4.44% Series 10,993 10,993 1,099 1,099 $104.25 l 5.00% Series ' 26,845 26,845 2,685 2,685 $104.63 5.08% Series 10,564 10,564 1,056 1,056 $103.57 4.52% Series 32,829 32,829 3,283 3,283 $103.34 6.08% Series 350,000 350,000 35,000 35,000 $101.80 7.56% Series 500,000 500,000 50,000 50,000 $102.43 8.52% Series I 350.000 350.000 35.000 35.000 $104.64 9.96% Series 1.364.438 ,Q64.438 $ 136.444 $136.444 Total without sinking fund With sinking fund: 237,963 260,275 $ 23,796 S 26,027 S100.00 8.80% Series 22,576 24,598 2,258 2,460 S100.00 9.75% Series 196,000 224,000 19,600 22,400 $103.00 8.64% Series
- 340,000 - 34,000 -
11.48% Series
- 510,000 - 51,000 -
12.92% Series
- 712,500 - 71,250 -
11.50% Series 216,000 240,000 21,600 24,000 $100.00 Adjustable Rate Series A,7.10% (3) 337.500 382.500 33.750 38.250 $103.00 Adjustable Rate Series B,7.15%(3) 1.010.039 2.693.873 S 101.004 $269.387 Total with sinking fund (1) This series is not redeemable as of December 31,1993. (2) he total dollar value represents the involuntary liquidation value of $25 per share. (3) Rates are as of December 31,1993. He fair value of GSITs preferred and preference stock with sinking fund was estunated to be approximately $255 million and $279.5 million as of December 31,1993 and 1992, respectively. The fair value
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GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) i was' determined using quoted market prices or estimates from nationally recognized investment bankmg firms. See Note 1 for additional information on disclosure of fair value of financial instruments. Changes in the common stock, preference stock, and preferred stock during the last three years were: Number of Shares i 1993 1992 1991 Common stock issuances 100 - 6,000,000 l Common stock retirements with Merger closing (114,055,065) - - t Preference stock issuances 6,000,000 - - Preference stock retirements
- (4,000,000) -
Preferred stock with sinking fund retirements (1,683,834) (559,257) - Minimum cash sinking fund requirements for preferred stock with sinkmg funds are $6.1 million for each of the years 1994-1998. Limitations based on the ratio of after-tax canungs to fixed charges and preferred divulends _ are imposed by the Articles ofIncorporation (Articles) upon the issuance of additional preferred stock. Based upon the results of operations for the year ended December 31,1993, GSU is unable to issue any additional preferred stock. NOTE 6. LONG-TERM DEBT GSU's long-term debt as of December 31,1993 and 1992, was as follows: Maturities Interest Rates Dm...Mr 31 Erg _ql .,_I,g_ From 1 1993 1992 (In Thousands) First Mortgage Bonds 1996 1998 5% 7.35 % $ 345,000 5 345,000 1999 2003 6.41 % 8-1/2% 470,000 420,000 2004 2008 6.77 % 8-7/8% 420,000 480,000 i 2022 2024 ' 8.70% 8.94 % -450,000 450,000 i Governmental and Industrial Development Bonds 2006 2016 5.9% 12 % 482,885 483,310 ' , Debentures - Due 1998, 9.72 % 200,000 200,000 Notes payable
- 160,000 Other long-term debt 6,879 2,718 Unamortized premium and discount - net (5.700) (6.145)
Totallong-term debt 2,369,064 2,534,883 Less amount due within one year 425 160.425 Long-term debt excluding amount due within one year M $ 2.374.458 i The fair value of GSU's long-term debt as of December 31,1993 and 1992 was MmW to be S2,548.1 million and $2,623 million, respectively. Fair values were determmed using bid prices reported by dealer markets and by nationally recognized investment banking finns. See Note 1 for additional information on disclosure of fair value of financial instruments.
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1 GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) 1 For the years 1994,1995,1996,1997, and 1998, GSU has long-term debt maturities and cash sinkmg fund requirements of (in millions) $.4, $50.4, $145.4, $160.9, and $190.9, respectively. In addition, other sinkmg requirements for the years 1994,1995,1996,1997, and 1998 of (in millions) S16.7, $16.7, $15.6, $14.3, and
$12.6, respectively, may be satisfied by cash or by cenification of property additions at a rate of 167% of such requirements.
GSU has three outstandmg series of pollution control bonds which are collateralized by irrevocable letters of credit which are scheduled to expire before the scheduled maturity of the bonds. The letter of credit collateralizing the $50 million 10-5/8% series due May 1,2014, expires in May 1994, the letter of credit collateralizing the 528.4 million variable rate series due December 1, 2015, expires in September 1996 and the letter of credit collateralizing the $20 million variable rate series due April 1,2016, expires in April 1996. GSU plans to refinance these series or renew the letters of credit. i l NOTE 7. DIVIDEND RESTRICTIONS Certain limitations on the payment of cash dividends on common stock are contamed in the Articles, Mortgage Indenture, loan agreements, and applicable state and federal law. Under existing limitations, as p the short-term line of credit discussed in Note 4, $560 million of GSUs retamed earnmgs are restricted agamst the payment of common dividends at December 31, 1993. If such restriction did not exist, the most restrictive limitation as of December 31,1993, as to the amount of such dividends which might be paid, was contained in the Articles. Under the restrictions contained in the Articles, as of December 31,1993, $21 million of GSUs retamed canungs were restricted agamst the payment of cash dividends or other distributions ca common stock. On February 1,1994, GSU paid Entergy Corporation a $100 million cash disidend on common stock. l i Prior to the February 1,1994, dividend payment, GSU had not paid a common disidend since June 1986. NOTE 8. COMMITMENTS AND CONTINGENCIES Financ'el Condition Although GSU received partial rate relief relating to River Bend, GSUs fmancial position was strained from 1986 to 1990 by its inability to earn a retum on and fully recover its investment and other costs associated with River Bend. GSUs financial position has continued to improve; however, issues to be finally resolved in PUCT rate proceedmgs and appeals thereof, as discussed in Note 2, combined with the application of accounting standards, may result in substantial write-offs and charges that could result in substantial net losses being repo in 1994, and subsequent periods, with resulting substantial adverse adjustments to common shareholder's equity. Future canungs will continue to be adversely affected by the lack of full recovery and retum on the investment other costs associated with River Bend. Caiun - River Bend GSU has signiScant business relationships with Cajun, primarily co ownership of River Bend and Big Cajun 2 Unit 3. GSU and Cajun own 70% and 30% of River Bend, respectively, while Big Cajun 2 Unit 3 is owned 42% 1 and 58% by GSU and Cajun, respectively. GSU operates River Bend, and Cajun operates Big Cajun 2 Unit 3. l In June 1989, Cajun filed a civil action against GSU in the U. S. District Court for the Middle District of louisiana. Cajun stated in its complaint that the object of the suit is to annul, rescind, terminate, and/or dissolve
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l GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) the Joint Ownership Participation and Operating Agreement entered into on August 28,1979 (Operating Agreement) related to River Bend. Cajun alleges fraud and error by GSU, breach of its Educiary duties owed to Cajun, and/or GSU's repudiation, renunciation, abandonment, or dissolution of its core obligations under the Operating Agreement, as well as the lack or failure of cause and/or consideration for Cajun's performance under the Operating Agreement. The suit seeks to recover Cajun's alleged $1.6 billion investment in the unit as damages, plus attomeys' fees, interest, and costs. In March 1992, the district court appointed a mediator to engage in settlement discussions and to schedule settlement conferences between the parties. Discussions with the mediator began in July 1992, however, GSU cannot predict what effect, if any, such discussions will have on the timing or outcome of the case. A trial without a jury is set for April 12,1994, on the portion of the suit by Cajun to rescind the Operating Agreement. Two member cooperatives of Cajun have brought an independent action to declare the River Bend Operating Agreement void, based upon failure to get prior LPSC approval alleged to be necessary. GSU believes the suits are without merit and is contesting them vigorously. No assurance can be given as to the outcome of this litigation. If GSU were ultimately unsuccessful in this litigation and were required to make substantial payments, GSU would probably be unable to make such payments and would probably have to seek relief from its creditors under the Bankmptcy Code. See Note 12 for the accounting treatment of preacquisition contingencies, including a charge resulting from an adverse resolution in the Cajun - River Bend litigation. In July 1992, Cajun notified GSU that it would fund a limited amount of costs related to the fourth refueling outage at River Bend, completed in September 1992. Cajun has also not funded its share of the costs associated with certain additional repairs and improvements at River Bend completed during the refueling outage. GSU has paid the costs associated with such repairs and improvements without waiving any rights agamst Cajun. GSU believes that Cajun is obligated to pay its share of such costs under the terms of the applicable contract. Cajun has filed a suit seeking a declaration that it does not owe such funds and seeking injunctive relief agamn GSU. GSU is contesting such suit and is reviewing its available legal remedies. In September 1992, GSU received a letter from Cajun alleging that the operating and maintenance costs for River Bend are "far in excess of industry averages" and that "it would be imprudent for Cajun to fund these excessive costs." Cajun further stated that until it is satisfied it would fund a maximum of $700,000 per week under protest for the remamder of 1992. In a December 1992 letter, Cajun stated that it would also withhold costs associated with certain additional repairs, of which the majority will be incurred during the next refueling outage, currently scheduled for April 1994. GSU believes that Cajun's allegations are without merit and is considering its legal and other remedies available with respect to the underpayments by Cajun. The total resulting from Cajun's failure to fund repair projects, Cajun's funding limitation on the fourth refueling outage, and the weekly fundmg limitation by Cajun was $33.3 million as of December 31,1993, compared with a $28.4 million unfunded balance as of December 31,1992. These amounts are reflected in long-term receivables. During 1994, and for the next several years, it is expected that Cajun's share of River Bend-related costs will be in the range of $60 million to $70 million per year. Cajun's weak financial condition could have a material adverse effect on GSU, including a possible Nuclear Regulatory Commission (NRC) action with respect to the operation of River Bend and a need to bear additional costs associated with the co-owned facilities. If GSU were required to fund Cajun's share of costs, there can be no assurance that such payments could be recovered. Cajun's weak fmancial condition could also affect the ultimate collectibility of amounts owed to GSU.
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GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) i Caiun - Transmission Service GSU and Cajun are parties to FERC proceedmgs related to transmission senice charge disputes. In April 1992, FERC issued a fmal order, and in May 1992, GSU and Cajun filed motions for rehearings which are pending consideration by FERC. In June 1992, GSU filed a petition for review in the United States Court of Appeals regarding certain of the issues decided by FERC. In August 1993, the United States Coun of Appeals rendered an opinion reversing the FERC order regarding the portion of such disputes relating to the calculations of certain credits and equalization charges under GSUs senice schedules with Cajun. The opinion remanded the issues to FERC for further proceedmgs consistent with its opinion. In January 1994, FERC denied GSU's request to collect a surcharge while FERC considers the court's remand. GSU interprets the FERC order and the court of appeals' decision to mean that Cajun would owe GSU approximately $85 million as of December 31,1993. GSU further estunates that if it prevails in its May 1992 motion for rehearing, Cajun would owe GSU approximately $118 million as of December 31,1993. If Cajun were to prevail in its May 1992 motion for rehearing to FERC, and if GSU were not to prevail in its May 1992 motion for rehearing to FERC, and if FERC does not implement the court's remand as GSU contends is required, GSU estimates it would owe Cajun approximately $76 million as of December 31, 1993. He above amounts are exclusive of a $7.3 million payment by Cajun on December 31,1990, which the parties agreed to apply to the disputed transmission senice charges. GSU and Cajun funher agreed that their positions at FERC would remam unaffected by the $7.3 million. Pending FERC's ruling on the May 1992 motions for rehearing, GSU has continued to bill Cajun utilizing the historical billing methodology and has booked underpaid transmission charges, including interest, in the amount of $140.8 million as of December 31, 1993. his amount is reflected in long-term receivables and in other deferred credits, with no effect on net income. Csoital Reauirements and Financine Construction expenditures (excluding nuclear fuel) for the years 1994,1995, and 1996 are estimated to total
$134 million, $128 million, and $119 million, respectively. GSU will also require $214 million during the period 1994-1996 to meet long-term debt and preferred stock maturities and sinking fund requirements. GSU plans to meet the above requirements with internally generated funds and cash on hand. External financing during the period would be prunanly for refinancing of higher cost securities. See Note 5 and Note 6 regarding the possible issuance of first mongage bonds and preference stock and the possible refunding, redemption, purchase or other acquisition of outstanding securities.
Nuclear Insurance The Price-Anderson Act limits public liability for a single nuclear incident to approximately $9.4 billion as of December 31,1993. GSU has protection for this liability through a combination of private insurance (currently
$200 million) and an industry assessment program Under the assessment program, the maxunum amount that would be required for each nuclear incident would be $79.28 million per reactor, payable at a rate of $10 million l
per licensed reactor per incident per year. GSU has one licensed reactor. Any assessments pertainmg to this l I program are subject to the 70/30 % ownership interest between GSU and Cajun. In addition, GSU participates in a private insurance program which provides coverage for worker tort claims filed for bodily injury caused by radiation exposure. GSU's maximum assessment under the program is an aggregate of approximately $3.1 million in the event losses exceed accumulated resene funds. GSU and Cajun are members of cenain insurance programs that provide coverage for property damage, including decontammation and premature decommissioning expense, to members' nuclear generating plants. As of December 31, 1993, GSU was insured against such losses up to $2.7 billion with $250 million of this amount
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l GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) ! designated to cover any shortfall in the NRC required decommissioning trust funding. In addition, GSU is a member of an insurance program that covers certain replacement power and business intermption costs incurred ] due to prolonged nuclear unit outages. Under the property damage and replacement power / business interruption j insurance programs, GSU could be subject to assessments if losses exceed the accumulated funds available to the j insurers. As of December 31,1993, the maximum amount of such possible assessments to GSU was $15.9 million. He amount of property insurance presently carried by GSU exceeds the NRC nurumum requirement for J nuclear power plant licensees of $1.06 billion per site. NRC regulations provide that the proceeds of this insurance f must be used, first, to place and maintain the reactor in a safe and stable condition and, second, to complete decontammation operations. Only after proceeds are dedicated for such use and regulatory approval is secured, would any remammg proceeds be made available for the benefit of plant oners or their creditors. Spent Nuclear Fuel and Decommissionine Costs GSU provides for estunated future disposal costs for spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. GSU entered into a contract with the DOE, whereby the DOE will furnish disposal senice at a cost of one mill per net KWH generated and sold. He fees payable to the DOE may be adjusted in the future to assure full recovery. GSU considers all costs incurred or to be incurred for the disposal of spent nuclear fuel to be proper components of nuclear fuel expense and provisions to recover such costs have been or will be made in applications to regulatory authorities. Due to delays of the DOE's repository program for the acceptance of spent nuclear fuel, it is uncertain when i shipments of spent fuel from GSU will commence. In the meantime, GSU is responsible for spent fuel storage. Current on-site spent fuel storage capacity at River Bend is estimated to be sufficient until 2003. Hereafter, GSU will provide additional storage capacity at an estimated initial cost of SS million to $10 million. In addition, approximately $3 million to 55 million will be required every four to five years subsequent to 2003 until DOE's repository begins accepting River Bend spent fuel. GSU is recovering in rates amounts sufficient to fund decommissioning costs for River Bend, based on the original 1985 decommissioning cost study of approxunately $141 million. He amounts recovered in rates are deposited in extemal trust funds, with a market value of approximately $18.5 million and $14.5 million at December 31,1993 and 1992, respectively. He accumulated decommissioning liability of $18.1 million as of December 31,1993, has been recorded in accumulated depreciation. Decommissioning expense amounting to
$3 million was recorded in 1993. A more recent 1991 engineering study, which has not yet been reficcted in rates and used as a basis of funding, indicates decommissioning costs may be $279.8 million. GSU feels that recent l changes in the laws will tend to allow annual contributions to the trust to remam at current levels of fundmg and l offset or mitigate the increase in decommissioning costs, as indicated in the 1991 engineering study. He actual decommissioning costs may vary from the above estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment, and management believes that actual decommissioning costs are likely to be higher than the amounts presented above.
He Energy Act has a provision that assesses domestic nuclear utilities with fees for the decontamination and decommissioning of the DOE's past uranium enrichment operations. The decontammation and decommissioning assessments will be used to set up a fund into which contributions from utilities and the federal government will be placed. GSU's assessment, which will be adjusted annually for inflation, is S.6 million annually for approximately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortued ne liability I of $7.8 million as of December 31,1993, is recorded in other current liabilities and other noncurrent liabilities and is offset in financial statements by a regulatory asset, recorded as a deferred debit.
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GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) Lone-Term Contracts NISCO Power Purchases. In 1988, GSU entered into a joint venture with a pnmary term of 20 years with Conoco, Inc., Citgo Petroleum Corporation, and Vista Chemical Cornpany (Industrial Participants) whereby GSU's Nelson Units 1 and 2 were sold to a partnership (NISCO) consisting of the Industrial Participants and GSU. The Industrial Participants are supplying the fuel for the units, while GSU operates the units at the discretion of the Industrial Participants and purchases the electricity produced by the units. GSU is continuing to sell electricity to the Industrial Participants. For the years ended December 31,1993,1992, and 1991, the purchases of electricity from thejoint venture totaled $62.6 million, $37.8 million, and $61.3 million, respectively. Natural Gas Contracts. GSU has long-term gas contracts which will satisfy approxunately 75% of its annual requirements. However, such contracts as a whole only require GSU to purchase in the range of 40% of expected total gas needs. Additional gas requirements are satisfied under less expensive short-term contracts. In November 1992, GSU entered into a transportation senice agreement which obligated the gas supplier to provide GSU with flexible natural gas swing service to the Sabine and Iewis Creek generating stations. This senice is provided by the supplier's pipeline and salt dome gas storage facility, which has a present capacity of 1.3 billion cubic feet of natural gas. Coal Contracts. GSU has contracted for a long-term supply oflow-sulfur Wyoming coal for use at Nelson Unit 6. This contract, which is set to expire in 2004, will provide a supply of 50 million tons over the term of the contract. Cajun has advised GSU that current contracts will provide an adequate supply of coal for Big Cajun 2 Unit 3 until 1997. Environmentalissues GSU has been notified by the U. S. Emironmental Protection Agency (EPA) that it has been designated as a potentially responsible party for the cleanup of sites on which GSU and others have or have been alleged to have disposed of material designated as hazardous waste. GSU is currently negotiating with the EPA and state authorities regarding the cleanup of some of these sites. Several class action and other suits have been filal in state and federal courts seeking relief from GSU and others for damages caused by the disposal of hazardous waste and for asbestos-related disease which allegedly occurred from exposure on GSU premises. While the amounts at issue in the cleanup efforts and suits may be very substantial sums, management believes that its results of operations and financial condition will not be materially affected by the outcome of the suits. As of December 31,1993, GSU has accrued cumulative amounts related to the cleanup of six sites at which GSU has been designated a potentially responsible party, totaling $25.2 million since 1990. Through December 31,1993, GSU has expensed $7 million cumulatively on the cleanup, resulting in a remanung liability of $18.2 million as of December 31,1993. GSU is also involved in litigation arising in the normal course of business. While the results of such litigation cannot be predicted with certainty, management believes that the final outcome will not have a material adverse effect on its financial condition or operating results when resolved in a future period. I 176 -
GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) NOTE 9. LEASES General , As of December 31,1993, GSU had capital leases and noncancelable operating leases (excluding nuclear fuel , leases) with muumum lease payments as follows: Capital Operating Leases Leases XgE (In Thousands) 1994 $ 12,475 $ 19,720 1995 12,475 19,720 : 1996 12,475 19,720 1997 12,475 9,509 1998 12,475 11,271 Years thereafter 93.855 96.749 Minimum lease payments 156,230 M Less: Amount representing interest 63.628 Present value of net muumum lease payments S 92.602 Rental expense for capital and operating leases (excluding nuclear fuel leases) amounted to approxunately
$31.9 million, $21.9 million, and $14.9 million, in 1993,1992, and 1991, respectively.
GSU is leasing the Lewis Creek generatmg station from its wholly owned consolidated subsidiary, GSG&T. Nuclear Fuel Lease , GSU has arrangements to lease nuclear fuel with a non-affiliated third party which finances its acquisition of j nuclear fuel through a credit agreement and the issuance of notes totaling $130 million as of December 31,1993. I On January 31,1994, $25 million of the notes matured, while $40 million of the notes each will mature on l January 31,1995 and January 31,1996. It is expected that altemative financing will be secured by the lessor upon the maturity of the notes in 1995 and 1996. If the lessor cannot arrange for alternative financing upon the matunty l of its borrowings, GSU must purchase nuclear fuel in an amount sufficient to enable the lessor to retire such borrowings. Lease payments are based on nuclear fuel use. Nuclear fuel expense of $43.6 million, $31.6 million, and
$58.1 million (includmg interest of $10.2 million, $11.5 million and $12.2 million) was charged to operations in '
1993,1992, and 1991, respectively. NOTE 10. . POSTRETIREMENT BENEFITS Pension Plan q GSU has a defined benefit pension plan covering substantially all of its employces. The pension plan is noncontributory and pro 5 ides pension benefits that are based on employees' credited service and the highest five consecutive years of employees' compensation during the last ten years before retirement. GSU funds pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974 %
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1 l GULF STATES UTILITIES COMPANY l 1 NOTES TO FINANCIAL STATEMENTS -(Continued) amended, and the Intemal Revenue Code of 1986, as amended. The assets of the plan consist primarily of common and preferred stocks and fixed income securities. GSU's 1993,1992, and 1991 pension cost, including amounts capitahzed, included the following components: For the Years Ended December 31. 1993 1992 1991 (In Thousands) Service cost - bene 6ts camed during the period S 10,417 S 12,396 $ 10,306 Interest cost on projected benefit obligation 17,643 16,307 15,355 Actual retum on plan assets (43,400) (28,117) (56,898) Net amortization and deferral 14.863 2.926 36.347 Net pension cost S (477) S 3.512 S 5.110 The funded status of GSU's pension plan as of December 31,1993 and 1992, was: 1993 1992 (In Thousands) Actuarial present value of benefit obligations: Vested $ 197,386 $ 186,845 Nonvested 13.667 11.508 Accumulated benefit obligation $211.053 $ 198.353 l Plan assets at fair market value $337,922 $306,660 Projected benefit obligation 259.462 255.573 Plan assets in excess of projected benefit obligation 78,460 51,087 Unrecogmzed prior service cost 25,977 24,671 Unrecogmzed transition asset (16,712) (19,099) Unrecogmzed net gain (92.910) (62.321) Accrued pension liability S (5.185) $ (5.662) The significant acuarial assumptions used in computing the information above were: 1993 1991 1991 Weighted average discount rate 7.50 % 6.50 % 7.25 % Weighted average increase in future compensation levels 5.00 5.75 6.10 Expected long-term rate of return on plan assets 8.50 8.50 8.50 i Transition assets are being amortized over 15 years. l l In December 1993, GSU recorded a $17 million charge related to the announced early retirement program in connection with the Merger, of which $14.9 million was expensed. l 1 l l - 178 -
GULF STATES UTILITIES COMPANY j NOTES TO FINANCIAL STATEMENTS -(Continued) Other Postretirement Benefits GSU also provides certain health care and life insurance benefits for retired employees. All of GSUs employees may become eligible for these benefits if they reach retirement age while still working for GSU. He cost of providing these benefits, recorded on a cash basis, was 55.3 million and 55.5 million for the years 1992 and 1991, respectively. Effective January 1,1993, GSU adopted SFAS 106. The new standard requires a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. GSU continues to fund these benefits on a pay-as-you-go-basis. As of January 1,1993, the actuanally determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be . approximately $128 million. This obligation is being amortized over a 20-year period haginning in 1993. In March 1993, the PUCT issued a ruling applicable to all Texas utilities that amounts recorded in compliance with SFAS 106 and included in a rate filing test period, will be recoverable in rates (at the time of the next general rate case) and that the pombsiuwst benefit amounts allowed in rates must then be funded by the , H utility. He PUCT made no specific provision in its order permitting deferral, as a regulatory asset, of these costs. He LPSC ordered GSU to use the pay-as-you-go method for re-maing purposes for postretirement benefits other than pensions, but the LPSC retams the flexibility to examine companies' accounting for postretirement benefits to determme if special exceptions to this order are warranted. GSUs net mcome in 1993 was decreased by approximately $7.9 million as a result of adopting SFAS 106. 1 GSUs 1993 postretirement benefit cost, including amounts capitabad and deferred, included the following components (in thousands): ; Service cost - benefits earned during the period S 5,467 Interest cost on APBO 9,976 Actual return on plan assets - Amortization of transition obligation 6.402 ; Net periodic postretirement benefit cost $21.845 , He funded status of GSUs postretirement plan as of December 31,1993, was (in thousands): Accumulated postretirement benefit obligation: Retirees S 46,270 Other fully eligible participants 38,091 Other active participants 18.359 102,720 Plan assets at fair value - Plan assets in excess of(less than APBO) (102,720) Unrecognized transition obligation 121,634 Unrecognized net gain (35.534) i Accrued postretirement benefit liability S (16.620) ! He assumed health care cost trend rate used in measuring the APBO is 10% for 1994, gradually decreasing ! cach successive year until it reaches 5% in 2002. A one percentage-point increase in the assumed health care cost trend rate for each year would increase the APBO as of December 31,1993, by 13.6% and the sum of the senice cost and interest cost by approximately 22.7%. He assumed discount rate and rate of increase in future compensation used in detemumng the APBO were 7.5%, and 5%, respectively.
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GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) NOTE 11. TRANSACTIONS WITII AFFILIATES Effective December 31,1993, GSU purchases electricity from and/or sells electricity to the other System operating companies under rate schedules filed with FERC. 1 Operating revenues include revenues from sales to System operating companies prior to the Merger, totalmg 5.5 million in 1993, $0 in 1992, and $.5 million in 1991. Operating expenses include charges from System operating companies for purchased power and related charges, prior to the Merger, totaling $25.5 million in 1993, l $38.8 million in 1992, and $16.1 million in 1991. NOTE 12. ENTERGY CORPORATION-GSU MERGER On December 31,1993, Entergy Corporation and GSU consummated their Merger. GSU became a wholly-owned subsidiary of Entergy Corporation and continues to operate as a corporation under the regulation of the PUCT and the LPSC. As consideration to GSU's shareholders, Entergy Corporation paid $250 million and issued 56,667,726 shares of its common stock in exchange for the 114,055,065 outstandmg shares of GSU common stock. Tne Merger was accounted for under the purchase method of accounting. Various parties have requested rehearings and/or are appealing the approval orders or plans of the SEC, NRC, LPSC, and FERC. As a result of the December 31,1993 Merger closing, GSU recorded expenses totaling $49 million, net of related tax effects, for early retirement and other severance related plans and the payment to financial consultants involved in Merger negotiations on behalf of GSU. See Note 2 for information regarding Merger related rate agreements. Entergy Corporation recorded an acquisition adjustment in utility plant in the amount of $380 million representing the excess of the purchase price over the net assets acquired of GSU. The acquisition adjustment will be amortized on a straight-line basis over a 31-year period, which approximates the remammg average book life of GSU's plant. The allocation of the purchase price has been based on prelimmary estunates which may be revised at a later date. The possibility of an adverse result in the litigation relating to Cajun (see Note 8) and the possibility of a write-off relating to Texas River Bend ratemakmg issues (see Note 2) represent preacquisition contingencies. There may be other contingencies associated with GSU which could also constitute preacquisition contingencies but which have not yet been specifically identified as such by Entergy Corporation. During the allocation period (which will not exceed one year after consummation of the transaction), Entergy Corporation will complete its analyses with respect to these contingencies. Upon completion, should Entergy Corporation no longer believe GSU has a reasonable possibility of attaining a favorable ruling in such preacquisition contingencies, any resulting wTite-offs and/or losses would cause the reduction of the affected noncurrent assets and an increase of an equal amount in the acquisition adjustment in Entergy Corporation's consolidated financial statements, in accordance with the purchase method of accounting for business combinations. Any resulting write-offs and/or losses would be charged to operations during the current period on GSU's fmancial statements.
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l GULF STATES UTILITIES COMPANY NOTES TO FINANCIAL STATEMENTS - (Concluded) 1 - NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED) Operatmg results for the four quarters of 1993 and 1992 were: Income (Loss) Before Extraordinary Items and the Cumulative Effect Net Operating Operating ofAccounting Income Revenues Income Channes (Loss) (In Thousands) ' 1993: First Quarter $404,178 $ 69,408 $ 15,007 $ 25,667 , Second Quarter $442,223 $ 81,989 $ 31,066 $ 30,781 ! Third Quarter $574,607 $118,032 5 70,155 $ 69,181 ! Fourth Quarter $406,612 $ 1,187 $(46,767) $(46,767) 1992: ; First Quarter $403,279 $ 71,372 $ 24,187 $ 26,209 ' Second Quarter $417,365 $ 78,999 $ 32,155 $ 27,889 Third Quarter $517,899 $116,252 $ 66,167 $ 65,648_ ' Fourth Quarter $434,831 $ 71,997 $ 16,904 $ 14,102 GSU's business is subject to seasonal fluctuations with the peak penod occurring during the third quarter. See Note 1 for information regardmg the change in accounting for unbilled revenues during 1993. See Note 2 for information regarding rate refunds during December 1993, and Note 12 for information regarding Merger-related charges recorded during the fourth quarter of 1993. See Note I for information regardmg extraordmary items recorded in 1992 due to the eninpia- of debt and for informatum regarding the cumulative effect of a change in accounting for power plant materials and supplies. 1 b 4
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i GULF STATES UTILITIES COMPANY i SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1993 1992 1991 1990 1989 (In Thousands) S1,827,620 $1,773,374 51,702,235 S1,690,685 5 1,607,406 Operating revenues Income (loss) before extraordmary items and the cumulative effect of S 69,461 5 139,413 $ 112,391 S (36,399) $ (45,573) accounting changes
$7,165,776 $7,164,447 $7,183,119 $7,135,399 $ 6,751,432 Total assets
$2,772,002 $2,798,768 $2,816,577 S2,663,249 $ 2,954,736 long-term obligations (1) i (1) Includes long-term debt (excluding currently maturing debt), preferred and preference stock with sinking fund, and noncurrent capital lease obligations. ,
See Notes 1 and 10 for the effect of scemnting changes in 1993 and 1992 and Notes 2 and 8 regarding River Bend rate appeals and litigation with Cajun. , 1993 1992 1991 1990 1989 i (Dollars in Thousands) Electric Department Operatmg Revenues: S $85,799 $ 560,552 $ 547,147 $ 523,911 $ 487,972 Residential 415,267- 400,803 383,883 378,253 357,568 Commercial 650,230 642,298 582,568 578,928 541,019 Industrial 26.118. 26.195 24.792 24.101 22.728 , Governmental 1,677,414 1,629,848 1,538,390 1,505,193 1,409,287 Total retail 31,898 24,485 44,136 48,125 51,584 Sales for resale 38.649 40.203 41.433 43.317 41.003 Other
$1.747.961 $1.694.536 $1.623 959 $1.596.635 $1.501.874 Total Electric Department Billed Electric Energy Sales (Millions of KWH):
Electric Department 7,192 6,825 6,925 6,834 6,473 Residential ' 5,711 5,474 5,460 5,388 5,198 Commercial 14,294 14,413 13,629 13,347 12,333 , Industrial 296 302 295 285 275 Govemmental 27,493 27,014 26,309 25,854 24,279 Total retail 666 540 1.049 1.180 916 Sales for resale 28,159 27,554 27,358 27,034 25,195 Total Electric Department 1.597 1.722 1.711 1.930 2.271 Steam Department ' 29.756 29.276 29.069 28.964 27.466 Total
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i 4 Louisiana Power & Light Company /1993 Financial Statements 1 i I I ,l \
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1 i LOUISIANA POWER & LIGHT COMPANY ! 1 DEFINITIONS Certain abbreviations or acronyms used in LP&L's Financial Statements, Notes to Financial Statements, ; and Management's Financial Discussion and Analysis are defined below: Abbreviation or Acronym ICIE , AFUDC Allowance for Funds Used During Construction , AP&L Arkansas Power & Light Company i DOE United States Department of Energy } Entergy or System Entergy Corporation and its various direct and indirect subsidiaries [ Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy Corporation that has operating responsibility for Grand Gulf 1, Waterford 3, ANO, and River Bend , FASB Financial Accounting Standards Board t FERC Federal Energy Regulatory Commission Grand Gulf 1 Unit No.1 of the Grand Gulf Station Grand Gulf 2 Unit No. 2 of the Grand Gulf Station l Grand Gulf Station Grand Gulf Steam Electric Generating Station l, GSU Gulf States Utilities Company (including ' wholly owned subsidiaries - Varibus Corporation, GSGAT, Inc., Prudential Oil and Gas, Inc., and Southern Gulf Railw3y Company) KWH Kilowatt-Hour (s) LP&L Louisiana Power & Light Company l LPSC Louisiana Public Service Commissiors , J Money Pool Entergy Money Pool, which allows certain System companies to borrow from, or lend to, certain other System companies MP&L Mississippi Power & Light Company NOPSI New Orleans Public Service Inc. OBRA Omnibus Budget Reconciliation Act of 1993
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LOUISIANA POWER & LIGHT COMPANY - DEFINITIONS -(Concluded) t
- Abbreviation or Acronym Igrgg A corporation that, in connection with the Waterford 3 sale and leaseback l Owner Participant
, transactions, has acquired a beneficial interest in a trust, the Owner l Trustee of which is the owner and lessor of. undivided interest in l Waterford 3 Each institution and/or individual actmg as owner trustee under a trust' .;
Owner Trustec agreement with an Owner Participant in connection with the Waterford 3 sale and leaseback trarinetiaan Securities and Exchange Comnussion SEC Statement of Financial Accounting Standards promulgated by the FASB SFAS r SFAS No.106, " Employers' Accounting for Postretirement Benents Other SFAS 106 Than Pensions" t SFAS No.109, " Accounting for Income Taxes" , SFAS 109 System or Entergy Entergy Corporation and its various direct and indirect subsidiaries
' System Energy System Energy Resources,Inc.
I i System Fuels, Inc. System Fuels i System operstmg companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively , Unit No. 3 of LP&L's Waterford Steam Electric Generatmg Station . Waterford 3 i f ( i k I t t
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_ _ _ ____-__-__- _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ = _ _ _ _ . _ - _ - LOUISIANA POWER & LIGHT COMPANY REPORT OF MANAGEMENT - De management of Louisiana Power & Light Company has prepared and is responsible for the financial 1 statements and related financial information included herein. De financial statements are based on generally accepted accounting principles. Financial information included elsewhere in this repost is consistent with the fmancial statements. To meet its responsibilities with respect to financial information, management maintains and enforces a system ofinternal accounting controls that is. designed to provide reasonable assurance, on a cost-effective basis, as l j to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. His system includes communication through written policies and procedures, an employee Code of Conduct, and an organizational structure that provides for appropriate division of responsibility and the trammg of personnel. This system is also tested by a comprehensive internal audit program The i% public accountants provide an objective assessment of the degros to which management meets its responsibility for fairness of financial reporting. Dey regularly evaluate the system of mternal accounting controls and perform such tests and other procedures as they deem necessary to reach and express an opinion on the fairness of the financial statements. Management believes that these policies and procedures provide reasonable assurance that its W-are carried out with a high standard of business conduct. EDWIN LUPBERGER GERALD D. MCINVALE Chairman and Chief Executive Officer Senior Vice President and Chief Financial Officer 1
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LOUISIANA POWER & LIGHT COMPANY AUDIT COMMITTEE CHAIRMAN'S LETTER
%e Louisiana Power & Light Company Audit Committee of the Board of Directors is comprised of three directors, who are not officers of LP&L: Joseph J. Krebs, Jr. (Chairman), William K. Hood, and H. Duke Shackelford. The committee held four wingt during 1993.
De Audit Committee oversees LP&L's financial reporting process on behalf of the Board of Directors and provides reasonable assurance to the Board that sufficient operatmg, accounting, and financial controls are in existence and are adequately reviewed by programs ofinternal and external audits. De Audit Committee discussed with Entergy's internal auditors and the independent public accountants (Deloitte & Touche) the overall scope and specific plans for their respective audits, as well as LP&L's financial statements and the adequacy of LP&L's internal controls, ne comnuttee met, together and separately, with Entergy's internal auditors and independent public accountants, without management present, to discuss the results of their aufts, their evaluation of LP&L's internal controls, and the overall quality of LP&L's financial reporting. The meetmgs also were designed to heimata and encourage any private communication between the committee and the internal auditors or independent public accountants. JOSEPH J. KREBS, IR. Chairman, Audit Committee L t l
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i k INDEPENDENT AUDITORS' REPORT To the Shareholders and the Board of Directers of i Louisiana Power & Light Company , We have audited the accompanying balance sheets ofIouisiana Power & Light Company (LP&L) as of , December 31,1993 and 1992, and the related statements ofincome, retamed canungs, and cash flows for each of the three years in the period ended December 31,1993. These financial statements are the responsibility of LP&L's management. Our responsibihty is to express an opuuon on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Dose standards i require that we plan and perfonn the audit to obtain reasonable assurance about whether the Anancial statements are free of material misstatement. An audit includes examuung, on a test basis, evidence supportmg the amounts ; and disclosures in the financial statements. An audit also includes assessing the m*- g principles used and significant estimates made by management, as well as evaluatmg the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of LP&L at December 31,1993 and 1992, and the results ofits operations and its cash flows for each of the three years in the period ended December 31,1993 in conformity with generally accepted scema'ia: principles. As discussed in Notes 3 and 10 to the financial statements, in 1993 LP&L changed its methods of accounting for income taxes and postretirement benefits other than pensions, respectively. DELOITTE & TOUCHE , New Orleans, Louisiana February 11,1994 ; i t I
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LOUISIANA POWER & LIGHT COMPANY BALANCE SHEETS ASSETS December 31, 1993 1992 (In Thousands) Utility Plant (Note 1):
$4,646,020 S4,577,410 !
Electric ! 225,083 225,083 Electric plant under lease (Note 9) 133,536 67,535 Construction work in progress 61,375 63,190 Nuclear fuel under capital leases (Note 9) 3,823 3,437 Nuclear fuel 5,069,837 4,936,655 Total 1.496,107 1,380,282 Less - accumulated depreciation and amortization 3,573,730 3,556,373 Utility plant - net Other Property and Investments: 20,060 20,060 Nonutility property 22,109 17,121 Decommissioning trust fund (Note 8) Investment in subsidiary company - at equity (Note 8) 14,230 14,230 984 922 Other 57,383 52,333 Total Current Assets: Cash equivalents (Note 1): Temporary cash investments - at cost, which approximates market: Associated companies (Note 4)
- 593 33,489 22,189 Other 33,489 22,782 Total cash equivalents 19,077 4,080 Special deposits Accounts receivable:
Customer (less allowance for doubtful accounts of 66,575 58,067
$1.1 million in 1993 and $2.0 million in 1992) 2,952 8,863 Associated companies (Note 11) 10,656 11,805 Other 64,314 57,716 4 Accrued unbilled revenues (Note 1)
- 2,939 Deferred fuel costs (Note 1) 6,031 4,915 Accumulated deferred income taxes (Note 3) 87,204 87,856 Materials and supplies - at average cost 28,422 28,422 Rate deferrals (Note 2) 16,510 41,527 Prepayments and other 335,230 328,972 Total Deferred Debits:
54,031 82,453 Rate deferrals (Note 2) SFAS 109 regulatory asset - net (Note 3) 349,703 - Unamonizedloss on reaquired debt 47,853 48,203 46,068 40,814 Other (Note 8) 497,655 171,470 Total
$4,463,998 $4,109,148 TOTAL See Notes to Financial Statements.
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LOUISIANA POWER & LIGHT COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31 1993 1992 (In Thousands) Capitahzation: Common stock, no par value, authorized 250,000,000 shares; issued and outstandmg 165,173,180 shares in 1993 and 1992 (Note 5) $1,088,900 $1,088,900 Capital stock expense and other (6,109) (7,469) Retamed earnmgs (Note 7) 89,849 94.510 Total common shareholder's equity 1,172,640 1,175,941 Preferred stock (Note 5): Without sinking fund 160,500 160,500 With sinking fund 126,302 148,802 Long-term debt (Note 6) 1,457,626 1,445,947 Total 2,917,068 2.931,190 Other Noncurrent Liabilities: Obligations under capital leases (Note 9) 27,508 28,160 / Other(Note 8) 27,672 17,027 Total 55,180 45,187 Current Liabilities: Currently maturmg long-term debt (Note 6) 25,315 1,275 Notes payable-associated companies (Note 4) 52,041 - Accounts payable: Associated companies (Note 11) 33,523 37,693 Other 76,284 100,312 Customer deposits 52,234 49,558 Taxes accrued 15,110 8,249 Interest accrued 42,141 41,138 Dividends declared 5,938 6,675 , Gas contract settlement - liability to customers - 55,998 l Deferred revenue - gas supplierjudgment proceeds (Note 2) 14,632 42,256
- Deferred fuelcost (Note 1) 605 -
l Obligations under capital leases (Note 9) 33,867 35,029 Other 9,741 11,428 Total 361,431 389,611 Deferred Credits: Accumulated deferred income taxes (Note 3) 834,899 441,064 Accumulated deferred investment tax credits (Note 3) 188,843 191,528 l Deferred revenue - gas supplierjudgment proceeds (Note 2) - 14,846 Deferred interest - Waterford 3 lease obligaion (Note 9) 25,372 24,796 Other 81,205 70,926 Total 1,130,319 743,160 Commitments and Contingencies (Notes 2, 8, and 9) TOTAL $4,463,998 $4,109,148 l See Notes to Financial Statements.
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1 l l LOUISIANA POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS For the Years Ended Decensber 31, 1993 1992 1991 (In Thousands) { Operating Activities: I
$188,808 $182,989 $166,572 Net income I Noncash items included in net income:
Change in rate deferrals (Note 2) 28,422 28,422 28,422 Depreciation and decommissioning 142,051 138,290 130,898 Deferred income taxes and investre:nt tax credits 40,261 42,896 73,795 l Allowance for equity funds used during construction (2,581) (1,714) (1,244) Amortization of deferred revenues (Note 2) (42,470) (38,646) (36,310) Changesin working capital: I Receivables (8,046) (5,135) (8,753) Accounts payable (28,198) 7,733 13,971 Taxes accrued 6,861 6,002 (22,642) Interest accrued 1.003 2,917 (6,680) Other working capital accounts 15,205 (16,037) (2,939) , Refunds to customers - gas contract settlement (56,027) (56,066) (56,098) l Decommissioning trust contributions (4,000) (2,000) (7,227) l 18,299 5,982 4,403 Other l Net cash flow provided by operating activities 299,588 295.633 276,168 i investing Activities: ' Construction expenditures (163,142) (150,527) (135,986) Allowance for equity funds used during construction 2,581 1,714 1,244-Net cash flow used in investing activities (160,561) (148,813) (134,742) Financing Activities: Proceeds from the issuance of: f First mortgage bonds 100,000 269,000 - j Preferred stock
- 87,000 85,000 ,
Common stock
- - 100,000 l Other long-term debt 58,000 44,094 49,907 l Changes in short-term borrowings 52,041 - -
Retirement of: First mortgage bonds (100,919) (309,205) (320,786) Other long-term debt (22,052) (15,977) (4,702) i Redemption of preferred stock (22,500) (63,981) (60,500) ! Dividends paid: Common stock (167,600) (17#,600) (63,552) Preferred stock (25,290) (28.845) _ 26,801) ( Net cash flow used in financing activities (128,320) (192,014J J2J1,527) Net increase (decrease) in cash and cash equivalents 10,707 (45,694) (100,101) Cash and cash equivalents at beginning of period 22,782 68,476 168,577 Cash and cash equivalents at end of period $33,489 $22,782 $68,476 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: l Interest - net of amount capitalized $127,497 $126,674 $172,421 l Income taxes S62,414 $32,668 $33,133 Noncash investing and financing activities: Capitallease obligations incurred $33,210 $37,689 $10,002 . l See Notes to Financial Statenents.
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l 1 LOUISIANA POWER & LIGHT COMPANY l MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES Liquidity is important to LP&L due to the capital intensive nature of our business, which requires large investments in long-lived assets. However, large capital expenditures for the construction of new generating capacity are not currently planned LP&L requires significant capital resources for the periodic maturity of certain series of debt and preferred stock. Net cash flow from operations totaled $300 million, $296 million, and $276 million in 1993,1992, and 1991, respectively. In recent years, this cash flow, supplemented by cash on hand, has been sufficient to meet substantially all investing and fmancing requirements, including capital expenditures, dividends, and debt /prefe:Ted stock maturities. LP&L's ability to fund these capital requirements results, in part, from our continued efforts to streamline operations and reduce costs, as well as collections under our Waterford 3 rate phase-in plan which exceed the current cash requirements for Waterford 3-related costs. (In the income statement, these revenue collections are offset by the amomzation of previously deferred costs, therefore, there is no effect on net income.) See Note 2, incorporated herein by reference, for additional information on LP&L's rate phase-in plan. See Note 8, incorporated herein by reference, for additional information on LP&L's capital and refmancing requirements in 1994 - 1996. Also, in order to take advantage of lower interest and dividend rates, LP&L may continue to refinance high-cost debt and preferred stock prior to maturity. Earnmgs coverage tests and bondable property additions limit the first mortgage bonds and preferred stock that LP&L can issue. Based on the most restrictive applicable tests as of December 31,1993, and assuming an armual interest or dividend rate of 8%, LP&L could have issued $92 million of additional first mortgage bonds or $686 million of additional preferred stock. Further, LP&L has the conditional ability to issue first mortgage bonds against the retirement of first mortgage bonds, in some cases without satisfying an carmngs coverage test. See Notes 5 and 6, incorporated herein by reference, for information on LP&L's financing activities and Note 4, incorporated herein by reference, for information on LP&L's short-term borrowings and lines of credit.
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LOUISIANA POWER & LIGHT COMPANY STATEMENTS OFINCOME r For the Years Ended December 31. 1993 1992 1991 , (In Thousands)
$1,729,666 $1,553,745 $1,528,934 Operanng Revenues (Notes 1,2, and 11):
i Operaung Expenses l Operation (Note 11): i Fuel for electric generation and fuel-related 338,670 256,313 212,973 expenses ' 381,252 335,750 344,637 Purchased power (Notes 2 and 8) 260,419 ' 250,836 253,080 I Other 98,281 92,363 101,896 l Maintenance (Note 11) 142,051 138,290 130,898 j Depreciation and decommissioning 50,391 49,507 . 48,428 Taxes other than income taxes ' 108,568 83,984 76,104 laceme taxes (Note 3) 28,422 28.422 28,422 Amortization of rate deferrals (Note 2) 1,408,054 1,235,465 1,196,438 . Total 321,612 318,280 332,496 Operannglocome : Other Tamme Allowance for equity funds used during 2,581 1,714 1,244 construction 2,069 6,676 8,739 Miscellaneous - net (2,245) - (3,053) (8.616) : lamme taxes (Note 3) 2,405 5,337 1,367 Total , i Interest Charges: laterest on long-term debt 124,632 128,672 158,816 - , 12,325. 12,691 9,206 ' Otherinterest - net Allowance for 6cd funds used : during construction (1,748) ' (735)- (731) 135,209 140,628 167,291 , Total 6 188,808 182,989 166,572 Netincome Preferred Stock Dividend Requirements 24,754 28,416 27,343 ,
$164,054 $154,573 $139,229 Earmngs Applicable to Common Stock ,
See Notes to Financial Statements. l l l 1
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LOUISIANA POWER & LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31 1993 1992 1991 (In Thousands) Retained Earmngs, January 1 $94,510 Si17,820 S46,583 Add: Net income 188,808 182,989 166,572 Total 283,318 300,809 213,155 Deduct: Dividends declared: Preferred stock 24,553 28,416 27,343 Common stock 167,600 174,600 63,552 Capital stock expenses 1,316 3,283 4,440 Total 193,469 206,299 95.335 Retamed Earmngs, December 31 (Note 7) $89,849 594,510 $117,820 See Notes to Financial Statements. l l i l I i I
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LOUISIANA POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income l Excluding the effects ofimplementing SFAS 109 and SFAS 106 (see Notes 3 and 10, incorporated herein by reference), net income for 1993 would have been $198.8 million resulting in an increase of $15.8 million. This increase is due prunarily to increased retail energy sales. Net income increased in 1992 due primarily to a decrease in interest expense. Significant factors affectmg the results of operations and causing vanances between the years 1993 and 1992, and 1992 and 1991, are discussed under " Revenues and Sales" and " Expenses" below. Revenues and Sales See " Selected Financial Data - Five-Year Comparison," incorporated herein by reference, following the notes, for information on operating revenues by source and KWH sales. Electric operating revenues were higher in 1993 due pnmarily to increased fuel adjustment revenues, which do not affect net income, and to increased residential and commercial energy sales resulting primarily from a return to more normal weather as compared to milder weather in 1992. Industnal energy sales also increased primarily in the petrochemicalindustry. Electric operating revenues were higher in 1992 due primarily to increased fuel adjustment revenues and i revenue from sales for resale. These increases were partially offset by decreased retail base revenues as a result of milder temperatures. Total energy sales remamed relatively flat in 1992 with higher sales for resale offset by lower l residential and commer -ial sales resulting from these milder temperatures. Eroenses Fuel for electric generation aad fuel-related expenses and purchased power increased in 1993 due primarily to an increase in generation requirements resulting primarily from increased retail energy sales and increased fuel costs. Fuel for electric generation and fuel-related expenses increased in 1992 due primarily to a higher average per unit cost for gas resulting from increased gas prices in 1992. i Total income taxes increased in 1993 due primarily to higher pretax income, an increase in the federal income tax rate as a result of OBRA, and the effect ofimplementing SFAS 109. l Interest expense decreased in 1993 and 1992 as a result of the continued refinancing of high cost debt during 1993 and 1992,
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l LOUISIANA POWER & LIGIIT COMPANY l MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS ) l I I Competition l l LP&L welcomes competition in the electric energy business and believes that a more competitive f environment should benefit our customers, employees, and shareholders of Entergy Corporation. We also recognize that competition presents us with many challenges, and we have identified the following as our major competitive challenges: J 1 Retail and Wholesale Rate Issues l l 1 Increasing competition in the utility industry brings an increased need to stabilize or reduce retail rates. l LP&L is scheduled for a review ofits rates and rate structure by the LPSC upon expiration of LP&L's current rate I freeze in March 1994. Under the same LPSC order, an approximate $46 million per year increase in LP&L's retail I rates will also expire in March 1994. See Note 2, incorporated herein by reference, for additional information. I Retail wheeling, a major industry issue which may require utilities to " wheel" or move power from third parties to their own retail customers, is evolving gradually. As a result, the retail market could become more competitive. In the wholesale rate area, FERC approved in 1992, with certain modiScations, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power, Inc. to sell wholesale power at market-based rates and to provide to electric utilities "open access" to the System's transmission system (subject to certain requirements). GSU was later added to this filing. Various intervenors in the proceedmg filed petitions for review with the United States Court of Appeals for the District of Columbia Circuit. FERC's order, once it takes effect, will increase marketing , opportunities for LP&L, but will also expose LP&L to the risk of loss of load or reduced revenues due to l j l competition with alternative suppliers. In light of the rate issues discussed above, LP&L is aggressively reducing c >sts to avoid potential earnings crosions that might result as well as to successfully compete by becoming a low-cost producer. To help nunmuze future costs, LP&L remams committed to least cost planning. In December 1992, LP&L filed a Least Cost Integrated Resource Plan (Least Cost Plan) with its retail regulators. Least cost planning includes demand-side ! measures such as customer energy conservation and supply-side measures such as more efficient power plants. nese measures are designed to delay the building of new power plants for the next 20 years. LP&L plans to periodically file revised Least Cost Plans. He Energy Policy Act of 1992 He Energy Policy Act of 1992 (Energy Act) is changing the transmission and distribution of electricity. His act encourages competition and affords us the opportunities, and the risks, associated with an open and more competitive market environment. He Energy Act increases competition in the wholesale energy market through the creation of exempt wholesale generators (EWGs). He Energy Act also gives FERC the authority to order investor-owned utilities to provide transmission access to or for other utilities, including EWGs.
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l LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS NOTE 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES LP&L maintains accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications. Revenues and Fuel Costs l LP&L records revenues when billed to its customers and, in addition, accrues revenue for the nonfuel l portion of estimated revenues for energy delivered since the latest billings. j l LP&L's rate schedules include fuel adjustment clauses that allow deferral of fuel costs until such costs are l reflected in the related revenues. Utility Plant Utility plant is stated at original cost. Partial disallowances of plant <,ost ordered by the regulators have ' been recorded as an adjustment to utility plant. The original cost of utility plant retired or removed, plus the l applicable removal costs, less salvage, is charged to accumulated depreciation. Maintenance, repairs, and minor i replacement costs are charged to operating expenses. Substantially all of LP&L's utility plant is subject to the lien ofits mortgage indenture. In addition, cenain assets of LP&L are subject to the liens of second mortgages related , to pollution control revenue bonds. I l AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return ) I on the equity funds used for construction. Although AFUDC increases utility plant and increases earmngs, it is only realized in cash through depreciation provisions included in rates. LP&L's effective composite rates for AFUDC were 10.4%,10.7%, and 10.6% for 1993,1992, and 1991, respectively. l Utility plant includes the portions of Waterford 3 that were sold and are currently under lease. LP&L 1 retired this propeny from its continuing propeny records as formerly owred property released from and no longer subject to LP&L's first mongage indenture. LP&L is reflecting such leased propeny for financial reporting purposes as property under lease from others and depreciating this property over the life of the plant. See Note 9 for additionallease disclosure. Depreciation is computed on the straight-line basis at rates based on the estunated service lives and costs of removal of the various classes of property. Depreciation provisions on average depreciable propeny approximated 1 3.0% in 1993 and 2.9% in 1992 and 1991. Income Taxes LP&L, its parent, and affiliates (excluding GSU prior to 1994) file a consolidated federal income tax return. Income taxes are allocated to LP&L in proportion to its contribution to consolidated taxable income. SEC regulations require that no System company pay more taxes than it would have had a separate income tax return been filed. Deferred taxes are recorded for all temporary differences between book and taxable income. Investment tax credits are deferred and amortized based upon the average useful life of the related property in accordance with rate treatment. As discussed in Note 3, effective January 1,1993, LP&L changed its accounting for income taxes to conform with SFAS 109.
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LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) Rescouired Debt The premiums and costs associated with reacquired debt are being amortized over the life of the related new issuances, in accordance with ratemaking treatment. Cash and Cash Eauivalents LP&L considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Fair Value Disclosure The simM fair value amounts of financial instruments have been determined by LP&L, using available market information and appropriate valuation methodologies. However, considerable judgment is required in developing the estimates of fair value. Therefore, estunates are not necessarily indicative of the amounts that LP&L could realize in a current market exchange. In addition, gains or losses reahzed on financial instmments may be reflected in future rates and not accrue to the benefit of stockholders. LP&L considers the carrying amounts of financial in:truments classified as current assets and liabilities to be a reasonable estunate of their fair value because of the short maturity of these instmments. In addition, LP&L does not presently expect that performance ofits obligations will be required in connection with certain off-balance sheet commitments and guarantees considered financial instruments. Due to this factor, and because of the related party nature of these commitments and guarantees, determmation of fair value is not considered practicable. See Notes 5,6, and 8 for additional fair value disclosure. NOTE 2. RATE AND REGULATORY MATTERS LPSC Investiention Pursuant to an LPSC request to explain LP&L's "relatively high cost of debt" compared to other electric utilities subject to LPSC jurisdiction, LP&L sent a response to the LPSC in August 1993. In an August 1993 report to the LPSC, the LPSC's legal consultants acknowledged LP&L's rationale for its cost of debt in comparison to two other utilities subject to the LPSC's jurisdiction. Further, the legal consultants suggested that certain aspects of the LP&L cost of debt could be taken up in any rate proceedings after the expiration of LP&L's rate freeze in March 1994. In October 1993, the LPSC approved a schedule to conduct a review of LP&L's rates and rate structure upon the expiration of LP&L's current rate freeze. Waterford 3 and Grand Gulf 1 In a series of LPSC orders, court decisions, and agreements between November 1385 and June 1988, LP&L was granted Waterford 3 and Grand GulfI rate relief. In addition, LP&L, in accorac with judicial decisions and LPSC rate orders, deferred a net amount of $266 million ofits Waterford 3 costs related to the period November 14,1985 through January 31,1988. These deferred costs are being recovered over vproximately 8.6 years begmnmg in April 1988. In November 1985, LP&L agreed to permanently absorb, and not recover from its retail customers,18% of its 14% (approximately 2.52%) FERC-allocated share of the costs of capacity and energy of Grand Gulf 1. However, LP&L was allowed to recover, through the fuel adjustment clause, 4.6 cents per KWH (currently
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LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) 2.55 cents per KWH through May 1994) for the energy related to the permanently absorbed percentage, with LP&L's permanently retamed percentage to be available for sale to non-affiliated parties, subject to LPSC approval. For the year ended December 31,1993, $91 million was billed to LP&L by System Energy. March 1989 Order A March 1989 LPSC Order, which expires in March 1994, entitled LP&L to an annual increase in retail ! rates of approximately $45.9 million. Instead of a rate increase, the LPSC allowed LP&L to retam $188.6 million i of proceeds LP&L received in October 1988 as a result oflitigation with a gas supplier. %erefore, in March 1989 ' LP&L began amortazmg over a 5.3 year period, for the benefit of ratepayers, the premic plus accrued interest through February 1989. As of December 31,1993, the unamortized balance of such jurisdictional proceeds was approximately $14.6 million. LP&L believes that the March 1989 Order has provided approxunately the same amount of additional net income as would an annual rate increase of $45.9 million. LP&L agreed to a five-year base rate freeze, at the then current level, except for, among other things, recovery of certain taxes, net increases or decreases in LP&L's costs resulting from proceedmgs at FERC relating to the Grand Gulf Station, or as a result of catastrophic events. Le impact of the March 1989 Order was to increase net income in 1993,1992, and 1991 by approximately $26.1, $28.5, and $27.7 million, respectively. NOTE 3. INCOME TAXES Effective January 1,1993, LP&L adopted SFAS 109. His new standard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that deferred tax balances be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 requires that regulated enterprises recogmze adjustments resulting from implementation as regulatory assets or liabilities ifit is probable that such amounts will be recovered from or returned to customers in future rates. A substantial majority of the adjustments required by SFAS 109 was recorded to deferred tax balance sheet accounts with offsettmg adjustments to regulatory assets and liabilities. %e cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. As a result of the adoption of SFAS 109,1993 net income was reduced by $5.7 million, assets were increased by $309.7 million, and liabilities were increased by
$315.4 million. ,
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9
LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) , r Income tax expense consisted of the followmg For the Years Ended December 31. 1993 1992 1991 (In Thousands) Current: S 62,037 $ 30,326 S 5,180 Federal 8.514 6.139 3.504 State 70.551 36.465 8.684 Total Deferred - net: 54,297 53,751 56,132 Liberalized depreciation 3,474 (7,906) 489 Unbilled revenue Deferred Waterford 3 expenses (14,043) (14,043) (14,043) 2,665 (5,331) (3,659) Adjustment of prior years' tax provisions (3,632) (3,526) (3,898) Waterford 3 sale andleaseback 9,513 15,180 15,342 : Gas contract settlement (5,768) 1,989 5,485 Nuclear refueling and maintenance Materials and supplies inventory adjustments (2,505) (2,497) (841) (8,781) - 10,361 Alternative muumum tax 438 344 540 Contract deferred revenue Propertyinsurance reserve 23 3,119 (682) Deferred fuel (1,337) 2,977 (357) , (243) 4,868 64 Bond reacquisition Decontamination and decommissioning fund 5,273 - - 3.643 2.964 2.859 Other Total 43.017 51.889 67.792 Investment tax credit adjustments - net (2.755) (1.317) 8.244 i Recorded income tax expense $110.813 $ 87.037 5 84.720 S108,568 $ 83,984 S 76,104 Charged to operations 2.245 3.053 8.616 Charged to otherincome Recorded income tax expense 110,813 87,037 84,720 Income taxes applied agunst the debt
- 442 440 component of AFUDC Totalincome taxes S110.813 $ 87.479 $ 85.160
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LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) Total income taxes differ from the amounts computed by applying the statutory federal income tax rate to 4 income before taxes. The reasons for the differences were: For the Years Ended December 31. 1993 1992 1991
% of % of % of Pretaz Pretax Pretaz Amount Income Amount Income Amount income (Dollars in Thousands)
Computed at statutory rate S104,867 35.0 $ 91,809 34.0 $ 85,439 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax effect 6,727 2.2 4,272 1.6 3,797 1.5 Depreciation 2,550 0.9 3,064 1.1 3,182 1.3 Impact of change in tax rate (2,767) (0.9) (3,989) (1.5) (3,012) (1.2) Recapture of prior years' consolidated . income tax savings 573 0.2 (175) (0.1) 5,032 2.0 Amortization ofinvestment tax credits (6,876) (2.3) (6,780) (2.5) (6,561) (2.6) SFAS 109 adju.tment 4,193 1.4 - - - - Other - net 1.546 _QJ (1.164) _(QJ) (3.157) _1).1) Recorded income tax expense $ 110,813 37.0 $ 87,037 32.1 5 84,720 33.7 income taxes applied agamst the debt component of AFUDC - - 442 _ _l 440 __Ql l Total income taxes S110.813 37.0 $ 87.479 E M 33.9 Significant components of LP&L's net deferred tax liabilities as of December 31,1993, were (in thousands): Deferred tax liabilities: Net regulatory assets S (422,371) l Plant related basis differences (665,517) Rate deferrals (40,737) Bond reacquisition loss (17,368) Other (14.429) Total S(1.160.422) Deferred tax assets: Unbilled revenues S 13,190 l 72,667 l Accumulated deferred investment tax credit l Gas contract settlement 12,917 Removal cost 47,603 Alternative muumum tax credit 41,618 Standard coal plant 12,898 Waterford 3 sale / leaseback 98,541 Other 32.120 i Total 5 331.554 l i Net deferred tax liabilities S (828.868)
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l LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) ne alternative mimmum tax (AMT) credit as of Dwnber 31,1993, was $41.6 million. His AMT credit can be carried forward indefinitely and will reduce LP&L's federal income tax liability in future years. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS 3 He SEC has authorized LP&L to effect short-term borrowings up to $125 million, subject to increase to q as much as $259 million after further SEC approval. This authorization is effective through November 30,1994. As of December 31,1993, LP&L had unused lines of credit for short-term borrowings of $20.2 million from banks within its service territory. In addition, LP&L can borrow from the Money Pool, subject to its maximum authorized level of short-term borrowings and the availability of funds. LP&L had $52 million in oumanding ; borrowings under the Money Pool arrangement as of December 31,1993. l i l t i l l
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LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) NOTE 5. PREFERRED AND COMMON STOCK The number of shares and dollar value of LP&L's preferred stock was: As of December 31, Shares Call Price Per Authorized and Total Share as of Outstanding Dollar Value December 31, 1993 1992 1993 1992 1993 (Dollars in Thousands) Without sinking fund: Cumulative, $100 par value 4.96% Series 60,000 60,000 $ 6,000 $ 6,000 $104.25 4.16% Series 70,000 70,000 7,000 7,000 $104.21 4.44% Series 70,000 70,000 7,000 7,000 $104.06 5.16% Series 75,000 75,000 7,500 7,500 $104.18 5.40% Series 80,000 80,000 8,000 8,000 $103.00 6.44% Series 80,000 80,000 8,000 8,000 $102.92 7.84% Series 100,000 100,000 10,000 10,000 $103.78 7.36% Series 100,000 100,000 10,000 10,000 $103.36 8.56% Series 100,000 100,000 10,000 10,000 $103.14 Cumulative, $25 par value 8.00% Series (1) 1,480,000 1,480,000 37,000 37,000 - 9.68% Series (1) 2.000.000 2.000.000 50.000 50.000 - Total without sinking fund 4.215.000 4.215.000 $160.500 $160.500 With sinking fund: Cumulative, $100 par value 7.00% Series (1) 500,000 500,000 $ 50,000 $ 50,000 - 8.00% Series (1) 350,000 350,000 35,000 35,000 - Cumulative, $25 par value 10.72% Series 390,211 630,211 9,755 15,755 $26.34 13.12% Series 61,121 221,121 1,528 5,528 $26.64 14.72% Series 416 200,416 10 5,010 $26.84 12.64% Series 1.200.370 1.500.370 30.009 37.509 $27.37 . Total with sinking fund 2.502.118 3.402.118 $126.302 5148.802 (1) These series are not redeemable as of December 31,1993. The fair value of LP&L's preferred stock with sinking fund was estunated to be approximately $141.9 million and $171.5 million as of December 31,1993 and 1992, respectively. The fair value was determined using quoted market prices or estunates from nationally recogmzed investment bankmg firms. See Note I for additional information on disclosure of fair value of fmancial instruments. As of December 31,1993, LP&L had 2,195,000 and 6,320,000 shares of cumulative, $100 and $25 par value preferred stock, respectively, that were authorized but unissued.
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i i LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) : 1 Changes in the common stock and preferred stock, with and without sinking fund, during the last three years were: ' Number of Shares 1993 1992 ,,, 1991 ; i Common stock issuances
- - 15,168,800 Preferred stock issuances. '
$100 par value - 500,000 350,000
$25 par value - 1,480,000 2,000,000 j Preferred stock retirements:
$100 par value - (370,000) (350,000) !
$25 par value (900,000) (1,015,160) (1,020,000)
Cash sinkmg fund requirements for the next five years for preferred stock outstandmg as of December 31,1993 are (in millions): 1994 - $8.3; 1995 - $6.8; 1996 - 56.8; 1997 - 54.5; and 1998 - $3.8. LP&L has the annual non-cumulative option to redeem, at par, additional amounts of certain senes of its ou'*aadia: l preferred stock. t LP&L has SEC authorization for the issuance and sale, through December 31,1994, of up to $285 mdhon ; of preferred stock (of which $113 million r==iaad avadable as of December 31,1993). The proceeds would be used for the refinancing of higher cost debt and preferred stock and general compur.es purposes LP&L has SEC ; authorization through December 31,1994 for the acquisition, in whole or in past, of up to $75 million aggregate l par value of certain oute=ading series ofits preferred stock. l NOTE 6. LONG-TERM DEBT ; LP&L's long-term debt as ofI'+:r ='=r 31,1993 and 1992, was: Maturities Interest Rates Er.g.gg Ig_ r Erggg _Ig_ 1993 1992 (In Thousands) First Mortgage Bonds 1994 1998 4-5/8% 10.36 % $ 204,000 S 204,000 ., 1999 2003 7-1/2% 9-3/8% 361,520 306,520 j 2004 2006 8-3/4% - 52,767 j 2020 2022 8-1/2% 10-1/8 % 185,000 185,000 Governmental Obligations
- 1993- 2008 6-2/5% 8% 37,794 15,520
'2009 2023 5.95 % 81/4% 350,000 314,589 Long-Tenn Obligation - Purchase Agreement - 21,737
' Waterford 3 Lease Obligation,8.76% (Note 9) 353,600 353,600 Unamortized Premium and Discount - Net (8.973) (6.511)
Total Long-Term Debt 1,482,941 1,447,222' Less Amount Due Within One Year - 25.315 1.275 , Long-Term Debt Excluding Amount Due Within One Year $ 1.457.626 $ 1.445.947 l
- Consists of pollution control bonds and municipal revenue bonds, certam series of which are secured by non-interest bearmg first mortgage bonds
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LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued)
'Ihe fair value of LP&L's long-term debt, excluding Waterford 3 lease obligation and long-term Purchase Agreement, as of December 31,1993 and 199? r. .:: estunated to be $1,205.1 million and $1,123.0 million, respectively. The fair value was determind using quoted market prices or estunates from nationally recogmzed investment banking firms. See Note i for additional information on disclosure of fair value of financial mstruments.
For the years 1994,1995,1996,1997, and 1998, LP&L has long-term debt maturities and cash sinking fund requirements of(in millions): $25.3, $75.3, $35.3, $34.3, and $35.3, respectively. In addition, other sinking fund requirements of approximately $6 million annually may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements. LP&L has SEC authorization for the issuance and sale through December 31,1994, of up to $625 million of Srst mortgage bonds (of which $256 million remamed available as of December 31,1993) and to enter into agreements, subject to meeting certain conditions, with the Parish of St. Charles, Louisiana (Parish) whereby the Parish would issue and sell up to $250 million of tax-exempt revenue bonds (of which $98 million remamed available as of December 31,1993) in order to reimburse LP&L for, or to permanently finance, the costs of certain solid waste disposal, sewage disposal, and/or air or water pollution control facilities. LP&L also has SEC authorization for the acquisition, in whole or in part, through December 31,1994 and prior to their respective maturities, (1) up to $436 million ofits outstanding first mortgage bonds, including, but not limited to, the 10.36% Series due December 1,1995, and (2) up to $75 million of outstandmg pollution control revenue bonds, including, but not limited to, the 8.25% St. Charles Parish Pollution Control Revenue Bonds, Series 1984 due 2014, and the 8% Second Series 1984 Bonds due 2014. NOTE 7. DIVIDEND RESTRICTIONS LP&L's Restated Articles of Incorporation, as amended, and certain of its indentures, contain prosisions restricting the payment of cash dividends or other distributions on common stock. As of December 31,1993, none of LP&L's retained earnmgs were restricted against the payment of cash dividends or other distributions on common stock. On February 1,1994, LP&L paid Entergy Corporation a $17.9 million cash disidend on common stock. NOTE 8. COMMITMENTS AND CONTINGENCIES Canital Reouirements and Financine Construction expenditures (excluding nuclear fuel) for the years 1994,1995, and 1996 are estimated to total $156 million, $143 million, and $142 million, respectively. LP&L will also require $158 million during the period 1994 - 1996 to meet long-term debt and preferred stock maturities and cash sinking fund requirements. LP&L plans to meet the above requirements with internally generated funds and cash on hand, supplemented by the issuance of debt and preferred stock. See Notes 5 and 6 regarding the possible refunding, redemption, purchase or other acquisition of certain outstanding series of preferred stock and long-term debt. Unit Power Sales Aereement System Energy has agreed to sell all ofits 90% owned and leased share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in accordance wis specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this agreement are paid in consideration for
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LOUISIANA POWER & LIGIIT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) LP&L's respective entidement to receive capacity and energy, and are payable irrespective of the quantity of energy delivered so long as the unit remams in commercial operation. The agreement will remam in effect until termmated by the parties and approved by FERC, most likely upon Grand Gulf l's retirement from service. LP&L's monthly obligation for pa ments under the agreement is approximately 58 million. Availability Aereement AP&L, LP&L, MP&L, and NOPSI are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 24.7%) in amounts that when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy's operating expenses. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Payrnents or advances ander the Availability Agreement are only required if funds available to System Energy from all sources are less than the amount required under the Availability Agreement. Since commercial operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments have ever been required. In 1989, the Availability Agreement was amended to pro 5id: that the write-off of $900 million of Grand Gulf 2 costs would be amortized for Availability Agreement purposes over a period of 27 years, in order to avoid the need for payments by AP&L, LP&L, MP&L, and NOPSL If AP&L, MP&L, or NOPSI fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, LP&L could be liable for payments to System Energy, in amounts that cannot be determined, over and above its payments under the Unit Power Sales Agreement. Reallocation Aereement System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation Agreement relating to the sale of capacity and energy from the Grand Gulf Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and obligations with respect to the Grand Gulf Station under the Availability Agreement. FERC's decision allocatmg a portion of Grand Gulf I capacity and energy to AP&L supersedes the Reallocation Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect AP&L's obligation to System Energy's lenders under the assignments referred to in the precedmg paragraph. AP&L would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual obligations. No payments of any amortization amounts will be required as long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future. System Fuels LP&L has a 33% interest in System Fuels, a jointly owned subsidiary of AP&L, LP&L, MP&L, and NOPSI The parent companies of System Fuels, including LP&L, agreed to make loans to System Fuels to finance its fuel procurement, delivery, and storage activities. As of December 31,1993, LP&L had approximately
$14.2 million of loans outstanding to System Fuels which mature in 2008.
In addition, System Fuels entered into a revohing credit agreement with a bank that prosides $45 million in borrowings to finance System Fuels' nuclear materials and senices inventory. Should System Fuels default on its obligations under its credit agreement, AP&L, LP&L, and System Energy have agreed to purchase the nuclear materials and senices financed under the agreement.
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l i l LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) Lone-Term Contracts LP&L has a long-term agreement through 2031 to purchase energy generated by a hydroelectric facility. During 1993,1992, and 1991, LP&L made payments under the contract of approximately $73.1 million, $39.1 million, and $43.2 million, respectively. If the maximum percentage (94%) of the energy is made available to LP&L, current production projections would require estunated payments of approximately $47 million per year through 1996, $54 million in 1997, and a total of $3.5 billion for the years 1998 through 2031. LP&L recovers the costs of purchased energy through its fuel adjustment clause. In June 1992, LP&L agreed to a renegotiated 20-year natural gas supply contract. LP&L has agreed to purchase natural gas in annual amounts equal to approxunately one-third of its projected annual 1Ui requirements for certain generating units. Annual demand charges associated with this contract are estunated to be $9 million through 1997, and a total of $124 million for the years 1998 through 2012. LP&L recovers the cost of fuel consumed during the generation of electricity through its fuel adjustment clause. Nuclear insurance The Price-Anderson Act limits public liability for a single nuclear incident to approxunately $9.4 billion, as of December 31,1993. LP&L has protection for this liability through a combination of printe insurance (currently $200 million) and an industry assessment program. Under the assessment program, the maximum amount that would be required for each nuclear incident would be $79.28 million per reactor, pa>2ble at a rate of
$10 million per licensed reactor per incident per year. LP&L has one licensed reactor. In addition, LP&L participates in a private insurance program which provides coverage for worker tort claims filed for bodily injury caused by radiation exposure. LP&L's maxunum assessment under the program is an aggregate of approximately $3.1 million in the event losses exceed accumulated resene funds.
LP&L is a member of certain insurance programs that provide coverage for property damage, including decontammation and premature dw umissioning expense, to members' nuclear generatmg plants. As of December 31,1993, LP&L was insured agamst such losses up to $2.7 billion, with $250 million of this amount designated to cover any shortfall in the NRC required decomnussioning trust fundmg In addition, LP&L is a member of an insurance program that covers certain costs of replacement power and business interruption incurred due to prolonged nuclear unit outages. Under the property damage and rephcemas power / business interruption insurance programs, LP&L could be subject to assessments iflosses exceed the accumulated funds available to the insurers. As of December 31,1993, the maxunum amount of such possible assessments to LP&L was
$24.34 million.
The amount of property insurance presently carried by LP&L exceeds the Nuclear Regulatory Commission's (NRC) muumum requirement for nuclear power plant licensees of $1.06 billion per site. NRC regulations provide that the proceeds of this insurance must be used, first, to place and maintain the reactor in a safe and stable condition and, second, to complete decontammation operations. Only after proceeds are dedicated for such use and regulatory approval is secured, would any remammg proceeds be made available for the benefit of plant owners or their creditors. Spent Nuclear Fuel and Decommissionine Costs LP&L provides for estimated future disposal costs for spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. LP&L entered into a contract with the DOE, whereby the DOE will furnish disposal senice at a cost of one mill per net KWH generated and sold after April 7,1983. 'Ihe fees paysble to the DOE may be adjusted in the future to assure full recovery. LP&L considers all costs incurred or to be incurred, except ,
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LOUISIANA POWER & LIGIIT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) accrued interest, for the disposal of spent nuclear fuel to be proper components of nuclear fuel expense and provisions to recover such costs have been accepted by the LPSC. Due to delays of the DOE's repository program for the acceptance of spent nuclear fuel, it is curtain when shipments of spent fuel from LP&L will commence. In the meantime, LP&L is responsible for spent fuel storage. Current on-site spent fuel storage capacity at Waterford 3 is estimated to be sufficient until 2000. Thereafter, LP&L will provide additional storage capacity at an estunated initial cost of $5.0 million to
$10.0 million. In addition, approxunately $3.0 million to $5.0 million will be required every four to five years subsequent to 2000 until the DOE's repository begins accepting Waterford 3's spent fuel.
Decommissioning costs for Waterford 3 were estimated to be S203.0 million (in 1988 dollars), based on a 1988 update to the original cost study. LP&L had LPSC authorization to fund and recover S4.0 million of decommissioning costs annually through 1993, based on the 1988 study update. LP&L will begin funding
$4.8 million in 1994 in anticipation of a 1994 study update and a related LPSC review and determmation of appropriate funding levels. These amounts are deposited in an external trust fund which has a market value of $23.5 million and $17.4 million as of December 31,1993 and 1992, respectively. The accumulated decommissioning liability of $22.1 million as of December 31, 1993 has been recorded in accumulated depreciation. Decommissioning expense in the amount of $4.0 million was recorded in 1993. He actual decommissioning costs may vary from the above eem* because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment, and management believes that actual decommissioning costs are likely to be higher than the amounts presented above.
He Energy Act has a provision that assesses domestic nuclear utilities with fees for the decontammation and decommissioning of the DOE's past uranium enrichment operations. The decontanunation and decommissioning assessments will be used to set up a fund into which contributions from utilities and the federal government will be placed. LP&L's annual assessment, which will be adjusted annually for inflation, is $1.2 million (in 1993 dollars) annually for approximately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortized he cumulative liability of $17.1 million at December 31,1993 is recorded in other current liabilities and other noncurrent liabilities, according to FERC guidelines, and is offset in the financial statements by a regulatory asset, recorded as a deferred debit. NOTE 9. LEASES General As of December 31,1993, LP&L had noncancelable operating leases with muumum lease payments as follows (in thousands): 1994 S 4,024 1995 3,844 1996 3,706 1997 3.644 1998 3,549 Years thereafter 6.717 Minimum lease payments $25.484 Rental expense for operating leases amounted to approximately $6.6 million, 58.7 million, imd $8.6 million in 1993,1992, and 1991, respectively.
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LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) Nudear Fuel Lent LP&L has an arrangement to lease nuclear fuel in an amount up to $95 million. He lessor fmances its acquisition of nuclear fud through a credit agreement and the issuance of notes. He credit agreement, which was entered into in 1989, has been nW to January 1997 and the notes have varying remammg maturities of up to 5 years. It is expected that the credit arrangement will be extended or altemative financing will be secured by the lessor upon the maturity of the current arrangements. If the lessor cannot arrange for alternative financing upon maturi+y of its borrowings, LP&L must purchase nuclear fuel in an amount sufficient to enable the lessor to retire such borrowings. Lease payments are based on nuclear fuel use. Nuclear fuel lease expense of $39.9 million, $38.3 million, and $39.8 million (including interest of $4.9 million, 55.4 million, and $7.5 million) was charged to operations in
- l 1993,1992, and 1991, respectively.
Waterford 3 Lesse Obliestions On September 28,1989, LP&L entered into three substantially identical, but entirely separate, transactions for the sale (for an aggregate cash consideration of $353.6 million) and leaseback of three undisided portions ofits 100% ownership interest in Waterford 3. He three undivided interests in Waterford 3 sold and leased back exclude certain transmission, pollution control, and other facilities that are part of Waterford 3. He interests sold and leased back, as described above, are equivalent on an aggregate cost basis to approximately 9.3% of Waterford 3. He sales were made to an Owner Trustee under three separate, but identical, tmst agreements with three Owner Participants. LP&L is leasing back the sold interests from the Owner Trustee on a net lease basis over an approximate 28-year basic lease term. LP&L has options to terminate the lease and to repurchase the sold interests in Waterford 3 at certain intervals during the basic lease term. Further, at the end of the basic lease term, LP&L has an option to renew the lease or to repurchase the undisided interests in Waterford 3. The Owner Trustee acquired the interests with funds provided by the Owner Participants and with funds obtamed from the issuance and sale by the Owner Trustee of intermediate-term and long-term bonds. He lease payments to be made by LP&L will be sufficient to service the debt incurred by the Owner Trustec. If LP&L does not exercise its option to repurchase the undivided interests in Waterford 3 on the fifth anniversary (September 1994) of the closing date of the sale and leaseback transactions, LP&L will be required to provide collateral to the Owner Participants for the equity portion of certain amounts payable by LP&L under the lease. Such collateral requirements are to be in the form of either a bank letter of credit or the pledge of new series of first mortgage bonds issued by LP&L under its first mortgage bond indenture. Upon the occurrence of certain adverse events (including lease events of default, events ofloss, deemed loss events or certain adverse " Financial Events" with respect to LP&L), LP&L may be obligated to pay amounts sufficient to permit the Owner Participants to withdraw from the lease transactions and LP&L may be required to assume the outstanding bonds issued by the Owner Trustee to finance its acquisition of the undisided interests in Waterford 3. " Financial Events" include, among other things, failure by LP&L, following the expiration of any applicable grace or cure periods, to maintain (1) as of the end of any fiscal quarter, total equity capital (including preferred stock) at least equal to 30% of adjusted capitalization, or (2) in respect of the 12-month period ending on the last day of any fiscal quarter, a fixed charge coverage ratio of at least 1.50. As of December 31,1993, LP&L's total equity capital (includmg preferred stock) was 48.59% of adjusted capitalization and its fixed charge coverage ratio was 3.18.
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LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) In accordance with SFAS No. 98, " Accounting for Leases," due to " continuing involvement" by LP&L, the sale and leaseback by LP&L of the undivided portions of Waterford 3, as described above, are required to be reflected for fmancial reporting purposes as fmancing transactions in LP&L's fmancial statements even though such portions are no longer owned by LP&L. See Note 1 for further information regarding fmancial reporting treatment. As of December 31,1993, LP&L had future nummum lease payments (reflecting an overall implicit rate of 8.76%) in connection with the Waterford 3 sale and leaseback transactions as follows (in thousands): 1994 S 32,568 1995 32,569 1996 35,165 1997 39,805 1998 41,447 Years thereafter 726.744 Minimum lease payments $908.298 NOTE 10. POSTRETIREMENT BENEFITS Pension Plan LP&L has a defmed benefit pension plan covering substantially all ofits employees. The pension plan is noncontributory and provides pension benefits based on employees' credited service and average compensation, generally during the last five years before retirement. LP&L funds pension costs in accordance with contribution guidelines established by the Employee Retirement income Security Act of 1974, as amended, and the Intemal Revenue Code of 1986, as amended. The assets of the plan consist prunarily of common and preferred stocks, fixed income securities, interest in a money market fund, and insurance contracts Effective October 1,1988, LP&L amended its plan to designate NOPSI as a participating employer. LP&L's pension expense allocation policy results in substantially the same expense as that which would have been recorded if LP&L had not designated NOPSI as a participating employer. Pension costs are allocated to NOPSI based on an evaluation determined by an independent actuary. i Effective June 6,1990, LP&L's V/aterford 3 nuclear employees became employees of Entergy Operations, i However, the employees still remain under LP&L's plan, and no transfers of related pension liabilities and assets have been made. i i LP&L's 1993,1992, and 1991 pension cost, including amounts capitalized, included the following j l components: For the Years Ended December 31. , i 1993 1992 1991 (In Thousands) Service cost - benefits earned during the period S 4,900 $ 4,307 S 4,102 ) Interest cost on projected benefit obligation 14,684 14,110 13,121 l Actual return on plan assets (26,533) (14,329) (38,644) l Net amortization and deferral 8,712 (3,113) 21,940 Other - - 559 Net pension cost S 1.763 S 975 $ 1.078
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LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) i ne funded status of LP&L's pension plan as of December 31,1993 and 1992, was (excluding amounts allocable to NOPSI): 1993 1992 (In Thousands) Actuanal present value of accumulated pension plan benefits:
$179,049 S160,001 Vested 768 558 Nonvested S179.817 5160.559 Accumulated benefit obligation
$224,203 $209,667 Plan assets at fair value 211.928 183.985 Projected benent obligation 12,275 25,682 Plan assets in excess of projected benefit obligation 6,257 6,723 Unrecogmzed prior service cost (22,460) (25,268)
Unrecogmzed transition asset (5.734) (15.036) Unrecogmzed net gain (9,662) (7,899) (12.256) (23.161) Unfunded portion of NOPSI pension liability 5(21.918) $ (31.060) Accrued pension liability He signi6 cant actuarial assumptions used in computing the information above for 1993,1992, and 1991 were as follows: weighted average discount rate,7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in future compensation levels, 5.6%; and expected long-term rate of return on plan assets, 8.5%. Transition assets are being amortized over 15 years. Other Postretirement Benefits > LP&L also provides certain health care and life insurance benefits for retired employtes. Substantially all employees may become eligible for these benefits if they reach wiuw. cat age while still working for LP&L. The cost of providing these benefits, recorded on a cash basis, to reurecs in 1992 was approxunately $3.7 million. Prior to 1992, the cost of providing these benefits for retuees was not separable from the cost of prosiding benefits for active employees. Based on the ratio of the number of retired employees to the total number of active and retired employees in 1991, the cost of providing these benefits in 1991, recorded on a cash basis, for retirees was approximately $3.5 million. Effective January 1,1993, LP&L adopted SFAS 106. He new standard requires a change from a cash method to an accrual method of accounting for postretirement beneSts other than pensions. LP&L continues to fund these benefits on a pay-as-you-go basis. As of January 1,1993, the actuanally determmed accumulated postretirement benefit obligation (APBO) camed by retirees and active employees was estunated to be approximately $59.4 million. His obligation is being imortized over a 20-year period begmnmg in 1993. He LPSC ordered LP&L to use the pay-as-you-go method for rate =Wg purposes for postretirement benefits other than pensions, but the LPSC retams the flexibility to exanune indisidual companies' accounting for postretirement bene 6ts to determine if special exceptions to this order are warranted. LP&L's net income in 1993 was decreased by approximately $4.2 million as a result of adopting SFAS 106.
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I LOUISIANA POWER & LIGIIT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) LP&L's 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components (in thousands): Senice cost - benefits earned during the period $2,083 Interest cost on APBO 4,749 Actual return on plan assets - Amortization of transition obligation 2.971 Net periodic postretirement beneSt cost $9.803 The funded status of LP&L's postretirement plan as of December 31,1993, was as follows (in thousands): Accumulated postretirement benefit obligation: Retirees S41,769 Other fully eligible participants 6,825 Other active participants 21.085 69,679 Plan assets at fair value - Plan assets less than APBO (69,679) Unrecorpuzed transition obligation 56,459 Unrecogmzed net loss 7.579 Accrued post retirement benefit liability S (5.641)
'Ihe assumed health care cost trend rate used in measuring the APBO was 9.9% for 1994, gradually decreasing each successive year until it reaches 5.6% in 2020. A one percentage-point increase in the assumed health care cost trend rate for each year would have increased the APBO as of December 31,1993, by 9.1% and the sum of the senice cost and interest cost by approximately 11.8%. 'Ihe assumed discount rate and rate of increase in future compensation used in determmmg the APBO were 7.5% and 5.5%, respectively.
NOTE 11. TRANSACTIONS WITH AFFILIATES LP&L buys electricity from and/or sells electricity to AP&L, MP&L, NOPSI, and System Energy under l rate schedules filed with FERC. In addition, LP&L purchases fuel from System Fuels, receives technical and advisory senices from Entergy Senices, Inc. and receives operating senices from Entergy Operations. I Operating revenues include revenues from sales to affiliates amounting to $4.8 million in 1993,
$5.5 million in 1992, and $0.2 million in 1991. Operating expenses include charges from affiliates for fuel costs, !
purchased power and related charges, management senices, and technical and adsisory senices totaling :
$322 mi!! ion in 1993, $314.3 million in 1992, and $327.9 million in 1991. LP&L pays directly or reimburses !
Entergy Operations for the costs associated with operating Waterford 3 (excluding nuclear fuel), which were i approximately $118.9 million in 1993, $152.1 million in 1992, and $151.1 million in 1991.
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LOUISIANA POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Concluded) , NOTE 12. QUARTERLY FINANCIAL DATA (UNAUDITED) LP&L's business is subject to seasonal fluctuations with the peak period occurring during the third quarter. Operating results for the four quarters of 1993 and 1992 were: Operating Operating Net Revenues Income 18192 1 (In Thousands) 1993:
$357,856 5 56,875 S25,733 First Quarter $46,932
$399,570 $ 79,472 Second Quarter
$545,487 $124,789 $92,287 Third Quarter $23,856
$426,753 $ 60,476 Fourth Quarter 1992:
$336,588 5 59,585 S25,366 First Quarter $46,560
$364,694 $ 81,679 Second Quarter
$464,975 $116,797 $82,627 Third Quarter $28,436
$387,488 5 60,219 Fourth Quarter i
i
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l l LOUISIANA POWER & LIGHT COMPANY SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1993 1992 1991 1990 1989 , (In Thousands) 1 Operating revenues $1,729,666 51,553,745 $1,528,934 51,485,572 $1,426,806 Net income $ 188,808 5 182,989 $ 166,572 S 155,049 $ 106,613 Total assets $4,463,998 $4,109,148 $4,131,751 $4,262,124 $4,280,474 Long-term obligations (1) $1,611,436 $1,622,909 $1,582,606 $1,867,369 $1,915,286 (1) Includes long-term debt (excluding currently maturing debt), preferred stock with sinking fund, and l noncurrent capital lease obligations. See Notes 3 and 10 for the effect of accounting changes in 1993. 1993 1992 1991 1990 1989 (Dollars in Thousands) Operatmg Revenues: Residential S 572,738 5 518,255 5 525,594 5 520,800 $ 496,800 Commerciai 345,254 320,688 318,613 314,700 305,600 Industrial 652,574 578,741 558,036 532,800 541,200 Governmental 29.723 27.780 28.303 26.500 25.800 Total retail 1,600,289 1,445,464 1,430,546 1,394,800 1,369,400 Sales for resale 49,388 38,632 31,997 41,800 38,100 Other 79.989 69.649 66.391 49.000 19.300 Total $1.729.666 $1.553.745 $1.528.934 $1.485.600 $1.426.800 Billed Electric Energy Sales (Millions of KWH): Residential 7,368 6,996 7,182 7,169 6,865 Commercial 4,435 4,307 4,367' 4,299 4,175 Industrial 15,914 15,013 14,832 14,170 14,025 Governmental 398 385 405 382 352 Total retail 28,115 26,701 26,786 26,020 25,434 Sales for resale 1.325 1.305 1.201 1.149 1.014 Total 29.440 28.006 27.987 27.169 26.448
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Mississippi Power & Light Company /1993 Financial Statements l i
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MISSISSIPPI POWER & LIGHT COMPANY. 1 DEFINITIONS f Certain abbreviations or acronyms used in MP&L's Financial Statements, Notes to Financial Statements, and Management's Financial Discussion and Analysis are defined below: Abbreviation or Acronym Ig_rm i AFUDC Allowance for Funds Used During Construction AP&L Arkansas Power & Light Company Entergy or System Entergy Corporation and its various direct and indirect subsidiaries , FASB Financial Accounting Standards Board , FERC Federal Energy Regulatory Comminion Final Order on Reheanng An order issued by the MPSC on September 16, 1985, with respect to l MP&L's Grand Gulf 1-related rate issues G&R Bonds General and Refundmg Mortgage Bonds issued and issuable under i MP&L's G&R Mo tgage dated as of February 1,1988, as anmind ' G&R Mortgage General and Refundmg Mortgage established by MP&L effective February 1,1988, to provide for issuances of G&R Bonds t Grand Gulf Station Grand Gulf Steam Electric CA.Eing Station Grand Gulf 1 Unit No.1 of the Grand Gulf Station .
- Grand Gulf 2 Unit No. 2 of the Grand Gulf Station !
GSU Gulf States Utilities Company (including wholly owned subsidianes - [ Varibus Corporation, GSGAT, Inc., Prudential Oil and Gas, Inc., and t Southern Gulf Railway Company) Independence Station Independence Steam Electric Generatmg Station l KWH Kilowatt-Hours { i LP&L Louisiana Power & Light Company ; I MWH Megawatt-Hours l Merger. He combination transaction, consummated on December 31,1993, by , which GSU became a subsidiary of Entergy Corporation and Entergy Corporation became a Delaware Corporation , i
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h _,_ ., ,, . m.
_ , _ _~ _ _ . _ __ . - . ._ _. O MISSISSIPPI POWER & LIGHT COMPANY DEFINITIONS -(Concluded) Abbreviation or Acronym I.tDR Money Pool Entergy Money Pool, which allows certain System ewa alaa to borrow from, or lend to, certain other System compames l f MP&L' MississippiPower & Light Company MPSC Mississippi Public Semcc C=W==ica . NOPSI New Orleans Public Semcc Inc. Omnibus Budget P m h Act of 1993 OBRA-MP&L's Grand Gulf 1-related rate phase-in plan, originally approved by ' Revised Plan the MPSC in the Final Order on Rehanng, as modi 6ed by the MPSC order issued September 29,1988, to bring such plan into compliance with the requirements of SFAS No. 92 C Securities and LA 7 ommission SEC Statement of Financial Accerea: Standards promulgated by the FASB SFAS SFAS No.106," Employers' A:+- - g for Postretirement Bene 6ts Other , SFAS 106 Than Pensions" SFAS No.109, "Acceneag for Income Taxes" SFAS 109 j System Energy System Energy Resources,Inc. i System Fuels System Fuels, Inc. Entergy Corporation and its vanous direct and indirect subsidistics System or Entergy AP&L, GSU, LPAL, MP&L, and NOPSI, collectively : System operatmg 9:-- f=?== t i
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l 4 i 220-et w w - s, ---r
l l MISSISSIPPI POWER & LIGHT COMPANY REPORT OF MANAGEMENT The management of Mississippi Power & Light Company has prepared and is responsible for the financial statements and related En=dal information included herein. He financial statements are based on generally j accepted accounting principles. Financial information included elsewhere in this report is consistent with the l financial statements. To meet iu responsibilities with respect to financial information, management maintains and enforces a l system ofinternal accounting controls that is designed to provide reasonable assurance, on a cost-effective basis, as l j to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets. This system j l includes communication through written policies and procedures, an employte Code of Conduct, and an ! l organizational structure that provides for appropriate division of responsibility and the trammg of personnel. His l system is also tested by a comprehensive internal audit program 1 l l He independent public accountants provide an objective assessment of the degree to which management meets its responsibility for fairness of financial reporting. Rey regularly evaluate the system of internal accounting controls and perform such tests and other procedures as they deem necessary to reach and express an ; j l opinion on the fairness of the financial statements. Management believes that these policies and procedures provide reasonable assurance that its operations are carried out with a high standard of business conduct. I EDWIN LUPBERGER GERALD D. MCINVALE . l Chairman and Chief Executive Officer Senior Vice President and l' Chief Financial Officer l; l l I
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1 j
MISSISSIPPI POWER & LIGHT COMPANY AUDIT COMMITTEE CHAIRMAN'S LETTER The Mississippi Power & Light Company Audit Committee of the Board of Directon, a comprised of four directors, who are not officers of MP&L: John O. Emmerich, Jr. (Chairman), John N. Palmer, Sr., Dr. Clyda S. Rent, and Robert M. Williams, Jr. The committee held four meetmgs during 1993. The Audit Committee oversees MP&L's financial reporting process on behalf of the Board of Directors and provides reasonable assurance to the Board that sufficient operatmg, accounting, and financial controls are in existence and are adequately reviewed by programs ofintemal and external audits. The Audit Committee discussed with Entergy's internal auditors and the iPt public accountants (Deloitte & Touche) the overall scope and specific plans for their respective audits, as well as MP&L's financial statements and the adequacy of MP&L's internal controls. The committee met, together and separately, with Entergy's internal auditors and independent public accountants, without management present, to discuss the results of their audits, their evaluation of MP&L's internal controls, and the overall quality of MP&L's financial reporting. ; The meetmgs also were designed to facilitate and encourage any private communication between the committee and l the internal auditors or independent public accountants. , JOHN O. EMMERICH Chairman, Audit Committec l l l
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INDEPENDENT AUDITORS' REPORT f To the Shareholders and the Board of Directors of Mississippi Power & Light Company We have audited the accompanying balance sheets of Mississippi Power & Light Company (MPAL) as of December 31,1993 and 1992, and the related statements ofincome, retamad earnings, and cash flows for each of i the three years in the period ended D-mhar 31, 1993. These Anancial statements are the responsibility of MP&L's management Our responsibility is to express an opinion on these Enancial statements based on our ; audits. We conducted our audits in accordance with generally accepted auditing wandards. Those standards
- require that we plan and perfonn the audit to obtam remumable assurance about whether the n amacial statements are free of matenal misstatement. An audit includes examuung, on a test basis, evidence supporting the amounts and disclosures in the financial statements An audit also includes assessing the =-:n: " --g principles used and significant estimates made by maangama=*. as well as evaluatmg the overall Anancial statement prenantmann We -
believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all matenal respects, the financial position of MP&L at December 31,1993 and 1992, and the results ofits +.nss and its cash flows for each of the three years in the period ended December 31,1993 in conformity with generally =~a*M accounting principles. As discussed in Note 1 to the financial statements, MP&L changed its method of accountag for revenues in 1993 and, as discussed in Notes 3 and 9 to the financial statements, in 1993 MPAL changed its nwhnds of accounting for income taxes and postretirement benefits other than pensions, respectively. DELOTITE & TOUCHE New Orleans, Louisiana February 11,1994 s
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MISSISSIPPI POWER & LIGHT COMPANY BALANCE SHEETS ASSETS December 31, 1993 1992 (In Thousands) Utility Plant (Note 1):
$1,389,229 $1,364,464 Electric 62,699 25,879 Construction work in progress 1,451,928 1,390,343 Total 577,728 549.150 ims - accumulated depreciation and amortization 874,200 841,193 Utility plant -net Other Property and Investments: I 5,531 5,531 Investment in subsidiary company - at equity (Note 8) 4,760 4.382 Other 10,291 9,913 Total Current Assets Cash and cash equivalents (Note 1):
7,999 3,438 Cash Temporary cash investments - at cost, which approxunates market ;
- 2,356 Associated companies (Note 4)
- 28,214 1 Other 7,999 34,008 Totalcash and cash equivalents 7,118 7,405 Notes receivable (Note 1)
Accounts receivable: Customer (less allowance for doubtful accounts of 33,155 29,284
$2.5 million in 1993 and $1.3 million in 1992) 7,342 3,605 Associated companies (Note 10) 3,672 4,718 Other l 57,414 -
Accrued unbilled revenues (Note 1) 8,652 7,325 Fuelinventory at average cost 20,886 21,472 Materials and supplies - at average cost 96,935 72,816 Rate deferrals (Note 2) 13,763 1,354 Prepayments and other l 256,936 181,987 Total Deferred Debits and Other Assets: 504,428 600,102 Rate deferrals (Note 2) 9,951 15,739 l Notes receivable (Note 1) 20,931 11,792 I Other 535.310 627,633 Total I $1,676,737 $1,660,726 - TOTAL See Notes to Financial Statements.
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MISSISSIPPI POWER & LIGHT COMPANY BALANCE SHEETS CAPITALIZATION AND LIABILITIES i December 31, 1993 1992 (la Thousands) Capitalization: Common stock, no par value, authorized 15,000,000 shares; issued and outstandmg 8,666,357 shares in 1993 and 1992 (Note 5) $199,326 $199,326 Capital stock expense and other (1,864) (2,716) Retained caramgs (Note 7) 236,337 230,201 Total common shareholder's equity 433,799 426,811 Preferred stock (Note 5): Without sinking fund 57,881 57,881 With sinking fund 46,770 63,270 Long-term dei,t (Note 6) 516,156 512.675 Total 1,054,606 1,060,637 Other Noncurrent Liabilities: Obligations under capitalleases 686 842 Other 6.231 2.946 Total 6,917 3,788 Current Liabilities: Currently maturing long-term debt (Note 6) 48,250 55,230 Notes payable - associated companies 11,568 - Accounts payable: Associated companies (Note 10) 29,181- 27,634 Other 12,157 8,649 Customer deposits 21,474 20,460 Taxes accrued 24,252 28,452 : Accumulated defened income taxes (Note 3) 41,758 31,842 Interest accrued 23,171 22,391 Dividends declared 1,985 2,472 Obligations under capitalleases 156 151 Other 17,147 7,745 Total 231,099 205,026 Deferred Credits: Accumulated deferred income taxes (Note 3) 311,616 346,107 Accumulated deferred investment tax 37,193 36,999 credits (Note 3) , SFAS 109 regulatory liability - net (Note 3) 23,626 - i 11,680 _ 8,169 I Other Total 384,115 391,275 ; Commitments and Contingencies (Note 8) TOTAL $1,676,737 $1,660,726 See Notes to Financial Statements. l
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MISSISSIPPI POWER & LIGHT COMPANY STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1993 1992 1991 (In Thousands) Operating Activities:
$101,743 565,036 $63,088 Net income Noncash items included in net incorre:
Cumulative effect of a change in accounting principle (32,706) - - 71,555 17,530 14,626 Change in rate deferrals (Note 2) 32,152 31,493 30,089 Depreciation and amoruzation (17,881) 18,685 30,857 Deferred income taxes and investment tax credits (928) (668) (1,302) Allowance for equity funds used during construction Changes in working capital: (11,814) (924) (3,743) Receivables (1,327) 2,061 (2,577) Fuelinventory 5,055 (14,365) (3,255) Accounts payable (4,200) 2,174 640 Taxes accrued 780 105 (2,712) Interest accrued (1,120) 1,918 230 Other working capital accounts 8,073 (4,272) 2.564 Other 149,382 118,773 128,505 Net cash flow provided by operaung activities Investing Activities: (66,404) (53,481) (58,368) Construction expenditures 928 668 1,302 Allowance for equity funds used during construction Net cash flow used in investing activities (65,476) (52,813) (57,066) Financing Activities: Proceeds from issuance of: 250,000 65,000 - l General and refunding bonds
- 25,000 -
l Common stock
- 19,777 - !
Prefemd stock Reurement of: l First mortgage bonds (204,501) (101.416) - l (55,000) - - ( Generaland refundmg bonds l Other long-term debt (230) (210) (200) Redemption ofpreferred stock (16,500) (9,500) (9,500) Diddends paid: , l (85,800) (68,400) (7,847) Common stock (9,452) (9,445) (10,322) Preferred stock 11,568 - (3,000) j Changes in short-term borrowings Net cash flow used in fmancing activities (109,915) (79,194) (30,869) l Net increase (decrease) in cash and cash equinients (26,009) (13,234) 40,570 34,008 47,242 6,672 Cash and cash equivalents at begmamg of period
$7,999 $34,008 $47,242 Cash and cash equivalents at end of period SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for: Interest net of amount capitalized $52,459 $62,727 $69,548 Income taxes $58,831 $14,866 $2,108 See Notes to Financial Statements.
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I MISSISSIPPI POWER & LIGHT COMPANY l MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS l LIQUIDITY AND CAPITAL RESOURCES l i Liquidity is important to MP&L due to the capital intensive nature of our business, which requires large investments in long-lived assets However, large capital expenditures for the construction of new generatmg capacity are not currently planned MP&L also requires significant capital resources for the periodic maturity of certain series of debt and preferred stock. Net cash flow from operations totaled $149 million, $119 million, and
$129 million in 1993,1992, and 1991, respectively. In recent years, this cash flow, supplemented by cash on hand and issuances of debt and common and preferred stock, has been sufficient to meet substantially all investmg and financing reqmrements, including capital expenditures, dividends, and debt / preferred stock maturities.- MP&L's.
ability to fund these capital requirements results, in part, from our contmued efforts to streamhne operations and ' reduce costs, as well as collections under our Grand Gulf 1 ' rate phase-in plan, which exceed the current cash requirements for Grand Gulf 1-related costs.- (In the income statement, these revenue collections are offset by the amortization of previously deferred costs, therefore, there is no effect on act income.) See Note 2, incorporated herein by .66.is.a for additional information on MP&L's rate phase-in plan. See Note 8, mcorporated herein by reference, for additional information on MP&L's capital and refinancing requirements in 1994 - 1996. Also, in , order to take advantage oflower interest and dividend rates, MP&L may continue to seni.ers high-cost debt and preferred stock prior to maturity. i Earmngs coverage tests (which are impacted by the inclusion of the cumulative effect of the change in accounting principle for accruing unbdled revenues discussed in Note 1), bondable property additions, and accumulated deferred Grand Gulf 1-related costs recorded as assets, limit the G&R Bonds and preferred stock that MP&L can issue. Based on the most restrictive applicable tests as of December 31,1993 and assummg an annual interest or dividend rate of 8%, MP&L could have issued $219 nullion of additional G&R Bonds or $548 million of ! additional preferred stock. Further, MP&L has the conditional ability to issue G&R Bonds agamst the retirement of bonds, in some cases without satisfying an earmngs coverage test. See Notes 5 and 6, incorporated herein by reference, for information on MP&L's financing activities and l Note 4, incorporated herein by reference, for information on MP&L's short-term borrowings and lines of credit. . I i [ a
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3 l MISSISSIPPI POWER & LIGHT COMPANY STATEMENTS OFINCOME For the Years Ended December 31, 1993 1992 1991 ; (In Thousands) l
$895.806 $817,650 $754,632 Operating Revenues (Notes 1,2, and 10):
1 Operating Expenses: Operation (Note 10): i Fuel for electric generation and fuel-related 140,391 112,032. 104,553 l expenses 289,016 301,912 284,868 Purchased power 110,301 104,287 98,884 l Other 42,153 37,660 l Maintenance 46,104 32,152 31,493 30,089 Depreciation and amortization 41,878 40,738 37,534 Taxes other than income taxes 33,074 21,681 29,936 Income taxes (Note 3) Rate deferrals (Note 2):
- (22,876) (53,333)
Rate deferrals 77,570 61,456 58.480 Amortization of rate deferrals 770,486 692,876 628,671 Total 1 125,320 124,774 125,%1 Operating Income Other income (Deductions): Allowance for equity funds used during 928 668 1,302 construction 948 4,562 1,525 Miscellaneous - net (3.462) (1,467) 81 Income taxes -(debit)(Note 3) (1,586) },763 2,908 Total Interest Charges: 52,100 60,709 63,628 Interest on long-term debt 3,260 3,357 4,013 Other interest - net Allowance for borrowed funds used during (663) (565) (1,860) construction 54,697 63.501 65,781 Total income before Cumulative Effect of a Change 69,037 65,036 63,088 in AccountingPrincipic Cumulative Effect to January 1,1993, of Accruing Unbilled Revenues (net ofincome taxes of
$19,456)(Note 1) 32,706 - -
101,743 65,036 63,088 Net income Preferred Stock Diddend Requirements 9,160 9,513 10.074
$92,583 $55,523 $53,014 Earnings Applicable to Common Stock _
See Notes to Financial Statements.
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MISSISSIPPI POWER & LIGHT COMPANY STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31. 1993 1992 1991 (In Thousands) Retamed Eamings, January 1 $230,201 $243,819 $199,393 I l Net income 101,743 65,036 63,088 Total 331,944 308,855 262,481
- l. Nc Dividends declared:
Preferred stock 8,964 9,513 10,074 1 Common stock 85,800 68,400 7,847 l Preferred stock expenses 843 741 741 Total 95,607 78,654 18,662 Retamed Earnmgs, December 31 (Note 7) $236,337 $230,201 $243,819 l See Notes to Financial Statements. 1 l l 1
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I 1 i 1 MISSISSIPPI POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income increased in 1993 due pnmarily to the one-time recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1, incorporated herein by reference) and its ongoing effects, i partially offset by the effects ofimplementing SFAS 109 and SFAS 106 (see Notes 3 and 9, incorporated herein by ; reference). Effective January 1,1993, MP&L began accruing as revenues the charges for energy delivered to customers but not yet billed. Electric revenues were previously recorded on a cycle-billing basis. Excluding the above mentioned items, net income for 1993 would have been $71.9 million. This $6.9 million increase is due 1 pnmarily to an increase in retail energy sales and a decrease in interest expense from the refinancing of high-cost ; debt. Net income increased in 1992 due pnmarily to increased operating revenues and decreased interest expense and income tax expense, partially offset by increased maintenance expense. Significant factors affecting the results of operations and causing variances between the years 1993 and 1992, and 1992 and 1991, are discussed under " Revenues and Sales," " Expenses," and "Other" below. Revenues and Sales See " Selected Financial Data - Five-Year Comparison," incorporated herein by reference, following the notes, for information on operating revenues by source and KWH sales. Electric operating revenues were higher in 1993 due to increased residential and commercial energy sales resulting pnmarily from a return to more normal weather as compared to milder weather in 1992. Industrial energy sales also increased due to higher sales to the rubber and plastics, petroleum refming, and petroleum pipelines sectors. Sales for resale to associated companies were higher due to changes in generation availability and requirements among AP&L, LP&L, MP&L, and NOPSI . Additionally, electric operating revenues increased due to increased fuel adjustment revenues and increased collections of previously deferred Grand Gulf 1-related costs, neither of which affects net income. These increases were partially offset by a decrease in other revenue related to MP&L's rate deferral over/under recovery which reflects adjustments for the difference between actual and estimated costs, and does not affect net income. Electric operating revenues were higher in 1992 resulting from an increase in other revenue related to MP&L's rate deferral over/under reconry and an increase in retail operating revenues due to lower fuel adjustment credits. Neither of these revenue fluctuations affected net income. Revenues from sales for resale were higher in 1992 resulting from the September 1991 one-time intra-system equalization billing adjustment. (Certain 1985-1991 l intra-system equalization billings under the System Agreement were adjusted in 1991, reducing operating revenues by approximately $10.6 million.) While total energy sales were relatively flat in 1992, increased sales for resale to nonassociated companies, resulting from changes in generation availability and requirements among AP&L, LP&L, l MP&L, and NOPSI, were offset by lower retail sales resulting from milder temperatures. Emenses Fuel for electric generation and fuel-related expenses increased in 1993 due primarily to an increase in generation requirements resulting primarily from increased energy sales, as discussed in " Revenues and Sales" above, and increased fuel costs. Rate deferrals decreased in 1993 and 1992 as the deferral period for MP&L's l l phase-in plan for Grand Gulf 1-related costs ended in 1992. Funher, the amortization of rate deferrals increased in 1993 reflecting the fact that MP&L, based on the Revised Plan, collected more Grand Gulf 1-related costs from its customers in 1993 than it recovered in 1992.
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MISSISSIPPI POWER & LIGIIT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS -(Concluded) Maintenance expense was higher in 1993 and 1992 due pnmarily to an increase in scheduled maintenance at MP&L's power plants. Total income taxes increased in 1993 due to the effect of higher pretax income, an increase in the federal income tax rate as a result of OBRA, and the effect of implementing SFAS 109. Total income taxes were lower in 1992 due pnmarily to an increase in Mimet~i mcome tax benefits related to tax depreciation resulting from certain elections made in 1991. 91htI Miscellaneous other income - net increased in 1992 due primarily to interest income in connection with the settlement of deferred coal charges from System Fuels. Interest on long-term debt decreased in 1993 due pnmarily to the continued refinancing of high-cost debt. l l 4 l
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l ( MISSISSIPPI POWER & LIGHT COMPANY MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Comoetition MP&L welcomes competition in the electric energy business and believes that a more competitive environment should benefit our customers, employees, and shareholders of Entergy Corporation. We also recognize that competition presents us with many challenges, and we have identiSed the following as our major competitive challenges: Retail and Wholesale Rate Issun Increasing competition in the utility industry brings an increased need to stabilize or reduce retail rates. The retail regulatory environment is shifting from traditional rate-base regulation to incentive-rate regulation. Incentive-rate and performance-based plans encourage efficiencies and productivity while permitting utilities to share in the results. In February 1994, the MPSC conducted a general review of MP&L's current rates and in March 1994, the MPSC issued a final order adopting a formula rate plan for MP&L that will allow for periodic small adjustments in rates based on a comparison of earned to benchmark returns and upon certain performance factors. The order also adopted previously agreed-upon stipulations of 1) a required return on equity of 11% and
- 2) certain accounting adjustments that result in a 4.3% ($28.1 million) reduction in MP&L's June 30,1993, test-year operating revenues. The MPSC's order requires MP&L to file rates designed to provide for this reduction in operating revenues for the test year on or before March 18,1994, to become effective for service rendered on or after March 25,1994. See Note 2, incorporated herein by reference, for further information.
Further in connection with the Merger, MP&L agreed with its retail regulator not to request any general retail rate increases or implement increases under the incentive plan that would take effect before November 1998, with certain exceptions. See Note 2, incorporated herein by reference, for further information. ; Retail wheeling, a major industry issue which may require utilities to " wheel" or move power from third f parties to their own retail customers, is evolving gradually. As a result, the retail market could become more { competitive. j
- i In the wholesale rate area, FERC approved in 1992, with certain modifications, the proposals of AP&L, l LP&L, MP&L, NOPSI and Entergy Power, Inc. to sell wholesale power at market-based rates and to provide to electric utilities "open access" to the System's transmission system (subject to certam requirements). GSU was later i added to the filing. Various intervenors in the proceedmg filed petitions for review with the United States Court of Appeals for the District of Columbia Circuit. FERC's order, once it takes effect, will increase marketmg opportunities for MP&L, but will also expose MP&L to the risk of loss of load or reduced revenues due to competition with alternative suppliers.
In light of the rate issues discussed above, MP&L is aggressively reducing costs to avoid potential earnings crosions that might result as well as to successfully compete by becoming a low-cost producer. To help muumize future costs, MP&L remams committed to least cost planning. In December 1992, MP&L filed a I. cast Cost Integrated Resource Plan (least Cost Plan) with its retail regulator. least cost planning includes demand-side measures such as customer energy conservation and supply-side measures such as more efficient power plants. These measures are designed to delay the building of new power plants for the next 20 years. MP&L plans to periodically file revised Least Cost Plans.
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I MISSISSIPPI POWER & LIGHT COMPANY i MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS '! SIGNIFICANT FACTORS AND KNOWN TRENDS -(Concluded) The Enerny Policy Act of 1992
'Ihe Energy Policy Act of 1992 (Energy Act) is ch= aging the transmission and distribution of electricity.
This act encourages competition and affords us the opportunities, and the risks, associated with an open and more competitive market environment. 'Ihe Energy Act increases competition in the wholesale energy market through the 1 creation of exempt wholesale generators (EWGs). The Energy Act also gives FERC the authority to order investor-owned utilities to provide transmission access to or for other utilities, including EWGs. 6 4 I i 233 -
MISSISSIPPI POWER & LIGIIT COMPANY NOTES TO FINANCIAL STATEMENTS NOTE 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES MP&L maintains accounts in accordance with FERC and other regulatory guidelines. Certain previously reported amounts have been reclassified to conform to current classifications. Revenues and Fuel Costs l Prior to January 1,1993, MP&L recorded revenues when billed to its customers with no accrual for energy ! delivered but not yet billed. To provide a better matching of revenues and expenses, effective January 1,1993, l The MP&L adopted a change in accounting principle to provide for'accmal of estunated unbilled revenues. cumulative effect of this accounting change as of January 1,1993, increased net income by $32.7 million. Had this new accounting method been in effect during prior years, net income before the cumulative effect would not have been materially different from that shown in the accompanying fmancial statements. MP&L's rate schedules include fuel adjustment clauses that allow current recovery of estimated fuel costs, with subsequent adjustments of estimates to actual Utility Plant Utility plant is stated at original cost. The original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of MP&L's utility plant is subject to the lien ofits first mortgage bond indenture and the second tien ofits G&R Mortgage bond indenture. AFUDC represents the approxunate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases utility plant and increases carmngs, it is only realized in cash through depreciation provisions included in rates. MP&L's effective composite rates for AFUDC were 11.8%,12.0%, and 10.4% for 1993,1992, and 1991, respectively. Depreciation is computed on the straight-line basis at rates based on the estunated senice lives and costs of removal of the various classes of property. Depreciation provisions on average depreciable property approximated 2.4% in 1993,2.5% in 1992, and 2.4% in 1991. Jointiv-Owned Generatine Station MP&L owns 25% of the Independence Station, a two-unit, coal-fired generating station located near Newark, Arkansas The total capability ofIndependence Station is 528 megawatts. MP&L records its investment in and expenses associated with this station to the extent ofits ownership and participation. MP&L's investment in the Independence Station was approximately $219.8 million less accumulated depreciation of approximately
$67.3 million as of December 31,1993.
f Notes Receivable l MP&L currently has a program, wherein it finances heat pumps for its customers through notes receivable. Such notes are repayable in equal monthly installments of principal and interest over a five-year period and bear intercst at a market-based rate at the time of sale. The amounts financed are classified on its balance sheet as current and noncurrent notes receivable.
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l l i MISSISSIPPI POWER & LIGHT COMPANY l NOTES TO FINANCIAL STATEMENTS -(Continued) Income Taxes i MP&L, its parent, and affihates (exdding GSU prior to 1994) file a consohdated federal mcome tax . return. Income taxes are allocated to MPAL in proportion to its contribution to consohdated taxable in=ne. SEC : f regulations require that no System compmy pay more taxes than it would have had a separate income tax return been filed. Deferred taxes are recorded fcir all temporary differences between book and taxable income. Investment ; tax credits are deferred and amortized based upon the average useful life of the related property, in acs44.s4 with ) rate treatment. As discussed in Note 3, effective January 1,1993, MP&L changed its =eraa'*ia= for income taxes i to conform with SFAS 109. l In addition, MP&L files a consolidated Minissippi state mcome tax return with certam other System companies. i Cash and Cash Eauivalents ; MP&L considers all unrestricted highly liquid debt mstruments purchased with an original maturity of ; three months or less to be cash equivalents Fair Value Disclosure ! The ~*i==*ad fair value amounts of financial instruments have been determmed by MP&L, using svadable i market information and appropriate valuation matkadalogies. However, considerable judgment is required in ! developing the estunates of fair value. Therefore, estunates are not necessarily =<hentive of the amounts that ! MP&L could realize in a current market avch= age In addition, gains or losses reshmi on fmanm=1 mstruments i may be reflected in future rates and not accrue to the bene 6t of stockholders. ; MP&L considers the carrymg amounts of financial instnaments classified as current assets and liabilities to be a reasonable estunate of their fair value haranea of the short maturity of these instruments In =ddMaa, MP&L - ! does not presently expect that performance ofits obligations will be required in connection with certam off-balance I sheet commitments and guarantees considered financial instruments. Due to this factor, and because of the related , party nature of these conumtments and guarantees, detemunation of fair value is not considered practicable. See Notes 5 and 6 for additional fair value disclosure. j NOTE 2, RATE AND REGULATORY MATTERS Incentive Rate Plan In July 1993, the MPSC ordered MP&L to file a formulary incentive rate plan designed to allow for-periodic small adjustments in rates based upon a comparison of earned to t=M ==k returns and upon performance r factors incorporated in the plan. In November 1993, MP&L filed a formula rate plan (Proposed Plan) with the } MPSC to become effective on March 1,1994, with any initial adjustment to base rates in June 1994. Under the ! Proposed Plan,' a formula would be established under which MP&L's carned rate of return would be calculated - automatically every 12 months and compared to a benchmark rate of return, which would be calculatart under a separate formula within the Proposed Plan. If MP&L's earned rate of return falls withm a bandwidth around the ; benchmark rate of return, there would be no adjustment in rates. If MP&L's earmngs are above the bandwidth, the , ! Proposed Plan would automatically reduce MP&L's base rates. Alternatively, if MP&L's earmnas are below the l bandwidth, the Proposed Plan would automatically increase MP&L's base rates (subject to the five-year rate cap l
- described below). The reduction or increase in base rates would be an amount representing 50% of the difference
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I' i J
- . _ _ . ~ , . _ , _._ . . . - - . ~ ,_- ._ ,
MISSISSIPPI POWER & LIGIIT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) between the earned rate of retum and the nearest limit of the bandwidth. In no event would the annual adjustment in rates exceed the lesser of 2% of MP&L's aggregate retail revenues, or $14.5 million. Under the Proposed Plan, the benchmark rate of return, and consequently the bandwidth, would be adjusted slightly upward or downward based upon MP&L's performance on three performance factors: customer reliability, customer satisfaction, and
^
customer pnce. Subsequently, the MPSC conducted a general review of MP&L's current rates and later issued a fmal order adopting the Proposed Plan and previously agreed-upon stipulations of 1) a required return on equity of 11
- 2) certain accounting adjustments that result in a 4.3% ($28.1 million) reduction in MP&L's June 30,1993, test-year base revenues. The MPSC's order requires MP&L to file rates designed to provide for this reduction operating revenues for the test year on or before March 18,1994, to become effective for service rendered o after March 25,1994.
Rate Arreement In November 1993, MP&L and the MPSC entered into a settlement agreement whereby the MPSC agreed to withdraw its request for hearings and its objections in the SEC proceedmg related to the Merger. MP&L agreed that MP&L's retail ratepayers would be protected from (1) increases in MP&L's cost of capital resulting from risks emM costs associated associated with the Merger, (2) recovery of any portion of the acquisition premium or tr with the Merger, (3) certain direct allocations of costs associated with GSU's River Bend nuclear unit; and (4) any losses of GSU resulting from resolution oflitigation in connection with its ownership of River Bend. In a related stipulation, MP&L also agreed (a) that retail base rates under its proposed formula rate plan would not be increased above November 1,1993 levels, and (b) that MP&L would not request any general retail rate increase that would increase retail rates above the level of MP&L's rates in effect as of November 1,1993, except, among other things, for increases associated with the Least Cost Plan, recovery of deferred Grand Gulf 1-related costs, recovery under the fuel adjustment clause, adjustments for certain taxes, and force majeure (defmed to include among other things, war, natural catastrophes, and high inflation), in each case for a period of five years begin November 9,1993. Grand Gulf 1 MP&L's Revised Plan provides, among other things, for the recovery by MP&L, in equal annual installments over ten years beginning October 1,1988, of all Grand Gulf 1-related costs deferred through September 30,1988 pursuant to the Final Order on Rehearing. Additionally, the Revised Plan provided that MP&L defer, in decreasing amounts, a portion of its Grand Gulf 1-related costs over four years beginning October 1,1988. These deferrals are being recovered by MP&L over a six year period begmnmg in October 1992 and ending in September 1998. The Revised Plan also allows for the current recovery of carr,ing charges on all deferred amounts. l NOTE 3. INCOME TAXES Effective January 1,1993, MP&L adopted SFAS 109. 'Ihis new standard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that deferred tax balances be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 requires that regulated enterprises recognize adjustments resulting from implementation as regulatory assets or liabilities ifit is probable that such amounts will be recovered from or retumed to customers in future rates. A substantial majority of the adjustments required by SFAS 109 was recorded to deferred tax balance sheet accounts with offsetting adjustments to regulatory assets and liabilities. The cumulative effect of the adoption of SFAS 109
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MISSISSIPPI POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) is included in income tax expense charged to operations. As a result of the adoption of SFAS 109,1993 net income was reduced by $1.7 million, assets were increased by S50.2 million, and liabilities were increased by 551.9 million. Income tax expense consisted of the following: For the Years Ended December 31. 1993 1992 1991 (In Thousands) Current: Federal S 46,744 $ 4,532 S (1,000) State 7.673 (69) - Total 54.417 4.463 (1.000) Deferred - net: Federal reclassification due to net operating loss - 28,561 29,756 State reclassification due to net operating loss - 4,883 4,587 Liberalized depreciation 5,293 9,448 8,565 Rate Deferral- net (31,317) (11,220) (10,137) Unbilled revenue 21,373 (5,722) 1,207 Pension liability (647) (1,233) (157) Adjustments of prior year taxes 4,299 (3,471) (84) Bond reacquisition 3,208 264 (228) Other (1.670) (1.079) (1.020) Total 539 20.431 32.489 Investment tax credit adjustments - net 1.036 (1.746) (1.634) Recorded income tax expense M t 23.148 Ugjjj, Charged to operations S 33,074 521,681 $ 29,936 Charged (credited) to other income 3,462 1,467 (81) Charged to cumulative effect 19.456 - - Totalincome taxes S 55.992 $ 23.148 U2jjj,
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MISSISSIPPI POWER & LIGliT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) Total income taxes differ from the amounts computed by applying the statutory federal mcome tax rate to income before taxes. The reasons for the differences were: For the Years Ended December 31. 1993 1992 1991
% of % of % of Pretaz Pretar Pretar Amount income Amount Income Amount income (Dollars in Thousands) 555,207 35.0 $ 29,983 34.0 $ 31,601 34.0 Computed at statutory rate >
Increases (reductions) in tax resulting from: State income taxes net of federal income 3,253 2.0 2,703 3.1 3,175 3.4 tax effect (5,890) (2,571) (2.9) 944 1.0 Depreciation (3.7) (4,680) (3.0) (2,456) (2.8) (3,257) (3.5) Amortization of excess deferred income taxes (1,772) (1.1) (1,746) (2.0) (1,634) (1.8) Amortization ofinvestment tax credits 5,228 3.3 (2,760) (3.2) (1,149) (1.2) Adjustments of prior year taxes - - - SFAS 109 adjustment 3,439 2.2 - 1.207 _Q1 (5) - 175 __Ql Other - net Totalincome taxes S 55.992 E $ 23.148 ,2fl M E l Significant components of MP&L's net deferred tax liabilities as of December 31,1993, were (in thousands): Deferred tax liabilities:
$(166,650)
Plant related basis differences (246,604) Rate deferrals (6.406) Other Total S(419.660) Deferred tax assets: S 9,411 Net regulatory liabilities 13,420 Accumulated deferred investment tax credits 13,854 Recoverable income tax 1,192 Alternative muumum tax credit 10,725 Removal cost 4,854 Standard coal plant 2,488 Pension related items 10.342 Other Total 5 66.286 Net deferred taxliabilities $(353.374) The alternative minimum tax (AMT) credit as of December 31,1993, was $1.2 million. His AMT credit can be carried foiward indefmitely and will reduce MP&L's federal income tax liability in future years.
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MISSISSIPPI POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) 1 4 NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS He SEC has authorized MP&L to effect short-term borrowings up to $100 million, subject to increase to i as much as $113 million after further SEC approval. Rese authorizations are effective through , November 30,1994. As of December 31,1993, MP&L had unused lines of credit for short-term borrowing of
$30 million from banks within its service territory. In addition, MP&L can borrow from the Money Pool, subject -
to its maxunum authorized level of short-term borrowings and the availability of funds. MP&L's short-term borrowmss are limited by the terms of its G&R Mortgage to amounts not exceedmg the greater of 10% of capitalization or 50% of Grand Gulf I rate deferrals available to support the issuance of G&R Bonds MP&L had !
. $ 11.6 million in outstanding borrowings under the Money Pool arrangement as of D~~har 31,1993, ,
t NOTE 5. PREFERRED AND COMMON STOCK i ne number of shares and dollar value of MP&L's cumulative, $100 par value prefened stock was: As of December 31. Shares - Call Price Per ! Authorized and Total Share as of Outstandine Dollar Value December 31, 1993 1992 1993 1992 1993 , (Dollars in Thousands) Without sinkmg fund: 4.36% Series 59,920 59,920 S 5,992 S 5,992 5103.86 . 4.56% Series 43,888 43,888 4,389 4,389 $107.00 4.92% Series 100,000 100,000 10,000 10,000 $102.88 { 7.44% Series 100,000 100,000 10,000 10,000 $102.81 8.36% Series 200,000 200,000 20,000 20,000 - 9.16% Series 75.000 75.000 7.500 7.500 $104.06 Total without sinking fund 578.808 578.808 $57.881 557.881 With sinkmg fund: . 9.00% Series 140,000 210,000 $14,000 $21,000 $106.75 . 9.76% Series 280,000 350,000 28,000 35,000 $103.26 1 12.00% Series 47,700 57,700 4,770 5,770 $106.00 I6.16% Series - 15.000 - 1.500 - Total with sinking fund 467.700 632.700 $46.770 M { De fair value of MP&L's preferred stock with sinking fund was estunated to be approxunately .
$49.3 million and $66.2 million as of December 31,1993 and 1992, respectively. He fair value was detemuned !
using quoted market prices or estunates from nationally recognized mvestment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. l
.e of December 31,1993, MP&L had 175,000 shares of cumulative, $100 par value preferred stock that were authorizd but unissued. On Dbruary 4.1994, MP&L amended its charter authorizing 1,500,000 additional ,
shares of $100 par value preferred stock.
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l MISSISSIPPI POWER & LIGHT COMPANY l NOTES TO FINANCIAL STATEMENTS -(Continued) Changes in the common stock and preferred stock, with and without sinking fund, during the last three years were: , Number of Sheres 1993 1992 1991 Common stock issuances ($23 issuance price) - 1,086,957 -
- 200,000 -
Preferred stock issuances: (165,000) (95,000) (95,000) Preferred stock retirements: Cash sinking fund requirements for the next five years for preferred stock outetanding as of December 31,1993, are (in thousands): 1994 - $14,500; 1995 - $14,500; 1996 - $7,500; 1997 - 57,500; and 1998 - $500. MP&L has the annual non-cumulative option to redeem at par, additional amounts of its 12.00% series preferred stock outstanding. MP&L has SEC authorization for the issuance and sale through December 31,1995, of up to $70 mi!! ion of preferred stock (of which $50 million remamed available as of December 31,1993), and for the possible acquisition, in whole or in part, of not more than $50 million aggregate par value of MP&L's outrtanding preferred stock, including but not limited to the 12.00% Series and the 9.76% Series. The proceeds of any sales of preferred stock would be used for the refmancing of higher cost of debt and preferred stock and general corporate purposes NOTE 6. LONG-TERM DEBT The long-term debt of MP&L as of December 31,1993 and 1992, was: Maturities , " Merest Rates
;'w To 1993 1992 Ef91n Ip._
(In Thousands) First Mortgage Bonds 4-5/8% 6-3/8% $ 55,000 $ 55,000 1994 1998 9-5/8% - 102,500 1999 2003 7-3/4%
- 25,000 2004 2008 9-7/8%
- 70,000 2014 2018 9-5/8%
G&R Bonds 14.95 %
- 215,000 270,000 1993 1997 5.95 %
6-5/8% 8.65 % 250,000 - 2003 2023 Governmental Obligations" 8-1/2% 17,925 18,155 1992 2008 7-1/2% 9-1/2% 30,000 30,000 2012 2014 9% (3.519) (2.750) Unamortized Premium and Discount-Net 564,406 567,905 Total Long-Term Debt 48.250 55.230 Less Amount Due Within One Year
$ 516.156 $512.675 Long-Term Debt Excludmg Amount Due Within One Year
- The 14.95% series of $20 million is due 2/1/95. A!! other series are at interest rates within the range of 5.95% - 11.2%.
" Consists of pollution control revenue bonds, certain series of which are secured by non-interest beanng first mortgage bonds.
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f MISSISSIPPI POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) The fair value of MP&L's long-term debt as of December 31,1993 and 1992, was estunated to be
$594.0 million and $595.0 million, respectively. He fair value was detemiined using quoted market prices or estimates from nationally recognized investment banking firms. See Note 1 for additional information on disclosure of fair value of fmancial instruments.
For the years 1994,1995,1996,1997 and 1998, MP&L has long-term debt maturities and cash sinking fund requirements of (in millions) 548.2, 566.2, $61.3, 596.3, and $0.3, respectively. In addition, other sinkmg fund requirements of approximately 50.2 million annually may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements. He G&R Mortgage prohibits the issuance of additional first mortgage bonds (including for rekn&ng purposes) under MP&L's first mortgage indenture, except such first mortgage bonds as may hereafter be issued from time to time at MP&L's option to the corporate trustee under the G&R Mortgage to proside additional security for MP&L's G&R Bonds. Under MP&L's G&R Mortgage indenture and subject to the earnmgs coverage test discussed below, G&R Bonds are issuable based upon 70% of property additions since December 31,1987, plus up to 50% of cumulative deferred Grand GulfI-related costs recorded as an asset on the books of MP&L, provided that the maxunum amount of G&R Bonds issuable agamst cumulative deferred Grand Gulf 1-related costs may not exceed
$400 million. He G&R Mortgage contains an cammgs coverage test requiring a nummum cammgs coverage (except for certain refunding issues) of twice the pro-forma annual mortgage interest requirements for the i=minner of additional G&R Bonds. As of December 31,1993, the total amount of GAR Bonds outstandmg aggregated $465 million.
MP&L has requested SEC authorization allowing the issuance and sale through December 31,1995, of up to $550 million of G&R Bonds (of which $235 million remamed available as of December 31,1993) and up to
$25 million of tax-exempt bonds. MP&L has also received SEC authorization through December 31,1995, for the possible acquisition, in whole or in part, of not more than $200 million aggregate principal amount of outstandmg bonds, including, but not limited to MP&L's G&R Bonds,14.95% Series due 1995; and not more than $25 million ag:pte principal amount of outstanding pollution control revenue bonds, including but not limited to independence County Pollution Control Revenue Bonds,9% 1982 Series B duc 2013,9.50% 1982 Series C due 2014,9% 1982-A Series A duc 2013, and 9.50% 1982 A Series B duc 2014.
NOTE 7. DIVIDEND RESTRICTIONS MP&L's bond indentures relating to long-term debt contain prosisions restricting the payment of cash dividends or other distributions on common stock. As of December 31,1993, $139.6 million of MP&L's retamed earnings were restricted agamst the payment of cash dividends or other distributions on common stock. On February 1,1994, MP&L paid Entergy Corporation a $4.6 million cash disidend on common stock. NOTE 8. COMMITMENTS AND CONTINGENCIES Csoital Reavirements and Financine Construction expenditures for the years 1994,1995, and 1996 are estunated to total 561 million,
$63 million, and $63 million, respectively. MP&L will aho require $212 million during the period 1994-1996 to meet long-term debt and preferred stock maturities and cash sinking fund requirements. MP&L plans to meet the
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MISSISSIPPI POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Continued) above requirements with internally generated funds and cash on hand, supplemented by the issuance oflong-term debt. See Notes 5 and 6 regarding the possible issuance, refundmg, redemption, purchase or other acquisition of certain outstandmg series of preferred stock and long-term debt. See Nue 11 for information on additional capital requirements related to a February 1994 ice storm. Unit Power Sales Arreement System Energy has agreed to sell all ofits 90% owned and leased share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this agreement are paid in consideration for MP&L's respective entitlement to receive capacity and energy, and are payable trrespective of the quantity of energy delivered so long as the unit remams in commercial operation. Theera waerd will remam in effect until termmated by the parties and approved by FERC, most likely upon Grand Gulfl's retirement from service. MP&L's monthly obligation for payments to System Energy for Grand Gulf I capacity and energy is approximately
$18 million.
Availability Arreement AP&L, LP&L, MP&L, and NOPSI are individually obligated to make payments or subordmated advances to System Energy in accordance with staed percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 24.7%) in amounts that when added to amounts received under the Unit Power Sales Agreement or othenvise, are adequate to cover all of System Energy's operatmg expenses. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Payments or advances under the Availability Agreement are only required if funds available to System Energy from all sources are less than the amount required under the Availability Agreement. Since commercial operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments have ever been required. In 1989, the Availability Agreement was ammtM to provide that the write-off of
$900 million of Grand Gulf 2 costs would be amortized for Availability Agreement purposes over a period of 27 years in order :o avoid the need for payments by AP&L, LP&L, MP&L, and NOPSI.
Reallocation Arre ment System Energy and AP&L, I?&L, MP&L, and NOPSI entered into the Reallocation Agreement relating to the sale of capacity and energy fren. the Grand Gulf Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and obligations with respect to the Grand Gulf Station under the Availability Agreement. FERC's decision allocating a portion of Grand GulfI capacity and energy to AP&L supersedes the Reallocation Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the Reallocation Aapww.at. However, the Reallocation Agreement does not affect AP&L's obligation to System Energy's lenders under the assignments referred to in the precedmg paragraph. AP&L would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual obligations. No payments of any amortization amounts will be required as long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future. System Fuels MP&L has a 19% interest in System Fuels, a jointly-owned subsidiary of AP&L, LP&L, MP&L, and NOPSI. The parent companies of System Fuels, including MP&L, agreed to make loans to System Fuels to
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MISSISSIPPI POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) fmance its fuel procurement, delivery, and storage activities. As of December 31,1993, MP&L had approximately
$5.5 million ofloans outstanding to System Fuels which mature in 2008.
On April 30,1993, AP&L assumed System Fuels' rights and obligations in connection with System Fuels' coal car leases. The other parent companies of System Fuels have been released from their obligations with respect to the coal car leases. However, MP&L, as a co <mner of the Independence Station, which uses the coal transported by the leased coal cars, will continue to reimburse AP&L for MP&L's share of the costs associated with the leases. Fuel Purchase Commitments . MP&L has a four-year gas purchase agreement with Koch Gateway Pipeline Company (formerly United Gas Pipeline Company) under which, beginning January 1,1991, MP&L is purchasing approxunately 34.1 billion cubic feet of gas. As of December 31,1993, MP&L had purchased approximately 23.4 billion cubic feet of gas. I ! MP&L owns certain coal mining equipment and facilities at a mine in Wyoming. The mine's estimated reserves are presently expected to provide the projected requirements of the Independence Station through at least 2014. NOTE 9. POSTRETIREMENT BENEFITS Pension Plan MP&L has a defmed benefit pension plan covering substantially all of its employees. The pension plan is l noncontnbutory and provides pension benefits based on employees' credited senice and average compensation. l generally during the last five years before retirement. MP&L funds pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plan consist pnmarily of common and preferred stocks, fixed income securities, interest in a money market fund, and insurance contracts. MP&L's 1993,1992, and 1991 pension cost, including amounts capitalized, included the following components: For the Years Ended December 31. 1993 1992 1991 l (In Thousands) Senice cost - benefits earned during the period S 2,409 $ 2,059 $ 2,061 Interest cost on projected benefit obligation 8,583 8,269 7,472 Actual return on plan assets (15,053) (8,474) (22,422) Net amortization and deferral 5,325 (1,009) 13,323 l Other - - 403 ) Net pension cost S 1.264 5 845 5 837
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MISSISSIPPI POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) ne funded status of MP&L's pension plan as of December 31,1993 and 1992, wn: 1993 1992
. (In Thousands)
Actuanal present value of accumulated pension plan benefits:
$ 101,664 5 92,473 Vested 390 283 Nonvested Accumulated benefit obligation 5102.054 S 92.756
$ 126,990 $ 119,173 Plan assets at fair value
_111916 107.658 Projected benefit obligation 4,934 11,515 Plan assets in excess of projected benefit obligation 3,574 3,856 Unrecogmzed prior service cost (10,003) (11,253) Unrecogmzed transition asset (1.798) (6.146) Unrecogmzed net gain S (3.293) S (2.028) Accrued pensionliability The significant actuarial assumptions used in computing the information above for 1993,1992, and 1991 were as follows: weighted average discount rate,7.5% for 1993 and 8.25% for 1992 :md 1991; weighted average rate of increase in future compensation levels, 5.6%; and expectal log-term rate of return on plan assets, 8.5%. Transition assets are being amortized over 15 years. Other Postretirement Benefits MP&L also provides certain health care and life insurance benefits for retired empicytes. Substantially all employees may become eligible for these benefits if they reach retirement age while still working for MP&L. The cost of providing these benefits, recorded on a cash basis, to retirees in 1992 wu approxunately $1.6 million. Prior to 1992, the cost of providing these berafits for retirees wu not separable from the cost of providing benefits for active employees. Based on the ratio of the number of retired employees to the total number of actiw and retired employees in 1991, the cost of providing these benefits in 1991, recorded on a cash basis, for retirees wm approxunately $1.1 million. Effective January 1,1993, MP&L adopted SFAS 106. He new standard requires a change from a cash method to an accrual method of accounting for postretirement benents other than pensions. MP&L continues to fund these beneSts on a pay-as-you-go basis. At January 1,1993, the actuanally determined accumulated postrctirement benent oblication (APBO) camed by retirees and active employees was esm*d to be approximately $30 million. This Sligatten is being amortized over a 20-year period begmmng in 1993. MP&L is expensing its SFAS 106 costs, which will % u.f!ccted in rates pursuant to an order from the MPSC in connection i with MP&L's fonnulary incentive rate plu (see Note 2). MP&L's net income in 1993 wu decreased by approximately $2.0 million as a result of adopting SFAS 106. MP&L's 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components (in thousands): Service cost - benefits camed dudng the pedod S 812 ; 2,400 Interest cost on APBO - Actual return on plan assets Amortization of transition obligation 1.502 Net periodic postretirement benefit cost S 4.714
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MISSISSIPPI POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS - (Continued) ne funded status of MP&L's postretirement plan as of December 31,1993, was (in thousands): Accumulated postretirement benent obligations: Retirees S 21,435 Other fully eligible participants 5,816 Other active participants 7.794 35,045 Plan assets ai fair value - Plan assets less than APBO (35,045) Unrecogmzed transition obligation 28,537 Unrecogmzed set loss 3.745 Accrued post retirement benefit liability S (2.763) He assumed health care cost trend rate used in measuring the APBO was 9.9% for 1994, gradually decreasing each successive year until it reaches 5.6% in 2020. A one percentage-point increase in the assumed health care cost trend rate for each year would have increased the APBO as of December 31,1993, by 8.6% and the sum of the service cost and mterest cost by approximately 10.9%. The assumed discount rate and rate of increase in future compensation used in determimng the APBO were 7.5% and 5.5%, respectively. NOTE 10. TRANSACTIONS WITH AFFILIATES MP&L buys electricity from and/or sells electricity to AP&L, LP&L, NOPSI, and System Energy under rate schedules filed with FERC. In addition, MP&L purchases fuel from System Fuels and receives technical and advisory senices from Entergy Senices, Inc.. Operating revenues include revenues from sales to afWa amountmg to $40.6 million in 1993, $18.0 million in 1992, and $9.8 million in 1991. As a result of an internal resiew designed to ensure consistency among the System operating companies, certain 1985-1991 intra-system equahzation billings pursuant to the System Agreement were adjusted in 1991 and reduced operating revenue in the amount of approximately $10.6 million. Operating expenses include charges from affiliates for fuel costs, purchased power and related charges, and technical and advisory services totaling $360.5 million in 1993, $364.0 million in 1992, $310.8 million in 1991. See Note 1 for information on MP&L's jointly-owned generating station. NOTE 11. SUBSEQUENT EVENT (UNAUDITED) In early February 1994, an ice storm left more than 80,000 MP&L customers without electric power in its senice area. He storm was the most severe natural disaster ever to affect MP&L, causing damage to transmission and distribution lines, equipment, poles, and facilities in certain areas. A substantial portion of the related costs, which are estunated to be S75 million to $100 million, are expected to be capitalized. Estunated construction expenditures (see Note 8) have not yet been updated to reflect the above amounts. He MPSC acknowledged that there is precedent in Mississippi for recovery of certain costs associated with storms and natural disasters and the restoration of senice resulting from such events. MP&L plans to immediately file for rate recovery of the costs related to the ice storm.
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MISSISSIPPI POWER & LIGHT COMPANY NOTES TO FINANCIAL STATEMENTS -(Concluded) NOTE 12. QUARTERLY FINANCIAL DATA (UNAUDITED) MP&L's business is subject to seasonal fluctuations with the peak period occurring during the third quarter. Operating results for the four quarters of 1993 and 1992 were: Operating Operating Net Revenues Income Income (In Thousands) 1993: First Quarter (1) $179,467 $24,134 $42,782 Second Quarter $229,506 $38,471 $25,339 Third Quarter $264,419 $39,896 $26,921 Fourth Quarter $222,414 $22,819 $ 6,701 1992: First Quarter $186,791 $26,866 $11,083 Second Quarter $202,297 $25,830 $10,306 Third Quarter $229,209 $40,673 $25,002 Fourth Quarter $199,353 $31,405 (2) $18,645 (2) (1) The first quarter of 1993 reflects a nonrecurring increase in net income of $32.7 million, net of taxes of
$19.5 million, due to the recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1). Beguunng with the second quarter, the remauung quarters are not generally comparable to prior year quarters because of the ongoing effects of the accounting change.
f (2) The fourth quarter of 1992 reflects a decrease in income tax expense of $4.8 million due to estunates of income tax benents related to tax depreciation having been adjusted as a result of certain elections made m conjunction with the filing of the 1991 tax retum. .
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MISSISSIPPI POWER & LIGHT COMPANY SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1993 1992 1991 1990 1989 (In Thousands) S 895,806 $ 817,650 $ 754,632 5 761,188 $ 709,746 ' Operating revenues Income before cumulative effect of a change in accounting principle S 69,037 5 65,036 $ 63,088 $ 60,830 $ 12,419
$1,676,737 $1,660,726 $1,672,275 $1,616,522 $1,565,707 Total assets
$ 563,612 S 576,787 $ 576,599 $ 679,458 $ 693,333 long-term obligations (1)
(1) Includes long-term debt (excluding currently maturing debt), preferred stock with sinkmg fund, and noncurrent capital lease obligations. See Notes 1, 3, and 9 for the effect of accounting changes in 1993.
, 1993 1992 1991 1990 1989 (Dollars in Thousands)
Operating Revenues: ,
$343,585 $308,346 $307,283 $302,622 $274,841 Residential 252,798 235,137 229,597 227,140 212,107 Commercial '
183,537 168,853 162,072 160,007 147,146 Industrial 28.708 26.250 25.630 25.117 23.624 Governmental 808,628 738,586 724,582 714,886 657,718 Total retail 55,740 37,983 25,487 35,678 45,886 Sales for resale 31.438 41.081 4.563 10.624 6.142 - Other
$895.806 $817.650 $754.632 $761.188 $709.746 Total Billed Electric Energy Sales (Millions of K%B):
3,983 3,644 3,739 3,701 3,452 Residential 2,928 2,804 2,807 2,802 2,679 Commercial 2,787 2,631 2,582 2,564 2,368 Industrial 336 318 321 318 308 Governmental 10,034 9,397 9,449 9,385 8,807 Total retail 1.428 1.190 1.032 902 1.038 Sales for resale 11.462 10.587 10.481 10.287 9.845 Total
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4 New Orleans Public Service Inc./1993 Financial Statements 3
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NEW ORLEANS PUBLIC SERVICE INC. DEFINITIONS Certain abbreviations or acronyms used in NOPSI's Financial Statements, Notes to Financial Statements, and Management's Financial Discussion and Analysis are defined below-1 Abbreviation or Acronym IstIn AFUDC Allowance for Funds Used During Construction , Alliance The Alliance for Affordable Energy, and others , AP&L Arkansas Power & Light Company City of New Orleans or City New Orleans, Louisiana Council Council of the City of New Orleans, Louisiana : Entergy or System Entergy Corporation and its various direct and indirect subsidiaries FASB Financial Accounting Standards Board February 4 Resolution The Resolution (including the Deternunations and Order referred to ; therein) adopted by the Council on February 4,1988, disallowmg the : recovery by NOPSI of $135 million of previously deferred Grand Gulf I-related costs i FERC Federal Energy Regulatory Commission G&R Bonds General and Refundmg Mortgage Bonds issued and issuable by NOPSI Grand Gulf 1 Unit No. I of the Grand Gulf Station Grand Gulf 2 Unit No. 2 of the Grand Gulf Station j Grand Gulf Station Grand Gulf Steam Electric C_4hig Station l l GSU Gulf States Utilities Company (including wholly owned subsidiaries - l Varibus Corporation, GSGAT, Inc., Prudential Oil and Gas, Inc., and . Southern Gulf Railway Company) ; KWH Kilowatt-Hour (s) l l LP&L Louisiana Power & Light Company Merger The combination transaction, enammm'ad on Dsd,cr 31,1993, by which GSU became a subsidiary of Entergy Corporation and Entergy Corporation became a Delawwe Corporation
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NEW ORLEANS PUBLIC SERVICE INC. DEFINITIONS -(Concluded) Abbreviation or Acronvin Igtm Money Pool Entergy Money Pool, which allows certam System companies to borrow from, or lend to, certam other System companies MP&L Mississippi Power & Light Company , 1986 Rate Settlement A,-.r., effective March 25,1986, between NOPSI and the Council regarding NOPSI's Grand Gulf 1-related rate issues 1989 Settlemeat Ay~.= An agreement between the Council and NOPSI, effective July 21,1989, that settled certsin local retail rate issues regarding Grand Gulf 1 1991 NOPSI Settlement b" W retroactive to October 4,1991, among NOPSI, the Council and the Alliance that settled certam Grand Gulf 1 prudence issues and pendmg litigation related to the February 4 Resolution NOPSI New Orleans Public ServiceInc. OBRA Omnibus Budget Reconcthaten Act of 1993 SEC Securities and Exchange Comnussion SFAS Statement of Financial A=- ^ ..g Standards promulgated by the FASB SFAS 106 SFAS No.106, " Employers' AccWag for Postretirement Benefits Other Than Pensions" SFAS 109 SFAS No.109, " Ace- -^ .g for Income Taxes" System Energy Sym Energy Resources,Inc. System Fuels System Fuels,Inc. System operstmg companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively System or Entergy Entergy Corporatim and its various direct and indirect subsidiaries
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NEW ORLEANS PUBLIC SERVICE INC. REPORT OF MANAGEMENT The management of New Orleans Public Service Inc. has prepared and is responsible for the financial statements and related financial information included herein. He fmancial statements are based on generally accepted accounting principles. Financial information included elsewhere in this report is consistent with the fmancial statements. To meet its responsibilities with respect to fmancial information, ====&=e mamtams and enforces a system of internal accounting controls that is designed to provide reasonable assurance, on a cost-effective basis, as , to the integrity, objectivity, and reliability of the financial records, and as to the protection of assets His system 4 includes communication through. written policies and procedures, an employee Code of Conduct, and an org=aintia==1 structure that provides for appropriate division of responsibility and the traimng of personnel His system is also tested by a comprehensive internal audit program. : He independent public accountants provide an objective assessment of the degree to which ====-- e meets its responsibility for fairness of financial reporting. Hey regularly evaluate the system of internal accounting controls and perform such tests and other procedures as they deem n==aary to reach and express an opinion on the fairness of the financial statements. Management believes that these policies and procedures provide reasonable assurance that its operations , are carried out with a high standard of business conduct. EDWIN LUPBERGER GERALD D. MCINVALE Chairman and Chief Executive Officer Senior Vice President and i Chief Financial Officer i i f
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1 NEW ORLEANS PUBLIC SERVICE INC. AUDIT COMMITTEE CHAIRMAN'S LETTER 1 The New Orleans Public Service Inc. Audit Committee of the Board of Directors is comprised of four l 1 directors, who are not officers of NOPSI: Anne M. Milling (Chairman), James M. Cain, Brooke H. Duncan and Dr. Norman C. Francis The committee held four meetmgs during 1993. The Audit Committee oversees NOPSI's fmancial reporting process on behalf of the Board of Directors and provides reasonable assurance to the Board that sufficient operatmg, accounting, and fmancial controls are in existence and are adequately reviewed by programs ofinternal and external audits. The Audit Committee discussed with Entergy's internal auditors and the inAWa* public accountants (Deloitte & Touche) the overall scope and specific plans for their respective audits, as well as NOPSI's fmancial statements and the adequacy of NOPSI's internal controls. The committee met, together and separately, with Entergy's internal auditors and i~'-7-5 he public accountants, without management present, to discuss the results of their audits, their evaluation of NOPSI's internal controls, and the overall quality of NOPSrs financial reporting. The meetmgs also were designed to facilitate and encourage any private communication between the committee and the intemal auditors or independent public accountants. ANNE M. MILLING Chairman, Audit Committee
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4 INDEPENDENT AUDITORS' REPORT I i To the Shareholders and the Board of Directors of ) New Orleans Public Service Inc. ! l l We have audited the accompanying balance sheets of New Orleans Public Service Inc. (NOPSI) as of December 31,1993 and 1992, and the related statements of income, retained earnmgs, and cash flows for each of the three years in the period ended December 31, 1993. These fmancial statements are the responsibility of NOPSI'e management. Our responsibility is to express an opinion on these fmancial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the fmancial statements are free of material misstatement. An audit includes examming, on a test basis, evidence supporting the amounts and disclosures in the fmancial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall fmancial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such fmancial statements present fairly, in all material respects, the financial position of NOPSI at December 31,1993 and 1992, and the results ofits operations and its cash flows for each of the three years in the period ended December 31,1993 in conformity with generally accepted accounting pnnciples. As discussed in Note I to the financial statements, NOPSI changed its method of accounting for revenues in 1993 and, as discussed in Notes 3 and 9 to the fmancial statements, in 1993 NOPSI changed its methods of accounting for income taxes and postretirement benefits other than pensions, respectively. DELOITTE & TOUCHE New Orleans, Louisiana February 11,1994
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NEW ORLEANS PUBLIC SERVICE INC. BALANCE SHEETS ASSETS December 31, 1993 1992 (In Thousaads) Utility Plant (Note 1): Electric $476,976 5466,319 Natural gas 113,666 110,399 ( Construction work in progress 15,205 6,906 j Total 605,847 583,624 j Less - accumulated depreciation and amoruzation 330,268 315,439 i Utility plant - net 275,579 268,185 Other Investments: Investment in subsidiary company - at equity (Note 8) 3,259 3,259 Current Assets: Cash and cash equivalents (Note 1): Cash 1,176 - Temporary cash investments - at cost, which approximates market Associated companies (Note 4) 10,034 3,513 Other 32.107 42,557 Totalcash and cash equivalents 43,317 46,070 Accounts receivable: Customer (less allowance for doubtful accounts of 50.8 million in 1993 and $1.4 million in 1992) 35,801 30,525 Associated companies (Note 10) 1,378 2,232 Other 876 676 Accrued unbilled revenues (Note 1) 19,643 - Deferred electric fuel and resale gas costs (Note 1) 6,323 486
- 4,566 Accumulated deferred income taxes (Note 3) l 11,925 l Materials and supplies - at average cost 11,885 24,587 15,617 Rate deferrals (Note 2) 2,994 3,633 l Prepayments and other Total 146,804 115,730 Deferred Debits:
204,190 229,002 Rate deferrals (Note 2) SFAS 109 regulatory asset - net (Note 3) 9,004 - 8,769 5,515 i Other Total 221,963 234,517 l
$647,605 $621,691 TOTAL See Notes to Financial Statements.
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NEW ORLEANS PUBLIC SERVICE INC. BALANCE SIIEETS CAPITALIZATION AND LIABILITIES December 31, 1993 1992 l (In Thousands) I Capitalization: Common stock, S4 par value, authorized 10,000,000 shares; issued and outstanding 8,435,900 shares in 1993 and 1992 $33,744 $33,744 l Paid-in capital 36,156 36,097 ) l Retained earmngs subsequent to the clinunation of the l accumulated deficit of $13.9 million on November 30, { 1988 (Note 7) 100,556 98,560 ! Total common shareholder's equity 170,456 168,401 , Preferred stock (Note 5): l Without sinking fund 19,780 19,780 With sinking fund 4,950 6,450 Long-term debt (Note 6) 188,312 159,467 Total 303,498 354,098 Other Noncurrent Liabilities: j Axumulated provision for losses (Note 1) 18,022 17,799 l Other 3,351 - Total 21.373 17,799 Current Liabilities: Currently maturmg long-tenn debt (Note 6) 15,000 44,400 Accounts payable: Associated companies (Note 10) 23.080 21,527 Other 3,011 22,395 Customer deposits 16,617 15,552 Am'mn1*A deferred income taxes (Note 3) 4,968 - Taxes accrued 5,161 5,243 Interest accrued 5,472 6,791 Dividends declared 432 490 Other 6,935 1,477 Total 99,676 117,875 l Deferred Credits: Accumulated deferred income taxes (Note 3) 105,096 100,423 Acamulawi deferred investment tax credits (Note 3) 11,592 12,338 Other 26,370 19,158 Total 143,058 131,919 Commitments and Contingencies (Notes 2 and 8) TOTAL $647,605 5621,691 See Notes to Financial Statements. l
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- - _ _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - )
NEW ORLEANS PUBLIC SERVICE INC. STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1993 1992 1991 (In Thousands) Operating Activities:
$47,709 $26,424 $74,699 Net income Noncash items included in net income:
Cumulative effect of a change in accounting principle (10,948) - - 15,842 2,856 (55,151) Change in rate deferrals (Note 2) 17,284 16,619 15,973 Depreciation and amortuation (2,132) (865) 36,180 Deferred income taxes and investment tax credits Allowance for equity funds used during construction (141) (119) (102) Changes in working capital: (6,725) 1,579 2,007 Receivables 1,169 (1,455) 2,802 Accounts payable (82) 1,4 73 2,471 Taxes accrued (1,319) (1,687) (168) Interest accrued Other working capital accounts 1,365 (6,344) 58
- (23,131) -
Pension payment 8,345 7,047 2,888 Other 70,367 22,397 81,657 Net cash flow provided by operating activities investing Acsisities: (24,813) (21,043) (22,535) Construcuon expenditures Allowance for equity funds used during 141 119 102 construction Net cash flow used in investing activities (24,672) (20,924) (22,433) Financing Actisities: Proceeds from the issuance of general and refunding bonds 100,000 - - Retirement of: General and refunding bonds (44,400) - . (56,823) (28,000) (16,400) First mortgage bonds (1,500) (1,500) (1,500) Redemption of preferred stock Dividends paid: (43,900) (32,154) (4,453) Common stock (1,825) (2,057) (2,289) Preferred stock Net cash flow used in fmancing activities (48,448) (63,711) (24,642) (2,753) (62,238) 34,582 Net increase (decrease) in cash and cash equivalents 46,070 108,308 73,726 Cash and cash equivalents at beginning of period
$43,317 $46,070 $108,308 Cash and cash equivalents at end of period SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
$21,953 $26,330 $25,341 Interest - net of amount capitalized
$25,661 $15,632 $6,357 Income taxes See Notes to Financial Statements.
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NEW ORLEANS PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES Liquidity is important to NOPSI due to the capital intensive nature of our business, which requires large investments in long-lived assets. However, large capital expenditures for the construction of new generatmg capacity are not currently planned. NOPSI requires significant capital resources for the periodic maturity of certain series of debt and preferred stock. Net cash flow from operations totaled $70 million, $22 million, and $82 million in 1993,1992, and 1991, respectively. In recent years, this cash flow, supplemented by cash on hand, has been sufficient to meet substantially all investing and fmancing requirements, including capital expenditures, disidends, and debt / preferred stock maturities. NOPSI's ability to fund these capital requirements results, in part, frorr, our continued efforts to streamline operations and reduce costs, as well as collections under our Grand Gut! I rate phase-in plan which exceed the current cash requirements for Grand Gulf 1-related costs. (In the income statement, these revenue collections are offset by the amortization of previously deferred costs, therefore, there is no effe-t on net income.) See Note 2, incorporated herein by reference, for additional information on NOPSI's rate phase-i.a plan. See Note 8, incorporated herein by reference, for additional information on NOPSI's capital and refinancing requirements in 1994 - 1996. Also, in order to take advantage oflower interest and dividend rates, NOPSI may continue to refmance high-cost debt and preferred stock prior to maturity. Eanungs coverage tests (which are impacted by the inclusion of the cumulative effect of the change in accounting principle for accruing unbilled revenues discussed in Note 1), bondable property additions, and accumulated deferred Grand Gulf 1-related costs recorded as assets, limit the G&R Bonds and preferred stock that NOPSI can issue. Based on the most restrictive applicable tests as of December 31,1993 and an assumed annual interest or dividend rate of 8%, NOPSI could have issued $40 million of additional G&R Bonds or $306 million of additional preferred stock. Further, NOPSI has the conditional ability to issue G&R bonds against the retirement of bonds, in some cases without satisfying an canungs coverage test. See Notes 5 and 6, incorporated herein by reference, for information on NOPSI's financing activities and Note 4, incorporated herein by reference, for information on NOPSI's short-term borrowings and lines of credit. l
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l NEW ORLEANS PUBLIC SERVICE INC. STATEMENTS OFINCOME For the Years Ended December 31. 1993 1992 1991 (la Thousands) Operating Revenues (Notes 1, 2, and 10): Electric $423,830 $391,936 $399,214 Natural gas 90.992 72,943 76.951 514,822 464,879 476,165 Total Operatmg Expenses Operation (Note 10): - Fuel for electric generation and fuel-related expenses 59,859 47,566 38,428 165, % 3 170,703 168,315 Purchased power Gas purchased for resale 52,592 43,212 49,986 69,658 74,696 74,713 Other 18,139 17,039 18,118 Maintenaner Depreciation and amortization 17,284 16,619 15,973 26,643 27,487 25,733 Taxes other than income taxes 24,232 14,382 41,998 Income taxes (Note 3) Rate deferrals (Note 2): Rate deferrals (1,651) (1,300) (3,348) Amortization of rate deferrals 22,351 4,426 38,627 Deferral of previously incurred
- - (90,000)
Grand Gulf 1-related costs 455,070 414,830 378,543 Total 59,752 50,049 97,622 Operatingincome Other income (Deductions): Allowance for equity funds used during cons:ruction 141 119 102 Miscellaneous - net (1,055) 3,056 5,329 (1,115) (1.683) (3,242) Income taxes (Note 3) (2,029) 1,492 2,189 Total Interest Charges: Interest on long-term debt 19,478 22,934 23,865 1,614 2,290 1,358 Other interest - net l Allowance for borrowed funds used during construction (130) (107) (111) 20,% 2 25,117 25,112 Total Income before Cumulative EKect of a Change in A-a6n= Principle 36,761 26,424 74,699 Cumulative E5ect to January 1,1993 f of AccruingUnbilled Revenues (net j ofincome taxes of $6.,592)(Note 1) 10,948 - - 47,709 26,424 74,699 Net incorne 1,768 1,999 2,231 Preferred Stock Dividend Requirements
$45,941 $24,425 $72,468 Earnings Applicable to Common Stock See Notes to Financial Statements.
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l l l
NEW ORLEANS PUELIC SERVICE INC. l STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1993 1992 1991 (In Thousands) s Retained Earmngs, January 1 $98,560 $106,341 $33,918 Add: Net income 47,709 26,424 74,699 Total 146,269 132,765 108,617 ; Deduct: Dividends declared: Preferred stock 1,768 1,999 2,231 . Common stock 43,900 32,154 - Capital stock expenses 45 52 45 Total 45,713 34,205 2,276 Retained Earmngs, December 31 (Note 7) $100,556 $98,560 $106,341 See Notes to Financial Statements. i
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NEW ORLEANS PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net income Net income increased in 1993 due primarily to the one-time recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1, incorporated herein by reference) and its ongoing effects, partially offset by the effect of implementing SFAS 106 (see Note 9, incorporated herein by reference). Effective January 1,1993, NOPSI began accruing as revenues the charges for energy delivered to customers but not yet billed. Electric and gas revenues were previously recorded on a cycle-billing basis. Excluding the above mentioned items, net income for 1993 would have been $37.8 million. 'Ihis $11.4 million increase is due primarily to increased gas revenues and increased electric retail energy sales. Net income decreased in 1992 due primarily to the net income effect of the 590 million 1991 NOPSI Settlement, which resulted in a $48.6 million increase in 1991 net income. Significant factors affectmg the results of operations and causing variances between the years 1993 and 1992, and 1992 and 1991, are discussed under " Revenues and Sales" and " Expenses" below. Revenues and Sales See " Selected Financial Data Five-Year Comparison," incorporated herein by reference, following the notes, for information on electric operating revenues by source and KWH sales. Electric operatmg revenues were higher in 1993 due primarily to increased fuel adjustment revenues and increased collections of previously deferred Grand Gulf I-related costs, neither of which affects net income, and increased residential energy sales resulting primarily from a return to more normal weather as compared to milder weather in 1992. Electric operating revenues were slightly lower in 1992 due primarily to decreased retail sales as a result of milder temperatures. Total electric energy sales were lower in 1992 resulting from these milder temperatures. Gas operating revenues increased in 1993 due primarily to an increase in gas rates and increased fuel adjustment revenues resulting from higher average per unit cost for gas purchased. Gas operating revenues decreased in 1992 due primarily to decreased recovery of resale gas costs through the city gate adjustment clause, partially offset by higher base revenues due to the gas rate increase in May 1992. Expenses Fuel for electric generation and fuel-related expenses increased in 1993 due primarily to increased gas costs and increased generation requirements resulting primarily from increased energy sales as discussed in i i
" Revenues and Sales" above. Fuel for electric generation and fuel-related expenses increased in 1992 due to increased generation.
Gas purchased for resale increased in 1993 due primarily to a higher average per unit cost for gas purchased while it declined in 1992 due primarily to a lower average per unit cost. The changes in the amortization of rate deferrals in 1993 and 1992 are pnmarily a result of the 1991 l NOPSI Settlement, which allowed NOPSI to record an additional $90 million of previously incurred Grand Gulf I-related costs.
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[ .. .
l l NEW ORLEANS PUBLIC SERVICE INC. l l 1 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS i RESULTS OF OPERATIONS -(Concluded) l
)
Total income taxes increased in 1993 due pnmarily to higher pretax income and an increase in the federal _ income tax rate as a result of OBRA. Total income taxes decreased in 1992 due primarily to lower pretax income < resulting from the effect of the 1991 NOPSI Settlement. E P r 1
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i
NEW ORLEANS PUBLIC SERVICE INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS Competition NOPSI welcomes competition in the electric energy business and believes that a more competitive ernironment should benefit our customers, employees, and shareholders of Entergy Corporation. We also recognize that competition presents us with many challenges, and we have identi6ed the following as our major competitive challenges: Retail and Wholesale Rate Issues Increasing competition in the utility industry brings an increased necd to stabilize or reduce retail rates. l NOPSI is currently operating under electric and gas base rate freezes through October 31, 1996. Also, in l connection with the Merger, NOPSI agreed with the Council to reduce its annual electric base rates by $4.8 million effective for bills rendered on or after November 1,1993. See Note 2, incorporated herein by reference, for further information. Retail wheeling, a major industry issue which may require utilities to " wheel" or move power from third parties to their own retail customers, is evohing gradually. As a result, the retail market could become more competitive. In the wholesale rate area, FERC approved in 1992, with certam modifications, the proposal of AP&L, LP&L, MP&L, NOPSI, and Entergy Power, Inc. to sell wholesale power at market-based rates and to provide to electric utilities "open access" to the System's transmission system (subject to certain requirements). GSU was later added to this filing. Various intervenors in the proceeding filed petitions for review with the United States Court of Appeals for the District of Columbia Circuit. FERC's order, once it takes effect, will increase marketing opportunities for NOPSI, but will also expose NOPSI to the risk of loss of load or reduced revenues due to competition with alternative suppliers. In light of the rate issues discussed above, NOPSI is aggressively reducing costs to avoid potential earmngs crosions that might result as well as to successfully compete by becoming a low-cost producer. To help nummize future costs, NOPSI remams committed to least cost planning. In December 1992, NOPSI filed a Least Cost Integrated Resource Plan (Least Cost Plan) with its retail regulator. Izast cost planning includes demand-side measures such as customer energy conservation and supply-side measures such as more efficier.t power plants. Rese measures are designed to delay the building of new power plants for the next 20 years. NOPSI plans to periodically file revised least Cost Plans. The Enerev Policy Act of 1992 The Energy Policy Act of 1992 (Energy Act) is changing the transmission and distribution of electricity. This act encourages competition and affords us the opportunities, and the risks, associated with an open and more competitive market environment. The Energy Act increases competition in the wholesale energy market through the creation of exempt wholesale generators (EWGs). The Energy Act also gives FERC the authority to order investor-owned utilities to provide transmission access to or for other utilities, including EWGs.
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NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS NOTE 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES NOPSI maintains accounts in accordance with FERC and other regulatory guidelines. Cenain previously reponed amounts have been reclassified to conform to current classifications. Revenues and Fuel Costs Prior to January 1,1993, NOPSI recorded revenues when billed to its customers with no accrual for energy delivered but not yet billed. To provide a better matching of revenues and expenses, effective January 1,1993, NOPSI adopted a change in accounting principle to provide for accrual of the nonfuel portion of estimated unbilled revenues. The cumulative effect of this accounting change as of January 1,1993, increased net income by
$10.9 million. Had this new accounting method been in effect during prior years, net income before the cumulative effect would not have been materially different from that shown in the accompanying financial statements.
NOPSPs rate schedules include electric fuel adjustment and city gate gas cost adjustment clauses that allow deferral of fuel costs until such costs are reflected in the related revenues. Utility Plant Utility plant is stated at original cost. The original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Maintenance, repairs, and minor replacement costs are charged to operating expenses Substantially all of NOPSPs utility plant is subject to the liens ofits mortgage bond indentures. AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases utility plant and increases earmngs, it is only realized in cash through depreciation provisions included in rates. NOPSfs effective composite rates for AFUDC were 11.4%,12.1%, and 11.3% for 1993,1992, and 1991, respectively. Depreciation is computed on the straight-line basis at rates based on the estimated service lives and costs of removal of the various classes of property. Depreciation provisions on average depreciable property approximated 3.1% in 1993 and 1992, and 3.2% in 1991. Income Taxes i NOPSI, its parent, ed afIlliates (excluding GSU prior to 1994) file a consolidated federal income tax retum. Income taxes are al!ocated to NOPSI in proportion to its contribution to consolidated taxable income. SEC
)
regulations require that no System company pay more taxes than it would have had a separate income tax retum been filed. Deferred taxes are recorded for all temporary differences between book and taxable income. Investment j tax credits are deferred and amoniued based upon the average useful life of the related property in accordance with l I rate treatment. As discussed in Note 3, effective January 1,1993, NOPSI changed its accounting for income taxes to conform with SFAS 109. Other Noncurrent Liabilities l NOPSI records provisions for uninsured propeny risks and claims for injuries and damages through charges to operation expenses on an accrual basis. Provisions for these accruals, classified as other noncurrent liabilities, have been allowed for ratemaking purposes.
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NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS -(Continued) Cash and Cash Eauivalents N'9 PSI considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Fair Value Disciqmg ne estunated fair value amounts of financial instruments have been deternuned by NOPSI, using available market information and appropriate valuation methodologies. However, considerable judgment is required in developing the estimates of fair value. Herefore, ~hta are not necessarily indicative of the amounts that NOPSI could reahze in a current market :xchange. In addition, gains m losses rmhmi on fmancial instruments may be reflected in future rates and not accme to the benefit of stockholha. NOPSI considers the carrying amounts of fmancial instruments classified as current assets and liabilities to be a reasonable estunate of their fair value because of the short maturity of these instruments. In addition, NOPSI does not presently expect that perfonnance ofits obligations will be required in connection with certain off-balance sheet commitments and guarantees considered fmancial instrumente. Due to this factor, and because of the related party nature of these comnutments and guarantees, determination of fair value is not considered practicable. See Notes 5 and 6 for additional fair valee disclosure. NOTE 2. RATE AND REGULATORY MATTERS Rate Arreement In Noveraber 1993, the Council adopted resolutions accepting a proposal by NOPSI to settle certain issues related to the Merger. Pursuant to the resolutions, the Council agreed to withdraw fmm the SEC proceedmg related to the Merger. In return, NOPSI agreed, among other things, that retail ratepayers in the City of New Orleans would be protected from (1) increases in NOPSI's cost of capital resulting from risks associated with the Merger; (2) recovery of any portion of the acquisition premium or transactional costs associated with the Merger; (3) certain direct allocations of costs associated with GSU's River Bend nuclear unit; and (4) any losses of GSU resulting from resolution of litigation in connection with its ownership of River Bend. NOPSI was required to reduce its annual electric base rates oy $4.8 million effective for bills rendered on or after November 1,1993, and to expense its SFAS 106 costt NOPSI's SFAS 106 expenses through October 31,1996, will be allowed by the Council for j purposes of evaluating the appropriateness of NOPSI's retes. He Council also agreed not to seek to disallow the first $3.5 million of costs incurred through October 31,1993, in connection with the Least Cost Plan. l l Prudence Settlement and Finalized Phase-In Plan ne February 4 Resolution required NOPSI to write off, and not recover from its re' ail electric customers,
$135 million of its previously deferred costs asso~iated with Grand Gulf 1. This wTite-off, which was recorded in NOPSI's 1987 fmancial statements, was in addition to the $51.2 million of Grand Gulf 1-related costs originally absorbed and not recovered by NOPSI as part of the 1986 Rate Settlement. In 1991, NOPSI reached a settlement l (1991 NOPSI SN4 ment) with the Council and with the Alliance that resolved the Grand Gulf 1 prudence issues I and she pending litigation related to the February 4 Resolution.
ne 1991 NOPSI Settlement supersedes both the 1986 Rate Settlement (which established a rate phase-in plan designed to reduce the immediate effect on ratepayers of the inclusion of Grand Gulf I costs in rates) and the February 4 Resolution and provides that there will be no further disallowance of the recovery of any Grand
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NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS -(Continued) Gulf 1-related costs incurred by NOPSI based on any alleged imprudence by NOPSI that may have occurred or may be alleged to have occurred prior to the effective date of the 1991 NOPSI Settlement. He 1991 NOPSI Settlement included the following terms: (i) Effective Date Base Electric Ratesm October 4,1991 511.3 million decrease (2) October 31,1992 S 7.3 million increase October 31,1993 5 6.7 million increase (3) October 31,1994 $ 5.2 million increase October 31,1995 , S 4.4 million increase (1) nese changes are subject to adjustment to reflect implementation of the Least Cost Lan. (2) ne October 4,1991 decrease partly offset an April 1991 increase of $18.9 million. (3) His increase was partially offset by the $4.8 million base rate reduction described above. (ii)In connection with the rate changes set forth in (i) above, NOPSI implemented a habd phase-in plan covering a ten-year period from October 1,1991 through September 30,2001, for recovery of all Grand Gulf I deferred costs, including associated canying charges. (iii)NOPSI agreed to a five-year electric base rate freeze extending through October 31,1996, excluding the annual rate increases provided for in (i) above and except for increases to reflect an increase in state and/or federal income tax rates or a catastrophic event such as a hurricane. NOPSI also agreed that during the period October 1,1993 through October 31,1996 the Council will have the right to investigate the appropriateness of NOPSPs rates if NOPSPs return on average equity on its electric operations (calculated in accordance with the applicable provisions of the 1991 NOPSI Settlement) for twelve month periods subsequent to September 30,1992 were to exceed 13.76%, and, after heanng(s), to impose a credit on NOPSPs customen' bills in an amount that would have allowed NOPSI, during the l relevant test year, to eam a retum on equity incident to its electric operations of no less than 12.76% ne Council agreed otherwise not to reduce NOPSPs base electric rates during the period through l October 31,1996 except to reflect a decrease in state and/or federal mcome tax rates. ; l (iv) NOPSI will include in the "over/under" provision ofits fuel adjustment clause, on a monthly l basis, the difference, if any, between the non-fuel Grand Gulf I costs billed by System Energy to NOPSI l and the estunate of such costs attached to the 1991 NOPSI Settlement, with the Council having the right to suspend this provision in the event of a catastrophe involving Grand Gulf 1. In the event the Council suspends this provision, NOPSI will have the right to seek a rate increase notwiernding (iii) above. ; NOPSI recorded on its balance sheet in 1991 as a deferred asset an additional $90 million of previously incurred Grand Gulf 1-related costs with a corresponding pretax gain on the income statement. Ac $90 million represents the increase in the present value of the recovery stream of deferred Grand Gulf 1-related costs consistent with the recoverable costs as set forth in (ii) above. He gain increased 1991 net income by $48.6 million after taxes. l l i j
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NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS -(Continued) Gas Pete FilinE in May 1992, NOPSI and the Council reached a settlement regarding NOPSI's application for an increase in gas rates. The settlement includes the followinE terms, among others: (i) an aggregate net rate increase of $7.5 million, effective on May 22,1992, phased in over a two-year period. "Ibe year one net increase is stipulated to be $3.8 million, with an additional $3.0 million being defened for recovery in equal annual installments in years two through six. The net increase in year two of $3.7 million includes $730,000 for recovery of the costs deferred in year one (including associated carrying charges). (ii) except as provided above, and except for increases to reflect an increase in state and/or federal income tax rates or a catastrophic event such as a hurricane, NOPSI has agreed to a gas base rate freeze through October 31,1996. In addition, the settlement provides that earnmgs from gas operations will be included with those from electric operations for purposes of the retum on average equity ceiling provisions of the 1991 NOPSI Settlement (discussed above) and revises the method of calculating such return on equity ceiling. NOTE 3. INCOME TAXES Effective January 1,1993, NOPSI adopted SFAS 109. This new standard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that defened tax balances be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 requires that regulated enterprises recogmze adjustments resulting from implementation as regulatory assets or liabilities ifit is probable that such amounts will be recovered from or returned to customers in future rates. A substantial majority of the adjustments required by SFAS 109 was recorded to deferred tax balance sheet accounts with offsetting adjustments to regulatory assets and liabilities. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. As a result of the adoption of SFAS 109,1993 net income was increased by 50.3 million, assets were increased by $4.1 million, and liabilities were increased by $3.8 million. P
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i NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS -(Continued) t Income tax expense consisted of the following: For the Years Ended December 31. 1993 1992 1991 (In Thousands) Current:
^
Federal $ 23,400 $ 16,575 5 8,885 State 4.079 - - i Total 27.479 16.575 8.885 ! Deferred - net: Rate deferrals - net (7,395) (1,185) - 20,548 1989 Settlement As-seid - - 1,821 - Net operating loss carryforward utilization 42 2,747 15,186 Unbilled revenue 4,621 (2,800) 1,513 Pension expense 2,935 (1,044) (1,041) Liberalized depreciation (19) (286) (469) , Deferred fuel or gas costs 2,251 1,904 (479) Bond reacquisition 1,074 328 - Alternative Minimum Tax 2,317 .(3) (590) : Other (623) (1) 458 Total 5.203 (340) 36.947 Investment tax credit adjustments - net (743) (170) (592) Recorded income tax expense S 31.939 S 16.065 S45.240 Charged to operations S 24,232 S 14,382 341,998 Charged to otherincome 1,115 1,683 3,242 Charged to cumulative income . 6.592 - - Totalincome taxes S31.939 [jgfj, S45.240 Total income taxes differ from the amounts computed by applying the statutory federal income tax rate to income before taxes. The reasons for the differences were: For the Years Ended Decc..ber 31. 1993 1992 1991
% of % of % of Pretax Pretax Pretax !
Amount Income Amount income Amount Income (Dollars in Thousands) Computed at statutory rate $ 27,877 35.0 $ 14,446 34.0 $ 40,779 34.0 Increases (reductions) in tax resulting from: State income taxes net of federal income tax cffect 3,411 4.3 1,462 3.5 4,420 3.7 Depreciation (780) (1.0) (731) (1.7) (654) (0.6): ; Amortization ofinvestment tax credits (745) (0.9) (752) (1.8) (650) (0.6) 1 Recapture of prior years' consolidated l income tax savings 323 0.4 481 1.1 1,180 1.0 Amortization of excess deferred income tax 384 0.5 376 0.9 376 0.3 Adjustment of prior year taxes 2,413 3.0 391 0.9 (400) (0.3) l SFAS 109 adjustment (1,170) (1.5) - - - - l Other - net 226 0.3 391 0.9 189 02 Totalincome taxes S 31.939 40.1 S 16.064 37.8 545.240 37 7
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NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS - (Continued) Significant components of NOPSI's net deferred tax liabilities as of December 31,1993, were (in thousands): Deferred tax liabilities: Net regulatory assets S (13,465) Plant related basis differences (49,753) Rate deferrals (80,380) Other (5.194) Total $(148.792) Deferred tax assets: Unbilled revenues S 5,812 Accumulated deferrtxiinvestment tax credit 4,460 > Pension related items 5,804 Removal cost 8,197 Standard coal plant 2,861 Operating reserves 6,934 Other 4.660 Total 5 38.728 Net deferred tax liabilities $(110.064) NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS The SEC has authorized NOPSI to effect short-term borrowings of up to 543 million. This authorization is effective through November 30,1994. In addition, NOPSI can borrow from the Money Pool, subiect to its maximum authorized level of short-term borrowings and the availability of funds. NOPSI's short term borrowings are also limited by the terms ofits G&R Bond indenture to amounts not exceedmg, in general, the greater of 10% of capitalization or 50% of Grand Gulf I rate deferrals available to support the issuance of G&R Bonds. NOPSI had no outstanding short-term borrowings under these arrangements as of December 31,1993. 270
I NEW ORLEANS PUBLIC SERVICE INC. J NOTES TO FINANCIAL STATEMENTS - (Continued) i i NOTE 5. PREFERRED STOCK ; The number of shares and dollar value of NOPSl's cumulative, $100 par value preferred stock was: As of December 31. I Shares Call Price Per l Authorized and Total Share as of I Outstandine Dollar Value December 31, l 1993 1992 1993 1992 1993 , (Dollars in Thousands) 1 I Without sinking fund: 4 3/4% Preferred Stock 77,798 77,798 $ 7,780 $ 7,780 $105.00 4.36% Series 60,000 60,000 6,000 6,000 S104.58 5.56% Series 60.000 60,00Q 6.000 6.000 $102.59 Total without sinking fund 197.798 197.798 S19.780 $19.780 With sinking fund: l 15.44% Series 49.495 64.495 S 4.950 $ 6.450 $107.72 The fair value of NOPSl's preferred tock with sinking fund was **im*~4 to be approxunately $5.3 million and $6.5 million as of December 31,1993 and 1992, respectively. The fair value was determined using quoted market prices or estunates from nationally recosmzed investment banking firms. See Note 1 for additional information on disclosure of fair value of financial instruments. Changes in the preferred stock during the last three years were: Number of Shares 1993 1992 1991 Preferred stock retirements:
$100 par value (15,000) (15,000) (15,000)
Cash sinking fund requirements for the next five years for preferred stock outeanding as of December 31,1993, are $750,000 annually. NOPSI has the annual non-cumulative option to redeem, at par, up to an additional $750,000 ofits 15.44% Series preferred stock outstanding. NOPSI has regulatory authorization for the issuance and sale through December 31,1994, of up to $20 million of preferred stock and, for the acquisition through December 31,1994, of up to $6.5 million of its outstandmg preferred stock.
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NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS -(Continued) NOTE 6. LONG-TERM DEBT NOPSPs long-term debt as of December 31,1993 and 1992, was: Maturities interest Rates To 1993 1992 EE2m _IP_- fI.qm (In Thousands) First Mortgage Bonds 5-5/8% 11.0% $ 35,250 $ 60,250 1994 1998 10.0 %
- 30,000 2004 2008 9-1/2%
G&R Bonds 13.9% 69,200 113,600 1993 1998 10.95 % 7.0% 8.0% 100,000 - 1999 2023 (1.138) 17 Unamortized Premium and Discount-Net 203,312 203,867 Total Long-Term Debt 15.000 44.400 Less Amount Due Within One Year
$ 188.312 $ 159.467 Long-Term Debt Excluding Amount Due Within One Year The fair value of NOPSPs long-term debt as of December 31,1993 and 1992 was esumated to be (in millions) $211.5 and $216.1 respectively. Fair values were detennined using bid prices reported by dealer markets and by nationally recogmzed investment banking firms. See Note I for additional information on disclosure of fair value of fmancial instruments.
For the years 1994,1995,1996,1997, and 1998, NOPSI has long-tenn debt maturities and cash sinking fund requirements of (in millions) SIS, $24.2, $38.3, $27, and $0, respectively. In addition, other sinking fund requirements of approximately $0.2 million annually may be satisfied by cash or by certification of property additions at the rate of 167% of such requirements. NOPSI has regulatory authorization for the issuance and sale through December 31,1994, of up to
$145 million of G&R Bonds (of which $45 million remamed available as of December 31, 1993) and for the acquisition, through December 31,1994, in whole or in part, prior to their respective maturities, of up to $135 million ofits outstandmg first mortgage and/or G&R Bonds.
Under NOPSrs G&R Mortgage, G&R Bonds are issuable based upon 70% of bondable property additions or based upon 50% of accumulated deferred Grand Gulf 1-related costs. The G&R Mortgage precludes the issuance of any additional G&R Bonds if the total amount of outstandmg Rate Recovery Mortgage Bonds issued on the basis of the uncollected balance of deferred Grand Gulf 1-related costs exceeds 66 2/3% of the deferred costs. As of December 31,1993, the total amount of Rate Recovery Mortgage Bonds outstanding aggregated $69.2 million, or 30.2% of NOPSPs accumulated deferred Grand Gulf 1-related costs. NOTE 7. DIVIDEND RESTRICTIONS NOPSrs Restatement of Articles of Incorporation, as amended, and certain of its indentures contain provisions restricting the payment of cash dividends or other distributions on common stock. As of December 31,1993, $24.2 million of NOPSrs retained earmngs were restricted against the payment of cash dividends or other distributions on common stock.
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NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS - (Continued) NOTE 8. COMMITMENTS AND CONTINGENCIES Capital Reauirements and Financine Construction expenditures for the years 1994,1995, and 1996 are estimated to total $26 million each year. NOPSI will also require $80 million during the period 1994-1996 to meet long-term debt and preferred stock maturities and cash sinking fund requirements. NOPSI plans to meet the above requirements with internally generated funds and cash on hand. See Notes 5 and 6 regarding the possible refmancing, redemption, purchase, or other acquisition of certain outstanding series of preferred stock and long-term debt. Unit Power Sales Aercement System Energy has agreed to sell all ofits 90% owned and leased share of capacity and energy from Grand Gulf 1 to AP&L, LP&L, MP&L, and NOPSI in accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this agreement are paid in consideration for NOPSI's respective entitlement to receive capacity and energy, and are payable irrespective of the quantity of energy delivered so long as the unit remams in commercial operation. The agreement will remam in effect until termmated by the parties and approved by FERC, most likely upon Grand Gulf l's retirement from service. NOPSI's monthly obligation for payments under the agreement is approximately $9 million. Availability Acreement AP&L, LP&L, MP&L, and NOPSI are individually obligated to make payments or subordmated advances to System Energy in accordance with stated percentages (AP&L 17.1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 24.7%) in amounts that when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy's operating expenses. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Payments or advances under the Availability Agreement are only required if funds available to System Energy from all sources are less than the amount required undet the Availability Agreement. Since commercial operation of Grand Gulf 1, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments have ever been required. In 1989, the Availability Agreement was amended to proside that the write-off of $900 nullion of Grand Gulf 2 costs would be amortized for Availability Agreement purposes over a period of 27 years, in order to avoid the need for payments by AP&L, LP&L, MP&L, and NOPSL If AP&L, LP&L, or MP&L fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, NOPSI could be liab!c for payments to System Energy, in amounts that cannot be determmed, over and above its payments under the Unit Power Sales Agreement. Reallocation Arreement System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation Agreement relating to the sale of capacity and energy from the Grand Gulf Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and obligations with resyt to the Grand Gulf Station under the Availability Agreement. FERC's decision allocating a portion of Grand Gulf I capacity and energy to AP&L supersedes the Reallocation Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect AP&L's obligation to System Energy's lenders under the assignments referred to in the preceding paragraph. AP&L would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual obligations. No payments of any amortization amounts will be required as long as amounts paid to System Energy under the Unit
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NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS -(Continued) Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the l Availability Agreement, which is expected to be the case for the foreseeable future. System Fuels l 1 NOPSI has a 13% interest in System Fuels, a jointly owned subsiAy of AP&L, LP&L, MP&L, and j NOPSI. He parent companies of System Fuels, including NOPSI, agreed to make loans to System Fuels to i 1 nnance its fuel procurement, delivery, and storage activities. As of December 31,1993, NOPSI had approximately
$3.3 million ofloans outstandmg to System Fuels which mature in 2008.
City Franchise Ordinances NOPSI provides electric and gas service b the City of New Orleans pursuant to City franchise ordiraces which state, among other things, that the City has a continuing option to purchase NOPSfs electric and gas utility properties. NOTE 9. POSTRETIREMENT BENEFITS Pension Plan NOPSI is a panicipating employer in a defmed benefit pension plan sponsored by LP&L, covering substantially all employees. He pension plan is noncontributory and provides pension benefits based on employees' credited service and averpge compensation, generally during the last five years before iniuuat. Pension costs are funded in accordance with contribution guidelines established by the Employee Rettrement income Security Act of 1974, as amended, and the Intemal Revenue Code of 1986, as amended. He assets of the plan consist primarily of common and preferred stocks, fixed income securities, mterest in a money market fund, and insurance contracts. NOPSl's 1993,1992, and 1991 pension cost, including amounts capitahzed, included the following components: For the Years Ended December 31. 1993a 1992* 1991* (In Thousands) Service cost - benefits camed during the period S 1,387 51,253 $ 1,366 2,422 2,119 1,572 Interest cost on projected benefit obligation (49) 173 35 Net amortization and deferral
- - 600 Other Net pension cost S 3.760 E5,4,5, 5 M
- Pension cost represents NOPSrs allocated portion of the total pension expense (as calculated by an independent actuary) for the defined benefit pension plan sponsored by LP&L.
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NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS - (Continued) ne funded status of LP&L's pension plan allocable to NOPSI employees as of December 31,1993 and 1992, was: 1993 1992 (In Thousands) Actuarial present value of accumulated pension plan benefits: Vested S 26,173 $ 22,276 Nonvested 36 26 Accumulated benefit obligation S 26 209
- $ 22.302 Plan assets at fair value S 7,523 $ (2,289)
Projected benefit obligation 36.831 29.944 Plan assets less than projected benefit obligation (29,308) (32,233) Unrecogmzed prior service cost 2,462 2,702 Unrecogmzed transition asset (1,354) (1,550) Unrecognized net loss 12.184 7.920 (16,016) (23,161) Unfunded porthn of NOPSI pension liability 12.256 23.161 Accrued pension liability 5 (3.760) S - He significant actuarial assumptions used in computing the information above for 1993,1992, and 1991 were as follows: weighted average discount rate,7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in future compensation levels, 5 ' 4; and expected long-term rate of return on plan assets, 8.5%. Transition assets are being amortized over the average remanung service period of active participants. Other Postretirement Benefits NOPSI also provides certain health care and life insurance benefits for retired employees. Substantially all employees may become eligible for these benefits if they reach retirement age while still working for NOPSI. He cost of providing these benefits, recorded on a cash basis, to retirees in 1992 was approxunately $3.7 million. Prior to 1992, the cost of providing these benefits for retirees was not reparable from the cost of providing benefits for active employees. Based on the ratio of the number of retired emplo>tes to the total number of active and retired employees in 1991, the cost of providing these benefits in 1991, recorded on a cash basis, for retirees was approximately $2.6 million. Effective January 1,1993, NOPSI adopted SFAS 106. He new standard requires a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. NOPSI continues to fund these benefits on a pay-as-you-go basis. As of January 1,1993, the actuanally deterr:ined accumulated postrctirement beneSt obligation (APBO) camed by retirees and active employees was estimated to be approximately $53.6 million. His obligation is being amortized over a 20-year period beguuung in 1993. NOPSI is expensing its SFAS 106 costs pursuant to resolutions adopted in November 1993 by the Council related to the Merger. NOPSPs SFAS 106 expenses through October 31,1996, will be allowed by the Council for purposes of evaluating the appropriateness of NOPSPs rates. NOPSPs net mcome in 1993 was decreased by approximately $2.2 million as a result of adopting SFAS 106.
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NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS -(Continued) NOPSI's 1993 postretirement benefit cost, including amounts capitalized and deferred, included the following components (in thousands): Service cost - benefits earned during the period S 822 4,248 Interest cost on APBO - Actual return on plan assets Amortization of transition obligation 2.671 S 7.748 Net periodic postretirement benefit co;t ne funded status of NOPSI. postretirement plan as of December 31,1993, was (in thousands): Accumulated postretirement benc6t obligation: S 46,218 Retirees 3,565 Other fully eligible participants 9.152 Other active participants 58,935 Plan assets at fair value (58,935) Plan assets less than APBO 50,895 Unrecogmzed transition obligation 4.835 Unrecogmzed net loss Accrued post retirement benefit liability
$ (3.205) ne assumed health care cost trend rate used in measuring the APBO wss 9.9% for 1994, gradually decreasing mch successive year until it reaches 5.6% in 2020. A one percentage-point increase in the assumed health care cost trend rate for each year would have increased the APBO as of December 31,1993, by 7.7% and the sum of the senice cost and interest cost by approximately 9.6% The assumed discount rate and rate ofincrease in future compensation used in determining the APBO were 7.5% and 5.5%, respectively.
NOTE 10. TRANSACTIONS WITH AFFILIATES NOPSI buys electricity from and/or sells electricity to AP&L, LP&L, MP&L, and System Energy under rate schedules filed with FERC. In addition, NOPSI purchases fuel from System Fuels and receives technical and advisory senices from Entergy Senices, Inc. Operating revenues include revenues from sales to affiliates amounting to $2.5 million in 1993, 53.1 million in 1992, and $2.8 million in 1991. Operattng expenses include charges from affiliates for fuel costs, purchased power and related charges, and technical and advisory services totaling S176.3 mi!! ion in 1933 SI83.0 mi!! ion in 1992, and $187.9 million in 1991. l f
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NEW ORLEANS PUBLIC SERVICE INC. NOTES TO FINANCIAL STATEMENTS -(Concluded) NOTE 11. BUSINESS SEGMENT INFORMATION NOPSI supplies electric and natural gas services in the City. NOPSI's segment information follows: 1993 1992 1991 Electric Gas Electric Gas Electric Gas (In Thousands) Operating revenues $423,830 $90,992 $391,936 572,943 $399,214 $ 76,951 Revenue from sales to unaffiliated customers (1) S421,.143 $90,992 $388,851 $72,943 $396,456 576,951 Operating income (loss) before income taxes S 72,572 $11,412 5 63,167 5 1,264 $143,031 (2) $ (3,411) Operating income (loss) S 52,046 5 7,706 $ 47,194 S 2,855 $ 98,096 (2) S (474) Net utility plant $211,776 $63,803 $206,402 $61,783 $204,200 $ 59,237 Depreciation expense S 14,308 5 2,976 S 13,776 S 2,843 $ 13,278 $ 2,695 Construction expenditures S 19,774 S 5,039 $ 15,724 S 5,319 $ 18,084 S 4,451 (1) NOPSI's intersegment transactions are not material (less than 1% of sales to unaffilhted customers). (2) Operating income before income taxes and operating income reflect a nonrecurring increase of
$90.0 million and $48.6 million, respectively, in connection with the 1991 NOPSI Settlement.
NOTE 12. QUARTERLY FINANCIAL DATA (UNAUDITED) NOPSl's business is subject to seasonal fluctuations with the peak periods occurring during the third quarter for electric and during the first quarter for gas. Operating results for the four quarters of 1993 and 1992 were: ! Net I Operating Operating Income , I Revenues Income _ (Loss) (In Thousands) 1993: First Quarter (1) $108,566 S 8,828 $ 14,930 ; Second Quarter $120,182 $17,789 $ 12,714 l Rird Quarter $154,610 $29,648 $ 24,843 Fourth Quarter $131,464 $ 3,487 $ (4,778) 1992: First Quarter $106,598 SI1,423 $ 5,819 Second Quarter $101,993 5 7,382 S 1,672 nird Quarter $139,362 $25,551 S 19,931 Fourth Quarter SI16,926 5 5,693 5 (998) (1) ne first quarter of 1993 reflects a nonrecurring increase in net income of $10.9 million, net of taxes of
$6.6 million, due to the recording of the cumulative effect of the change in accounting principle for unbilled revenues (see Note 1). Beginning with the second quarter, the remauung quarters are not generally comparable to prior year quarters because of the ongoing effects of the accounting change.
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NEW ORLEANS PUBLIC SERVICE INC, SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1993 1992 1991 1990 1989 (In Thousands) S 514,822 S 464,879 5 476,165 5 485,246 S 470,909 Operating revenues Income before cumulative effect(,f a change in
$ 36,761 S 26,424 5 74,699 $ 27,542 S 14,464 accounting principle S 647,605 5 621,691 5 685,217 5 577,283 $ 564,251 Total assets S 193,262 S 165,917 5 231,901 $ 243,239 5 261,495 Long-term obligations (1) >
(1) Includes long-term debt (excluding currently maturing debt) and preferred stock with sinking fund. See Notes 1,3, and 9 for the effect of accounting changes in 1993. 1993 1992 1991 1990 1989 (Dollars in Thousands) Electric Operating Revenues: S 151,423 $ 137,668 $ 136,030 $ 141,900 $ 134,000 Residential 167,788 160,229 159,118 162,600 158,000 Commercial 26,205 23,860 24,062 27,000 25,200 Industrial 61.548 56.023 55.097 53.500 51.500 Governmental 406,964 377,780 374,307 385,000 368,700 Total retail 11,778 10,320 9,805 8,400 8,000 Sales for resale 5.088 3,$16 15.102 3.900 3.800 Other 5 423.830 $ 391.936 S 399.214 5 397.300 5 380.500 Total Billed Electric Energy Sales (Millions of KWH): 1,830 1,914 1,806 1,844 1,903 Residential 1,989 1,977 2,023 2,054 2,035 Commercial 499 457 487 530 490 Industrial 924 888 887 846 837 Govemmental ' 5,326 5,128 5,241 5,333 5,192 Total retail 351 405 418 294 284 Sales for resale 5.677 5.533 5.659 5.627 5.476 Total
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System Energy Resources, Inc./1993 Financial Statements
$systet"
\
y,nerg7 i
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SYSTEM ENERGY RESOURCES, INC. DEFINITIONS Certam abbreviations or acronyms used in System Energy's Financial Statements, Notes to Financial { Statements, and Management's Financial Discussion and Analysis are defmed below: Abbreviation or Acronym 1s_rni AFUDC Allowance for Funds Used During Construction ALJ Admmistrative Law Judge I AP&L Arkansas Power & Light Company APSC Arkansas Public Service Commission Capital Funds Agreement Agreement, dated as of June 21,1974, as amended, between System Energy and Entergy Corporation, and the assignments thereof City of New Orleans or City New Orleans, Louisiana DOE United States Department of Energy Entergy Operations Entergy Operations, Inc., a subsidiary of Entergy Corporation that has operating responsibility for Grand Gulf 1, Waterford 3, ANO, and River Berui Entergy or System Entergy Corporation and its various direct and indirect subsidiaries FASB Financial Accounting Standards Board FERC Fede a! Energy Regulatory Commission FERC Complaint Case Settlement Settlement, effective May 21,1991, whereby System Energy credited approximately 547.6 million in the aggregate (including interest) against its June 1991 bills to AP&L, LP&L, MP&L, and NOPSI for capacity and energy from Grand Gulf 1 FERC Return on Equity Case Settlement, effective October 25,1993, whereby System Energy refunded approximately $29.6 million in the aggregate (including interest) agamst its October 1993 bills to AP&L, LP&L, MP&L, and NOPSI when FERC reduced System Energy's Return on Equity from 13% to 11% prospectively from November 3,1992 Grand Gulf Station Grand Gulf Steam Electric Generating Station Grand Gulf 1 Unit No. I of the Grand Gulf Station I Grand Gulf 2 Unit No. 2 of the Grand Gulf Station l 1
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SYSTEM ENERGY RESOURCES,INC. DEFINITIONS -(Concluded) Abbreviation or Acronyni .Tsan GSU Gulf States Utilities Company (including wholly oned subsidiaries - Varibus Corporation, GSG&T, Inc., Prudential Oil and Gas, Inc., and Southem Gulf Railway Company) KWH Kilowatt-Hours LP&L Louisiana Power & Light Company LPSC Louisiana Public Service Commission Money Pool Entergy Money Pool which allows certain System companies t'; borrow from, or lend to, certain other System companies MP&L Mississippi Power & Light Company MPSC Mississippi Public Service Commission NOPSI New Orleans Public Service Inc. NRC Nuclear Regulatory Commission OBRA Omnibus Budget Reconciliation Act of 1993 Reellocation Agreement 1981 Agreement, superseded in part by a June 13,1985 decision of FERC, among AP&L, LP&L, MP&L, NOPSI, and System Energy relating to the sale of capacity and energy from the Grand Gulf Station SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards promulgated by the FASB SFAS 109 SFAS No.109, " Accounting for Income Taxes" SMEPA South Mississippi Electric Power Association System or Entergy Entergy Corporation and its various direct and indirect subsidiaries System Energy System Energy Resources, Inc. System Fuels System Fuels,Inc. System operating companies AP&L, GSU, LP&L, MP&L, and NOPSI, collectively Unit Power Sales Agreement Agreement, dated as of June 10,1982, as amended, among AP&L, LP&L, MP&L, NOPSI, and System Energy, relating to the sale of capacity and energy from System Energy's share of Grand Gulf 1
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l 1 SYSTEM ENERGY RESOURCES,INC. l REPORT OF MANAGEMENT The management of System Energy Resources, Inc. has prepared and is responsible for the fmancial statements and related fmancial information included herein. The financial statements are based on generally accepted accounting principles. Financial information included elsewhere in this report is consistent with the fmancial statements. To meet its responsibilities with respect to fmancial information, management maintains and enforces a system of internal accounting controls that is designed to provide reasonable assurance, on a cost effective basis, as to the integrity, objectivity, and reliability of the fmancial records, and as to the protection of assets. This system includes communication through written policies and procedures, an employee Code of Conduct, and an organizational structure that prosides for appropriate division of responsibility and the trammg of personnel. This system is also tested by a comprehensive intemal audit program. The independent public accountants provide an objective assessment of the degree to which management meets its responsibility for faimess of financial reporting. They regularly evaluate the system of internal accounting controls and perform such tests and other procedures as they deem necessary to reach and express an opinion on the fairness of the financial statements. Management believes that these policies and procedures provide reasonable assurance that its operations are carned out with a high standard of business conduct. DONALD C. HINTZ GERALD D. MCINVALE President and Chief Executive Officer Senior Vice President and Chief Financial Officer
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i l SYSTEM ENERGY RESOURCES,INC. < AUDIT COMMITTEE CHAIRMAN'S LETTER The Entergy Operations Board of Directors' Audit Comnuttee factions as the Audit Committee for System Energy. The Audit Committee is comprised of three directon, who are not officers of System Energy or Entergy Operations: Brooke H. Duncan (Chairman), Robert D. Pugh, and William Clifford Smith. The committee held four meetings during 1993. The Audit Committee oversees System Energy's fmancial reporting process on behalf of the Board of Directors and provides reasonable assurance to the Board that sufficient operating, accounting, and financial controls are in existence and are adequately reviewed by programs of internal and external audits.
'Ihe Audit Committee discussed with Entergy's internal auditors and the independent pubhc accountants (Deloitte & ToucM %e overall scope and specific plans for their respective audits, as well as System Energy's fmancial statemes and the adequacy of System Energy's internal controls. 'Ihe committee met, together and separately, with Entergy's internal auditors and independent public accountants, without management present, to discuss the results of their audits, their evaluation of System Energy's internal controls, and the overall quality of System Energy's financial reporting. The meetmgs also were designed to facilitate and encourage any private communication between the committee and the internal auditors or independent public accountants.
BROOKE H. DUNCAN Chairman, Audit Committee l l l 1
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INDEPENDENT AUDITORS' REPORT To the Shareholder and the Board of Directors of System Energy Resources,Inc. We have audited the accompanying balance sheets of System Energy Resources, Inc. (System Energy) as of December 31,1993 and 1992, and the related statements ofincome, retained earmngs, and cash flows for each of the three years in the period ended December 31, 1993. These fmancial statements are the responsibility of System Energy's management. Our responsibility is to express an opinion on these fmancial = tat-t< based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the fmancial statements are free of material misstatement. An audit includes examuung, on a test basis, evidence supporting the amounts and disclosures in the fmancial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall fmancial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the fmancial position of System Energy at December 31,1993 and 1992, and the resuhs ofits operations and its cash flows for each of the three years in the period ended December 31,1993 in conformity with generally accepted accounting principles. As discussed in Note 2, " Rate and Regulatory Matters - FERC Audit" of Notes to Financial Statements, a regulatory proceedmg is pending, which, if ultimately resolved in an adverse manner, would require that System Energy (1) write off and not recover in rates approximately $95 million of costs charged to utility plant resulting from System Energy's accounting for certain allocated income tax charges and (2) make refunds for overcollections from the Entergy System operating companies related thereto. 'Ihe ultimate outcome of this uncertainty cannot presently be determined. Accordingly, no provision has been made in the accompanying financial statements for the possible effects of a decision adverse to System Energy. I As discussed in Note 3 to the fmancial etatments, in 1993 System Energy changed its mebod of l accounting for income taxes. I I DELOITTE & TOUCHE New Orleans, Louisiana February 11,1994 l
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SYSTEM ENERGY RESOURCES,INC. BALANCE SHEETS ASSETS December 31, 1993 1992 (In Thousands) Utility Plant (Note 1):
$3,027,537 $3,019,241 Electric 437,941 437,317 Electric plant underlease (Note 8) 41,442 30,658 Constmetion work in progress 79,625 67,991 Nuclear fuel under capital lease (Note 7 and 8) 3,586,545 3,555,207 Total 669,666 572,302 Less - accumulated depreciation 2,916,879 2,982,905 Utility plant - net Other Investments:
24,787 19,127 Decommissioning trust funds (Note 7) Current Assets: Cash and cash equivalents (Note 1): 2,424 - Cash Temporary cash investments - at cost, which approxunates market 46,601 13,993 Associated companics (Note 4) 147,107 167,802 Other 196,132 181,795 Total cash and cash equivalents Accounts receivable: 57,216 60,601 Associated companies (Note 10) 2,057 4,871 Other 69,765 71,660 Materials and supplies - at average cost 63,400 47,900 Recoverable income taxes (Note 3) 4,835 3,497 Pnpapnents and other 393,405 370,324 Total Deferred Debits: 29,289 174,941 Recoverable income taxes (Note 3) SFAS 109 regulatory asset - net (Note 3) 384,317 - 17,258 14,723 Unamortizedloss on reacquired debt 125,131 110,421 Other(Note 7 and 8) 555,995 300,085 Total
$3,891,066 $3,672,441 TOTAL See Notes to Financial Statements.
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SYSTEM ENERGY RESOURCES,INC. BALANCE SHEETS CAPITALIZATION AND LIABILITIES December 31, , 1993 1992 ; (in Thousands) Capitalization: Conunon stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 1993 and 1992 $789,350 $789,350 - Paid-in capital 7 . Retamed earmngs (Note 6) 228,574 367,747 Total common shareholder's equity 1,017,931 1,157,097 Iong-term debt (Note 5) 1,511,914 1,755,308 Total 2,529,845 2,912,405 Other Noncurrent Liabilities: Obligations under capital 1 cases (Note 8) 24,679 12,991 Other(Note 7) 18,229 18,919 Total 42,908 31,910 Current Liabilities: Currently maturing long-term debt (Note 5) 230,000 30,000 Accounts payable: Associated companies (Note 10) 1,928 2,164 Other 18,223 33,110 - Taxes accrued 20,952 23,224 Interest accrued 48,929 50,560 Obligations under capital leases (Note 8) 55,000 55,000 Other 2,805 530 Total 377,837 194.588 Deferred Credits: l Accumulated deferred income taxes (Note 3) 775,630 349,081 Aramnia*M deferred investment tax credits (Note 3) 113,849 144,284 Other - 50,997 40,173 Total 940,476 533,538 Commitments and Contingencies (Notes 2,7, and 8) TOTAL $3,891,066 $3,672,441 , See Notes to Financial Statements.
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SYSTEM ENERGY RESOURCES,INC. ! l STATEMENTS OF CASH FLOWS 1 For the Years Ended December 31, 1993 1992- 1991 (In Thousands) Operating Activities: $104,622
$93,927 $130,141 Net income Noncash items included in net income 85,986 90,920 85,932 Depreciation and decommissioning -)
15,832 70,356 79,660 Deferred income taxes and investment tax credits (772) (681) (763) l Allowance for equity funds used during construction Amortization of debt discount 4,520 6,417 7,495 ) Changes in working capital: 6,199 225 (5,530) Receivables 37,511 (15,123) Q0,517) , Accounts payable (2,272) 2,672 (178) ) Taxes accrued (1,631) 1,252 (10,245) Interest accrued 2,832 (4,412) 15,716 Other working capital accounts 130,152 Q,475) (14.277) Recoverable income taxes (Note 3) (2,201) (4,911) (5,641) Decommissioning trust contributions (1,617) 86 (15,454) Other 318.056 252,355 282,342 Net cash flow provided by operating activities Investing Activities: (23,083) (21,671) (21,663) Construction expenditures 772 681 763 Allowance for equity funds used during construction Q2,822) (13,724) (28,922) Nuclear fuel purchases 32,822 28,094 14,552 Proceeds from sale and leaseback of nuclear fuel - 125,225 Change in other temporary investmeats (22.311) (6,620) 89,955 Net cash flow provided by (used in) investing activities Financing Activities: Proceeds from the issuance of first mortgage bonds 60,000 220,000 - (108,308) (240,750) (294,000) Reurement offirst mortgage bonds (233,100) (137,700) (115,785) Common stock dividend payments Net cash flow used in financing activities (281,408) (158,450) (409.785) 14,337 87,285 Q7,488) Net increase (decrease) in cash and cash equivalents 181,795 94,510 131.998 , Cash and cash equivalents at begmnmg of period
$196,132 $181.795 $94,510 Cash and cash equivalents at end of period SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
$186,786 $201,287 $238,199 Interest - net of amount capitalized
($65,992) $21,431 ($12,667) Income taxes (refund) Noncash investing and fmancing actinties:
$45,089 $28,094 $14,552 Capitallease obligations incurred See Notes to Financial Statements.
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SYSTEM ENERGY RESOURCES, INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS LIQUIDITY AND CAPITAL RESOURCES He fmancial condition of System Energy significantly depends on the continued commercial operation of Grand Gulf I and on the receipt of payments from AP&L, LP&L, MP&L, and NOPSI. Payments under the Unit Power Sales Agreement are System Energy's only source of operatmg revenues. Net cash flow from operations totaled $318 million, $252 million, and $282 million in 1993,1992, and 1991, respectively. In recent years, this cash flow has been sufficient to meet substantially all investing and fmancing requirements, including capital expenditures, dividends, and debt maturities. See Note 7, incorporated herein by reference, for information on System Energy's capital and refinancing requirements in 1994 - 1996. Funher, in order to take advantage oflower interest rates, System Energy may continue to refmance high-cost debt prior to maturity. In addition, System Energy's financial condition could be affected by the outcome of a pendmg FERC audit matter. In December 1990, FERC Division of Audits issued a report for System Energy that recommended that System Energy write off and not recover in its rates approximately $95 million of Grand Gulf I costs included in utility plant, and compute refimds for over collections from AP&L, LP&L, MP&L, and NOPSL In August 1992, FERC issued an opinion and order (August 4 Order) afYirming an initial decision by a FERC ALJ. System Energy filed a Request for Rehearing, and in October 1992, FERC issued an order allowing additional time for its consideration of the request, and it deferred System Energy's refund obligation until 30 days after FERC issues an order on rehearing. If the decision is implemented, System Energy estunates that as of December 31,1993, net income would be reduced by $151.6 million. This amount includes refund obligations of approximately S I 13.0 million (including interest). See Note 2, incorporated herein for reference, for additional information. Eammgs coverage tests, bondable property additions, and equity ratio requirements contained in its mortgage, and in iu letters of credit and reimbursement agreement in connection with its sale and leaseback transactions, limit the amount of first mortgage bonds that System Energy can issue. Based on the most restrictive applicable tests as of December 31,1993, and assuming an annual interest rate of 8%, System Energy could have issued $290 million of additional first mortgage bonds. System Energy has the conditional ability to issue first mortgage bonds against the retirement of first mortgage bonds, in some cases, without satisfying an earmngs coverage test. In connection with the fmancing of Grand Gulf 1, Entergy Corporation has undertaken, in the Capital Funds Agreement, to provide to System Energy sufficient capital to (1) maintain System Energy's equity capital at an amount equal to at least 35% of System Energy's total capitalization (excluding short-term debt), (2) permit the continuation of commercial operation of Grand Gulf 1, and (3) enable System Energy to pay in full all borrowings, whether at maturity, on prepayment, on acceleration, or otherwise. In addition, Entergy Corporation has agreed in the Capital Funds Agreement to make certain cash capital contributions, if required, to enable System Energy to make payments when due on specific issues ofits long-term debt. See Note 4, incorporated herein by reference, for information regarding System Energy's short-term borrowings.
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SYSTEM ENERGY RESOURCES,INC. STATEMENTS OF INCOME For the Years Ended December 31, 1993 1992 1991 (In Thousands)
$650,768 $723,410 5686,664 Operating Revenues (Note 2):
Operating Expenses Operation (Note 10): Fueli electric generation 42,296 55,110 78,060 and fuel-related expenses 114,086 102,971 79,494 Other 21,263 29,370 14,358 Maintenance (Note 10) 90,920 90,628 87,296 Depreciation and decommissioning (Note 7) 26,589 28,717 27,342 Taxes other than income taxes 83,412 93,438 81.302 Income taxes (Note 3) 378,566 400,234 367,852 Total 272,202 323,176 318,812 Operating Income Other Income: Allowance for equity funds used 772 681 763 during construction 6,518 5,816 6,378 Miscellaneous - net 4,859 4,584 7,726 Income taxes (Notes I and 3) 12,149 11,081 14,867 Total Interest Charges: 184,818 196,618 218,538 Interest on long-term debt 6,120 7,923 11,111 Otherinterest net Allowance for borrowed funds used during construction (514) (425) ~ (592) 190,424 204.116 229,057 Total S93,927 $130,141 $104,622 j Net income See Notes to Financial Statements. l
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b* " l J J-~ , SYSTEM ENERGY RESOURCES,INC. STATEMENTS OF RETAINED EARNINGS For the Years Ended December 31, 1993 1992 1991 (la Thousands) l l Retained Earnings, January 1 $367,747 $375,306 $386,469 ! Add: Net income 93,927 130,141 104,622 Total 461,674 505,447 491,091 l' Deduct: Dividends declared 233,100 '137,700 115,785 Retamed Earmngs, December 31 (Note 6) $228,574 $367,747 $375.306 See Notes to Financial Statements. h I I i i l i
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SYSTEM ENERGY RESOURCES,INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Net Income Net income decreased in 1993 primarily due to the impact of the FERC Return on Equity Case settlement regarding the return on equity component of System Energy's formula wholesale rates (see Note 2, incorporated herein by reference). His decrease in revenue was partially offset by a reduction in interest expense due to the refmancing of high-cost debt. Net mcome increased in 1992 primarily due to the impact of the FERC Complaint Case settlement recorded in June 1991, which reduced net income in 1991. See Note 2, incorporated herem by reference, for further information on this sett!cment in addition,1992 net income was imp *i by a reduction in interest expense (as a result of the repayment of and refundmg of higher cost debt) not recovered through rates and the lower retum System Energy camed on its net imestment in Grand Gulf I during 1992. Significant factors affecting the results of operations and causing vanances between the years 1993 and 1992, and 1992 and 1991 are discussed under " Revenues" and " Expenses" below. Revenues System Energy's operating revenues recover operatmg expenses, depreciation, and capital costs attributable to Grand Gulf 1. He capital costs are computed by allowing a return, currently set at a rate of 11.0%, (see Note 2, incorporated herem by reference, for further information on the FERC Return on Equity Case) on System Energy's common equity funds allocable to its investment in Grand Gulf 1 plus System Energy's effective interest cost for its debt allocable to this investment. Operating revenues decreased in 1993 due primarily to the effect of the FERC Return on Equity Case settlement which reduced System Energy's return on equity as discussed in " Net Income" above and a lower return on System Energy's decreasing investment in Grand Gulf 1 (caused by depreciation of the unit). Future revenues attributable to the return on equity will consequently be lower as a result of the reduction in return on equity. Also, future revenues attributable to the return on investment are expected to decline each year as a result of the depreciation of System Energy's investment in Grand Gulf 1. Operating revenues were higher in 1992 due primarily to the effect of the FERC Complaint Case We in 1991. He higher operating revenues in 1992 l also reflect the increase in 1992 operatmg expenses primarily associated with the scheduled fifth refueling outage l partially offset by a lower return earned on its imestment in Grand Gulf I resulting from a decrease in net unit imestment. i l l 292 -
I l SYSTEM ENERGY RESOURCES,INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS -(Concluded) d Expenses Grand Gulf I was t;n-line for 284 of 365 days in 1993 as compared with 298 of 366 days in 1992. The unit capability factor, which is a measure of the unit's performance (based on a ratio of avadable energy generation to the maximum power capability multiplied by the period hours), was 76.1% for 1993 as compared with 79.9% for 1992. These vanances are pnmarily due to the unit's sixth and fifth refueling outages that lasted from September 28, 1993 to December 3,1993, (67 days) and April 17,1992 to June 9,' 1992; (52 days), respectively and, to a lesser extent, to unplanned outages in September 1993 (14 days) and January 1992-(10 days). These outages contributed significantly to the decrease in fuel for electnc generation and fuel related expenses. The decrease in fuel expense in 1993 and 1992 is also due to refuchng with less expensive nuclear fuel. (Approximately one-third of the reactor core was replaced during each outage.) Increased operatmg efficiency also contributed to the 1993 decrease. Nonfuel operation and mamtenance expense increased in 1992 due primarily to the fifth refueling outage as mentioned above. The FERC Complaint Case settlement, recorded by System Energy in June 1991, contributed to fluctuations in 1992 operstmg results. Other operation expense mcreased in 1992 due, in part, to the provision of that settlement that called for 1991 credits from S>m Energy to AP&L, LP&L, MP&L, and NOPSI relating to System Energy's rate treatment of the portions of Grand Gulf I sold and leased back. Total income taxes decreased in 1993 due pnmarily to lower pretax book income partially offset by an increase in the federal income tax rate as a result of OBRA. Income taxes increased in 1992 due pnmarily to the effects of the FERC Complaint Case settlement. I J e I l
-i
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i I SYSTEM ENERGY RESOURCES,INC. MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS SIGNIFICANT FACTORS AND KNOWN TRENDS l
- FTRC Audit r
See Note 2, incorporated herein by reference, for information with respect to possible wTite-offs and t refunds which may result from a decision issued by FERC. I r l l i I i 1 l l l l 294
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SYSTEM ENERGY RESOURCES,INC. NOTES TO FINANCIAL STATEMENTS , NOTE 1.
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES System Energy maintains accounts in accordance with FERC guidelines. Certain previously reported amounts have been reclassified to conform to current classifications. Orranization System Energy is a generating company providing electricity to AP&L, LP&L, MP&L, and NOPSI and has a 90% interest in Grand Gulf 1, a nuclear generatmg station that began cor.unercial operation in 1985. In June 1990, Entergy Operations assumed responsibility for the operation and maintenance of Grand Gulf 1. System Energy has a combined ownership and leaschold interest of 90% and SMEPA has an undivided ownership interest of 10% in Grand Gulf 1. System Energy records its investment associated with Grand Gulf I to the extent to which it owns and maintains a leasehold interest in the generating station. Likewise, System Energy's operating expenses reflected in the accompanying financial statements represent 90% of such Grand GulfI expenses Ulility Plant Utility plant is stated at original cost. The original cost of utility plant retired or removed, plus the applicable removal costs, less salvage, is charged to accumulated depreciation. Mh==. repairs, and nunor replacement costs are charged to operating expenses Substantially all of the utility plant owrai by System Energy is subject to the lien ofits first mortgage bond inderture. AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases utility plant and represents current cammgs, it is only realized in cash through depreciation provisions included in rates. System Energy's effective composite rates for AFUDC were 11.6%,12.3%, and 12.4% for 1993,1992, and 1991, respectively. Utility plant inclnt % portions of Grand Gulf 1 that were sold and are currently under lease. System Energy retired this propert; e its continuing property records as formerly owned property released from and no longer subject to System Erugy's mortgage and deed of trust. System Energy is reflectmg such leased property for financial reporting purposes as property under lease from others and is depreciating this property over the life of the basic lease term. Such depreciation is being deferred until recoverable from customers in future periods. See Note 8. Depreciation is computed on a straight-line basis at rates based on the estunated service lives and costs of removal of the various classes ofproperty. Depreciation provisions on average depreciable property approximated
~
2.9% in 1993,1992, and 1991. Income Taxes System Energy, its parent, and affiliates (excluding GSU prior to 1994) file a consolidated federal income tax return. Income taxes are allocated to System Energy in proportion to its contribution to consolidated taxable income. SEC regulations require that no System compary pay more taxes than it would have had a separate income tax return been filed. Deferred taxes are recorded for all temporary differences between book and taxable income. Imtsunent tax credits are deferred and amortized based upon the average useful life of the related 295 -
SYSTEM ENERGY RESOURCES,INC. NOTES TO FINANCIAL STATEMENTS -(Continued) property in accordance with rate treatment. As discussed in Note 3, effective January 1,1993, System Energy changed its accounting for income taxes to conform with the SFAS 109. In addition, System Energy files a consolidated Mississippi state income tax return with certain other System companies. Cash and Cash Eouivalents System Energy considers all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Fair Value Disclosure The estimated fair value amounts of financial instruments have been determmed by System Energy, using available market information and appropri te valuation methodologies. However, considerable judgment is required in developing the estunates of fair value. Therefore, estunates are not necessarily indicative of the amounts that System Energy could realize in a current market exchange. In addition, gains or losses realized on financial mstruments may be reflected in future rates and not accrue to the benefit of stockholders. System Energy considers the carrying amounts of financial mstruments classified as current assets and liabilities to be a reasonable estunate of their fair value because of the short maturity of these mstruments. In addition, System Energy does not presently expect that performance ofits obligations will be required in connection with certain off-balance sheet commitments and guarantees considered f.nancial instruments. Due to this factor, and because of the reind party nature of these commitments and gucrantees, determmation of fair value is not considered practicable. See Notes 5 and 7 for additional fair value disclosure. NOTE 2, RATE AND REGULATORY MATTERS FERC Audit In December 1990, FERC Division of Audits issued a report for System Energy for the years 1986 through 1988. The report recommended that System Energy (1) write off and not recover in rates approxunately 595 million of Grand GulfI costs included in utility plant related to certam System income tax allocation procedures (and System Energy's accountmg resulting from certain allocated income tax charges) alleged to be inconsistent with FERC's accounting requirements and (2) compute refunds for the years 1987 to date to correct for over collections from AP&L, LP&L, MP&L, and NOPSI. In August 1992, FERC issued an opinion and order (August 4 Order) which found that System Energy overstated its Grand Gulf I utility plant account by approxunately $95 million as indicated in FERC's report. The order required System Energy to make adjusting accounting entries and refunds, with interest, to AP&L, LP&L, MP&L, and NOPSI within 90 days from the date of the order. System Energy filed a Request for Rehearing, and in October 1992, FERC issued an order allowing additional time for its consideration of the request. In addition, it deferred System Energy's refund obligation until 30 days after FERC issues an order on rehearmg. Should such refunds and adjusting entries be necessary, System Energy edi=tes that as of December 31,1993, its net income i would be reduced by approximately M52.3 million. This amount includes System Energy's potential refund obligation which is esumated to be $113.0 million (including interest) as of December 31,1993. The ongoing effect of this order, ifimplemented, would be to reduce System Energy's revenues by approximately S19.8 million
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SYSTEM ENERGY RESOURCESc INC. NOTES TO FINANCIAL STATEMENTS -(Continued) during the first twelve months following the write-off and by a comparable amount (but decreasing by approximately 50.4 million per year) in each subsequent year. If the August 4 Order is implemented, System Energy would need the consent of certam banks to temporarily waive the fixed charge coverage and equity ratio covenants in the letters of credit and reimbursement agreement related to the Grand Gulf I sale and leaseback transactions (see Note 7) in order to avoid violation of the covenant. System Energy has obtained the consent of the banks to waive these covenants, for the 12-month period beginning with the earlier of the write-off or the first refund, if the August 4 Order is implemented prior to December 31,1994. The waiver is conditioned upon System Energy not paying any common stock dhidends to Entergy Corporation until the equity ratio covenant is once again met. Absent a waiver, System Energy's failure to perform these covenants could cause a draw under the letters of credit and/or early tenmnation of the letters of credit. If the letters of credit were not replaced in a timely manner, a default or early tennination of System Energy's leases could result. System Energy believes that its consolidated income tax accounting procedures and related rate treatment are in compliance with SEC and FERC requirements and is vigorously contesting this issue. He ultimate resolution of this matter cannot be predicted. FERC Return on Eaulty Case In August 1992, FERC instituted an investigation of the return on equity (ROE) component of all formula wholesale rates for System Energy as well as AP&L, LP&L, MP&L, and NOPSL Payments received by System Energy under the Unit Power Sales Agreement are its only source of operatmg revenue. Rates under the Unit Power Sales Agreement are based on System Energy's cost of service including a return on common equity which had been set at 13% (see below). In August 1993, Entergy and the state regulatory agencies that intervened in the proceedmg reached an agreement (Settlement Agreement) in this matter. He Settlement Agisirsit, which was approved by FERC on October 25,1993, provides that an 11.0% ROE will be included in the formula rates under the Unit Power Sales Agreement. He Unit Power Sales Agreement formula rate, including the 11.0% ROE component, will remam in effect without change for two years, until early August 1995. System Energy's refunds payable to AP&L, LP&L, MP&L, and NOPSI, which were due prospectively from November 3,1992, were reflected as a credit to their bills in October 1993. Rese refunds decreased System Energy's 1993 revenues and net income by approximately $29.4 million and $18.2 million, respectively. ; l FERC Comolaint Case Settlement i in Febmary 1990, the APSC, the LPSC, the MPSC, the Mississippi Attorney General, and the City of New Orleans ud a complaint with FERC against System Energy and Entergy Services, Inc. (as agent for Entergy Corporation, AP&L, LP&L, MP&L, and NOPSI) alleging that the rates being charged to AP&L, LP&L, MP&L, and NOPSI by System Energy for capacity and energy from Grand Gulf I were notjust and reasonable. This filing j was consolidated with proceedmgs related to System Energy's decommissioning collections. la May 1991, a settlement was reached which, among other things (1) reduced System Energy's rate of return on common equity from 14% to 13% effective retroactively to April 1990 (pursuant to a subsequent l settlement in the FERC Return on Equity Case - see above - the allowed rate of return was funher reduced to 11% l effective November 3,1992); (2) imposed no ceiling for ratemakmg purposes on System Energy's common equity i ratio; (3) established a zero cash working capital allowance, effective retroactively to April 1990; (4) resohed the cost of service treatment of cenain Grand Gulf 2 assets transferred to Grand Gulf 1; (5) set the amount to be
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SYSTEM ENERGY RESOURCES,INC. NOTES TO FINANCIAL STATEMENTS -(Continued) collected in rates for the cost of de==iesioning System Energy's 90% interest in Grand Gulf I at appronmately
$198 million in 1989 dollars (with a rew study of these costs to be prepared and submitted to FERC on or before June 1,1995); (6) increased System Energy's decommissioning expense collections from appronmately $1.1 million to approximately $4.3 million per year, effective retroacively to June 1990, subject to a 5% annual inflation adjustment; and (7) provided for 1991 credits from System Energy to AP&L, LP&L, MP&L, and NOPSI totaling approximately $17 million relating to System Energy's rate treatment of the portions of Grand Gulf I sold and leased back. The settlement did not resolve income tax secwnting issues raised in the complaint (see "FERC Audit" above). The settlement was approved by FERC in September 1991.
Based on the settlement, System Energy credited in 1991 appronmately $47.6 mdhon in the aggregate (including interest) agamst its bills to AP&L, LPE, MP&L, and NOPSI for capacity and energy from Grand Gulf 1. As a result of the FERC Complaint Cee We 1991 net mcome was reduced by appronmately
$36.0 million, of which approximately $15.8 million relates to billings in 1990.
NOTE 3. INCOME TAXES Effective January 1,1993, System Energy adopted SFAS 109. This new standard requires that deferred income taxes be recorded for all temporary differences and carryforwards, and that deferred tax balances be based on enacted tax laws at tax rates that are expected to be in effect when the temporary differences reverse. SFAS 109 requires that regulated enterprises recogmze adjustments resulting from implementation as regulatory assets or liabilities ifit is probable that such amc'mts will be recovered from or returned to customers in future rates. A substantial majority of the adjustments required by SFAS 109 was recorded to deferred tax balance sheet accounts with offsetting adjustments to regulatory assets and liabilities. The cumulative effect of the adoption of SFAS 109 is included in income tax expense charged to operations. As a result of the adoption of SFAS 109,1993 net income was increased by $0.4 million, assets were increased by $327.9 million, and liabilities were mercased by
$327.5 million.
h
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SYSTEM ENERGY RESOURCES,INC. NOTES TO FINANCIAL STATEMENTS - (Continued) , l Income tax expense consisted of the following: For the Years Ended December 31. , .l 1993 1992 1991 ; (In Thousands) Current: Federal 5 59,049 S 13,890 $ (31,900) State 3.671 6.786 5.052 , Total 62.720 20.676 (26.848) Deferred - net: Liberalized depreciation 46,600 43,873 45,551 ; Nuclear fuel 2,706 (3,299) (2,927) l Capitahzed interest (456) (1,402) (1,441) Taxes capitalized (929) (935) (572) i Decontamination and decommissioning fund 5,601 - - Bond reacquisition (787) 852 (1,857) Sale and leaseback (4,057) (4,122) (4,044) ! Other (2.394)~ 3.088 2.458 , Total 46.284 38.011 37.168 Investment tax credit adjustments - net (30.452) 30.123 63.256 , M Recorded income tax expense S 78.552 L73 Charged to operations $ 83,412 5 93,438 5 81,302 Credited to other income (4.859) (4.584) (7.726) Recorded income tax expense 78,553 88,854 73,576 Income taxes applied agamst the debt w...yosest of AFUDC - 253 352 Totalincome taxes S 78.553 5 89.107 5 73.928 Total income taxes differ from the amounts computed by applying the statutory federal mcome tax rate to income or loss before taxes. The reasons for the differences were: For the Years Ended Dm...kr 31. 1993 1992 1991
% of % of % of Pretar Pretas Pretar Amount income Amount income Amount I!!sm!!8 1
(Dollars in Thousands) Computed at statutory rate 560,368 35.0 $ 74,458 34.0 $ 60,587 34.0 Increases (reductions) in tax resulting from: Depreciation 12,839 7.4 11,520 5.3 8,343 4.7 State income taxes net of federal income tax effect 6,778 3.9 8,380 3.8 6,0'4 3.4 Amortization ofinvestment tax credits (3,759) (2.2) (3,865) (1.8) (1,92.8) (1.1) Other -(net) 2.327 _ Li .,_(.L612) (D7) 490 __Ql Recorded income tax expense 78,553 45.5 88,854 40.6 73,576 41.3 Income taxes applied against the debt component of AFUDC - - 253 __.Ql 352 __9.2 Totalincome taxes S 78.553 ,,4,f,,j, S 89.107 ,,4,,pl 5 73.928 41.5
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,e,
SYSTEM ENERGY RESth TRCES,INC. NOTES TO FINANCIAL STATEMENTS - (Continued) Significant components of System Energy's net deferred tax liabilities as of December 31,1993, were (in thousands): Deferred tax liabilities: Net regulatory assets $(425,318) , Plant related basis differences ($52,782) Other (16.343) Total $(994.443) Deferred tax assets: Sale and leaseback $ 142,850 Accumulated deferred investment tax credit 43,547 Alternative nummum tax credit 20,452 Recoverable income tax 92,689 Other 11.964 Total S 311.502 Net deferred tax liabilities S(682.941) Recoverable income taxes include the tax effects of the substantial loss generated in September 1989 by the Grand Gulf 2 write-off. Th: loss increased System Energy's tax net operating loss carryforward to a total of approximately $265.5 million as of December 31,1993, which may be utilized in the future to offset taxable income. If not utilized to offset Federal taxable income, income tax benefits related to the net operating loss carryforwards will expire in the years 2004 through 2007. In connection with an Internal Revenue Senice (IRS) audit of Entergy's 1988,1989, and 1990 consolidated federal income tax returns, the IRS is proposing that adjustments be made to the Grand Gulf 2 abandonment loss deduction clanned on Entergy's 1989 consolidated federal income tax return. If any such adjustments are necessary, the effect on System Energy's net income should , l be immaterial. Entergy intends to contest the proposed adjustments if finalized by the IRS. He outcome of such proceedings cannot be predicted at this time. He alternative muumum tax (AMT) credit at December 31,1993, was $20.5 million. His AMT credit can be carried forward indefmitely and will arduce System Energy's federal income tax liability in the future. NOTE 4. LINES OF CREDIT AND RELATED BORROWINGS 1 i ne SEC has authorized System Energy to effect short-term borrowings up to $125 million, subject to f increase to as much as $238 million after further SEC approval. These authorizations are effective through i November 30,1994. In addition, System Energy can borrow from the Money Pool, subject to its maxunum authorized level of short-term borrowings and the availability of funds. System Energy had no short-term borrowings or bank lines of credit as of December 31,1993, i 300 -
l SYSTEM ENERGY RESOURCES,INC. NOTES TO FINANCIAL STATEMENTS -(Continued) NOTES. LONG TERM DEBT - The long-term debt of System Energy as of Decen > . ,1993 and 1992, was as follows: Msturities Interest Rates ; ft9m .lt - EE92 .12.- 1993 1992 ! (In Thousands) First Mortgage Bonds ! 1994 1998 6.0% 14%* $ 615,000 $ 555,000 1999 2003 8-1/4% 11 % 130,000 235,000 2016 11-3/8 % 90,319 90,319 Governmental Obligations" 2013 2016 8-1/4% 12-1/2 % 416,600 416,600 Grand Gulf Lease Obligation,7.02% (Note 8) 500,000 500,000 Unamortized Discount (10.005) (11.611) Total Long-Term Debt .1,741,914 1,785,308 . Iess Amount Dee Within One Year 230.000 30.000 Long-Term Debt Excluding Amount Due Within One Year $ 1.511.914 m
- h 14% series of $200 million is duc 11/15/94. All other series are at interest rates within the range of 6 % - 11.375 %.
" Consists of pollution control bonds, certam series of which are secured by non-interest beanng first !
mortgage bonds ; The fair value of System Energy's long-term deb, excluding Grand Gulf lease obligation, as of ; December 31,1993 and 1992, was estunated to be $1,397.8 mdlion and $1,442.7 mdhon, respectively. Fair values were determined using bid prices reported by dealer markets and by nationally recogmzed investment bankmg .j firms. For the years 1994,1995,1996,1997, and 1998 System Energy has long-term debt maturities and smkmg ; fund requirernents (in millions) of $230, $135, $250, $10, ami $70, respectively. i System Energy has SEC authorizati'.a for the issuance and sale of up to $500 nulhon of first mortgage , bonds through Dwrd,er 31,1994, (of which $220 million remamed avadable as of December 31,1993). In i addition, System Energy has SEC authornanon for the acquisition of not more than $500 milhon ofits ouwdag first mortgage bonds through December 31,1964, all of which remained available as of D-M 31,1993. NOTE 6. DIVIDEND RESTRICTIONS Various agrxments relating to the long-term debt of System Energy restrict the payment of cash dividends or other distributions en its common stock. As of December 31,1993, $152.7 nulhon of System Energy's retamed carmngs were nestricted agamst the payment of cash dividends or other distributions on common stock. On l February 1,1994, System Energy paid Entergy Corporation a $57.8 nulhon cash dividend on common stock. l 1
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l 1 SYSTEM ENERGY RESOURCES,INC. NOTES TO FINANCIAL STATEMENTS -(Continued) NOTE 7. COMMITMENTS AND CONTINGENCIES Caoital Reavirements and Financine ! l i Construction expenditures (excluding nuclear fuel) for the years 1994,1995, and 1996 are estimated to total $26 million, $22 million, and $23 million, respectively. System Energy will also require 5615 million during l the period 1994-1996 to meet long-term debt and preferred stock maturities and sinking fund requirements. System Energy plans to meet the above requirements with internally generated funds and cash on hand, supplemented by the issuance oflong-term debt. See Note 5 for the possible issuance of new first mortgage bonds and the potential refundmg, redemption, purchase, or other acquisition of certain series of outstandmg first mortgage bonds. Caoital Funds Arreement Entergy Corporation has agreed to arrange for or supply to System Energy sufficient amounts of capital to (1) maintain System Energy's equity capital at not less than 35% of System Energy's total capitalization (excluding short-term debt) and (2) con'.inue commercial operation of Grand Gulf I and enable System Energy to pay its borrowings under any circumstances. In addition, under supplements to the Capital Funds Agreement assigning System Energy's rights as r.ecurity for specine debt of System Energy, Entergy Corporation has agreed to make cash capital contributions ta enable System Energy to make payments on such debt when due. System Energy has entered into various agreements with AP&L, LP&L, MP&L, and NOPSI, whereby AP&L, LP&L, MP&L, and NOPSI are obligated to purchase their respective entitlements of capacity (discussed below) and energy from System Energy's 90% ownership and leaschold interes* in Grand Gulf 1, and to make 1 payments that, together with other available funds, are adequate to cover System bergy's operating expenses. System Energy would have to secure funds from other sources, including Entergy's obligations under the Capital Funds Agreemere, to cover any shortfalls from payments received from AP&L, LP&L, MP&L, and NOPSI under these agreements. Unit Power Sale 9 Arreement System Energy has agreed to sell all ofits 90% owned and leased share of capacity and energy from Grand Gulf 1 to APB.L. LP&L, MP&L, and NOPSI in accordance with specified percentages (AP&L 36%, LP&L 14%, MP&L 33%, and NOPSI 17%) as ordered by FERC. Charges under this agreement are paid in consideration for the respectise entitlements of AP&L, LP&L, MP&L, and NOPSI to receive capacity and energy, and are payable irrespective of the quantity of energy delivered so long as the unit remams in commercial operation. He agreement will remain in effect until ternunated by the parties and approved by FERC, which most likely would occur after Grand Gulf l's retirement from service. He monthly obligation for payments from AP&L, LP&L, MP&L, and NOPSI to System Energy is approxunately $54 nullion. Availability Acreement 1 i AP&L, LP&L, MP&L, and NOPSI are individually obligated in accordance with stated percentages (AP&L 17,1%, LP&L 26.9%, MP&L 31.3%, and NOPSI 24.7%) to make payments or subordmated adunces to System Energy in amounts that, when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy's operating expenses as defined, including an amount sufficient to amortize Grand Gulf 2 over 27 years, as discussed below. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Papnents or advances under the Availability Agreement are only required if funds available to System Energy from all sources are less than the amount required under the Availability Agreement. Since commercial operation of Grand Gulf 1, papnents under
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SYSTEM ENERGY RESOURCES, INC. NOTES TO FINANCIAL STATEMENTS -(Continued) the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments have ever been required. In 1989, the Availability Agreement was amended to proside that the write-off of approximately $900 million of Grand Gulf 2 costs would be amortized for Availability Agreement purposes over a period of 27 years, in order to avoid the need for payments under the Availability Agreer,ent by AP&L, LP&L, MP&L, and NOPSI. Reallocation Arreement System Energy and AP&L, LP&L, MP&L, and NOPSI entered into the Reallocation Agreement relating to the sale of capacity and energy from the Grand Gulf Station and the related costs, in which LP&L, MP&L, and NOPSI agreed to assume all of AP&L's responsibilities and obligations with respect to the Grand Gulf Station under the Availability Agreement. FERC's decision allocatmg a portion of Grand Gulf I capacity and energy to AP&L supersedes the Reallocation Agreement as it relates to Grand Gulf 1. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (LP&L 26.23%, MP&L 43.97%, and NOPSI 29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect AP&L's obligation to System Energy's lenders under the assignments referred to in the precedmg paragraph. AP&L would be liable for its share of such amounts if LP&L, MP&L, and NOPSI were unable to meet their contractual obligations. No payments of any amortization amounts will be required as long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future. Reimbursement Arreement In December 1988, System Energy entered into two entirely separate, but identical, arrangements for the sales and leasebacks of an approximate aggregate 11.5% ownership interest in Grand Gulf 1 (see Note 8). In connection with the equity fundmg of the sale and leaseback arrangements, letters of credit are required to be maintained to secure certain amounts payable for the benefit of the equity investors by System Energy under the leases. The current letters of credit are effective until January 15,1997. Under the provisions of the Reimbursement Agreement, as amended, related to the letten of credit, System Energy has agreed to a number of covenants relating to the maintenance of certain capitahntion and fixed charge coverage ratios. System Energy agreed, during the term of the reimbursement agreement, to maintain its equity at not less than 33% of its adjuswd capitalization (as defined in the Reimbursement Agreement to include certain amounts not included in capitalization for financial statement purposes). In addition, System Energy must maintain, with respect to each fiscal quarter during the term of the reimbursement agreement, a ratio of adjusted net income to interest expense (calculated, in each case, as specified in the reimbursement agreement) of at least 1.60. As of December 31,1993, System Energy's equity approximated 34.74% ofits adjasted capitalization, and its fixed charge coverage ratio was 1.88. Failure by System Energy to perform its covenants under the Reimbursement Agreement could give rise to a draw under the letters of credit and/or an early termmation of the letters of credit. If such letters of credit were not replaced in a timely manner, a default under System Energy's related inses could result. Draws under the letters of credit must be repaid by System Energy within 5 days (or in some cases,90 days) following the date of drawing. See Note 2 for infonnation with respect to a FERC order that, if ulumately m"Med and implemented, ceald cause System Energy to fall below the required equity and fixed charge coverage covenant levels.
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SYSTEM ENERGY RESOURCES,INC. NOTES TO FINANCIAL STATEMENTS -(Continued) Nuclear Insurarce ne Price-Anderson Act limits public liability for a single nuclear incident to approximately $9.4 billion, as of December 31,1993. System Energy has protection for this liability through a combination of private insurance (currently $200 million) and an industry assessment program. Under the assessment program, the maxunum amount that would be required for each nuclear incident would be $79.28 million per reactor, payable at a rate of $10 million per licensed reactor per incident per year. As a co-licensee of Grand Gulf I with System Energy, SMEPA would share 10% of this obligation. System Energy has one licensed reactor. In addition, System Energy participates in a private insurance program which provides coverage for worter tort claims filed for bodily injury caused by radiation exposure. System Energy's mammum assessment under the program is an aggregate of approximately $3.1 million in the event losses exceed accumulated reserve funds. System Energy on behalf ofitself and other insured interests (including other co-owners of Grand Gulf 1) is a member of certain insurance programs that provide coverage for property damage, including d-+=mintion and premature decommissioning expense. As of December 31,1993, System Energy was insured agamt such losses up to $2.7 billion with $250 millice of this amount designated to cover any shortfall in the NRC required decommission trust fundmg Under the property damage insurance programs, System Energy could be subject to assessments if losses exceed the accumulated funds available to the insurers. As of December 31,1993, the maximum amount of such possible assessments to System Energy was $21.89 million. Under its agreement with System Energy, SMEPA would share in System Energy's obligation. He amount of property insurance presently carried by System Energy exceeds the NRC muumum requirement for nuclear power plant licensees of $1.06 billion per site. NRC regulations provide that the proceeds of this insurance must be used, first, to place and maintain the reactor in a safe and stable condition and, second, to complete decontammation opvations. Only after proceeds are dedicated for such use and regulatory approval is secured, would any remauung proceeds be made available for the benefit of plant owners or their creditors. Soent Nuclear Fuel and Decommissionine Costs System Energy provides for smatM future disposal costs for spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. System Energy entered into a contract with the DOE, whereby the DOE will fumish disposal service at a cost of one mill per net KWH generated and sold after April 7,1983. The fees payable to the DOE may be adjusted in the future to assure full recovery. System Energy considers all costs incurred or to be incurred for the disposal of spent nuclear fuel to be proper components of nuclear fuel expense and recovers such costs in rates. Due to delays of the DOE's repository program for the acceptance of spent nuclear fuel, it is uncertam when shipments of spent fuel from System Energy will commence. In the meantune, System Energy is responsible for spent fuel storage. Current on-site spent fuel storage capacity at Grand Gulf 1 is estunated to be sufficient until 2004. Hereafter, System Energy will provide additional storage capacity at an estunated initial cost of $5 million to $10 million. In addition, approximately $3 million to $5 million will be required every four to five years subsequent to 2004 until DOE's repository begms acceptmg Grand Gulf I spent fuel. Decommissioning costs were estunated to approximate $248.7 million in 1989 dollars based on a 1989 decommissioning cost study. However, as a result of the FERC Complaint Case sd-t. the amount to be ; col' N in rates for the total cost of decommissioning System Energy's 90% interest in Grand Gulf I was set at appe .ately $198 million (in 1989 dollars). These collections are deposited in external trust funds which have a market value of $26.8 million and $20.1 million at December 31,1993 and 1992, respectively. He accumulated decommissioning liability of $24.8 millioa has been recorded in other deferred credits as of December 31,1993.
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SYSTEM ENERGY RESOURCES,INC. NOTES TO FINANCIAL STATEMENTS -(Continued) Decommissioning expense in the amount of $4.9 million was recorded in 1993. System Energy regularly reviews and updates estunated decommissioning costs (an updated entt study is scheduled to be completed by mid-1994), and applications will be made to the appropriate regulatay authorities to reflect in rates any future change in projected decommissioning costs. .The actual decommissioning costs may vary from the above estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment, and management believes that actual decommissioning costs are likely to be higher than the amounts presented above. The Energy Act has a provision that assesses domestic nuclear utilities with fees for the decontanunation and decommissioning of DOE's past uranium enrichment operations. The decontammation and decommissionirr provisions will be used to set up a fund into which contributions from utilities and the federal government will be placed. System Energy's annual assessment, which will be adjusted annually for mflation, is approxunately $1.3 million (in 1993 dollars) for approximately 15 years. FERC requires that utilities treat these assessments as costs of fuel as they are amortized. The cumulative liability of $16.8 million as of December 31,1993, is recorded in other current liabilities and other non-current liabilities, according to FERC guidelines, and is offset in the fmancial statements by a regulatory asset, recorded as a deferred debit. System Fuels System Fuels entered into a revolving credit agreement with a bank that provides $45 million in borrowings to fmance System Fuels' nuclear materials and services inventory. Should System Fuels default on its obligations under its credit agreement, AP&L, LP&L, and System Energy have agreed to purchase the nuclear materials and services financed under the agreement. NOTE 8. LEASES Nuclear Fuel Lease System Energy has an arrangement to lease nuclear fuel in an aggregate amount up to $105 million. The lessor finances its acquisition of nuclear fuel through a credit agreement and the issuance of notes. The credit agreement which was entered into in 1989 has been evtandad to February 1997 and the notes have varying remammg maturities of up to 4 years. It is expected that the credit arrangements will be evtendad or altemative financing will be secured by the lessor upon the maturity of the current arrangements If the lessor cannot anange for alternative financing upon maturity of its borrowings, System Energy must purchase nuclear fuel in an amoma sufficient to enable the lessor to retire such borrowings. Lease payments are based on nuclear fuel use. Nuclear fuel lease expense of $36.2 million, $48.4 million, and $66.9 million (including interest of $5.1 million,58.5 million, and $11.1 million) was charged to operations in 1993,1992, and 1991, respectively. S.gle and Leaseback Transactions On December 28,1988, System Energy entered into two entirely separate, but identical, arrangements for the sales and leasebacks of an approximate aggregate 11.5% undivided ownership interest in Grand Gulf I for an aggregate cash consideration of $500 million. System Energy is leasing back the undivided interest on a net lease basis over a 261/2 year basic lease term. System Energy has cptions to termmate the leases and to repurchase the undivided interest in Grand Gulf I at certain intervals during the basic lease term. Further, at the end of the basic lease term, System Energy has an cption to renew the leases or to repurchase the undivided interest in Grand Gulf 1. See Note 7 with respect to certain other terms of the transaction.
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SYSTEM ENERGY RESOURCES,INC. NOTES TO FINANCIAL STATEMENTS -(Continued) On January 11,1994, System Energy refmanced the debt portion of the sale and leaseback arrangements of the undivided portions of Grand Gulf 1. The secured lease obligation bonds of $356 million, 7.43% series due 2011 and $79 million, 8.2% series duc 2014 will be indirectly secured by liens on, and a security interest in, certam ownership interests and the respective leases relating to Grand Gulf 1. See Note 7, incorporated herein by reference, for inforrration on letters of credit maintamed by System Energy for the benefit of the equity investors in the transactions. In accordance with SFAS No. 98, " Accounting for Leases," due to " continuing involvement" by System Energy, the sale and leaseback arrangements of the undivided portions of Grand Gulf 1, as described above, are required to be reflected for fmancial reporting purposes as fmancing transactions in System Energy's financial statements. The amounts charged to expense for financial reporting purposes include the interest portion of the lease obligations and depreciation of the plant. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as sales and leasebacks for rate-makmg purposes. The total interest and depreciation expense exceeds the corresponding revenues realized during the early part of the lease term. Consistent with a recommendation contained in a FERC audit report, System Energy recorded as a deferred asset the difference between the recovery of the lease payrnents and the amounts expensed for interest and depreciation and is recording such difference as a dcferred asset on an ongoing basis. The amount of this deferred asset was $71.2 million and $59.1 million as of December 31,1993 and 1992, respectively. See Note I for further information regardmg the accounting for the sale and leaseback transactions. As of December 31,1993, System Energy had future muumum lease payments (reflecting an implicit rate of 7.02% after the above refmancing) as follows (in thousands):
$ 17,423*
1994 42,464 1995 42,753 1996 42,753 1997 42,753 1998 845.573 Years thereafter Total $ 1.033.719
- An additional $24 million payment was made in January 1994 prior to the refmancing of the debt portion of the sale and leaseback arrangements.
NOTE 9. POSTRETIREMENT BENEFITS , Pension Plan System Energy participates in a defmed benefit pension plan sponsored by Entergy. Effective June 1990, all of System Energy's employees became employees of Entergy Operations. However, the employees still remam under System Energy's plan and no transfers of related pension liabilities and assets have been made. The pension plan, which covers substantially all of its employees, is noncontributory and prosides pension benefits based on employees' credited senice and average compensation, generally during the last five years before retirement. System Energy funds pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plan consist pnmarily of common and preferred stocks, fixed income securities, interest in a money market fund, and insurance contracts.
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SYSTEM ENERGY RESOURCES, INC. NOTES TO FINANCIAL STATEMENTS -(Continued) i System Energy's 1993,1992, and 1991 pension cost (credit), including amounts capitahzed, included the following components: jror the Years Ended December 31. 1r91 1992 1991 (In Thousands) Service cost - benefits camed during the period S 2,045 $ 1,737 $ 1,327 Interest cost on projected benefit obligation '.,709 1,439 1,035 Actual return on plan assets (3,828) (2,070) (5,432) Net amortization and deferral 972 (587) 2,991 Other - - 17 Net pension cost (income) $ 898 5 519 $ (62) The funded status of System Energy's pension plan as of December 31,1993 and 1992, was: 1993 1992 (In Thousands) Actuarial present value of accumulated pension plan bene 6ts: Vested 5 16,728 $ 12,400 Non vested 615 428' Accumulated benefit obligation $ 17.343 M , Plan assets at fair value $ 33,914 $ 30,167 Projected benefit obligation 28.931 20.759 Plan assets in excess of projected benefit obligation 4,981 9,408 Unrecognized prior service cost 879 925 Unrecogmzed transition asset (7,080) (7,677) Unrecogmzed net loss (gain) 1.802 (1.176) Accrued pension asset S 582 $ 1.480 The significant actuarial assumptions used in computing the information above for 1993,1992, and 1991 were as follows: weighted average discount rate,7.5% for 1993 and 8.25% for 1992 and 1991; weighted average rate of increase in future compensation levels, 5.6%; and expected long-term rate of return on plan assets, 8.5%. Transition assets are being amortized over the average remaining service period of active participants.
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' SYSTEM ENERGY RESOURCES,INC.
NOTES TO FINANCIAL STATEMENTS - (Concluded) NOTE 10. TRANSACTIONS WITH AFFILIATES s System Energy sells all of the capacity and energy from its share of Grand Gulf I to AP&L, LP&L, MP&L, and NOPSI under rate schedules approved by FERC. Accordingly, all of System Energy's operating , revenues consist of billings to AP&L, LP&L, MP&L, and NOPSI. [ t MP&L provides a nummal amount of technical and advisory services and other miscellaneous services to System Energy. In addition, pursuant to a senice agreement, System Energy receives technical and adsisory senices from Entergy Services, Inc. Charges from MP&L and Entergy Senices, Inc. for technical, adsisory and miscellaneous services amounted to approxunately $12.3 million in 1993, $13.8 million in 1992, and $10.9 million in 1991. System Energy pays directly or reimburses Entergy Operations for the costs associated with operating Grand Gulf 1 (excluding nuclear fuel) which were approximately $151.3 million in 1993, $179 million in 1992, and
$1'6 million in 1991.
In addition, cenain materials and senices required for fabrication of nuclear fuel are acquired and financed i by System Fuels and then sold to System Energy as needed. Charges for these materials and services, which represent additions to nuclear fuel, amounted to approximately $32.8 million in 1993, $13.7 mi!! ion in 1992, and
$28.9 million in 1991.
NOTE 11. QUARTERLY FINANCIAL DATA (UNAUDITED) Operating results for the four quarters of 1993 and 1992 were: Operating Operating Net i Revenue Income - Income , (In Thousands) 1993:
$164,630 $76,331 $31,782 l First Quarter i
$153,527 $65,539 $21,268 Second Quarter
$155,071 $63,992 $23,040 ,
Third Quarter (1) '
$177,540 $66,340 $17,837 l Fourth Quarter 1992:
$177,466 $82,294 $33,198 First Quarter
$194,140 $81,688 $32,321 _
Second Quarter !
$177,464 $80,784 $32,584 Third Quarter
$174,340 $78,410 $32,038 Fourth Quarter ,
l. (1) The third quarter of 1993 reflects a nonrecurring decrease in operating revenues of $14.3 million and a - decrease in operating income and net income of $8.7 million, net of tax, due to the settlement of the FERC Retum on Equity Case (See Note 2). L
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SYSTEM ENERGY RESOURCES, INC. SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON 1993 1992 1991 1990 1989 (Dollars in Thousands) Operating revenues S 650,768 5 723,410 $ 686,664 5 801,618 5 837,307 Net income (loss) S 93,927 5 130,141 5 104,622 5 168,677 5 (655,524) Total assets $3,891,066 $3,672,441 $3,642,203 $3,883,241 $ 3,987,055 Long-term obligations (1) 51,536,593 $1,768,299 51,707,470 $1,849,000 $2,229,022 Electric energy sales (Millions of KWH) 7,113 7,354 8,220 6,666 7,064 (1) Includes long-term debt (excluding current maturities) and noncurrent capitat lease obligations. See Note 2 for information with respect to possible write-offs and refunds which may result from a decision issued by FERC and Note 3 for the effect of the accounting change for income taxes in 1993. i
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- . . =. - . _ Item 9. Chsares In and Disanrwr.:nts With Accountants On Accountine and Financial Disclosure. No event that would be described in response to this item has occurred with respect to Entergy, System l Energy AP&L, GSU, LP&L, MP&L, or NOPSI. PART III Item 10. Directors and Executive Officers Of The Reelstrants. . All officers and directors listed below held the specified pesitions with their respective companies as of the date of filing this report. ENTERGY CORPORATION Directors Information required by this item concerning directors of Entergy Corporation is set forth under the hemdmg
" Election of Directors" contamed in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held May 6,1994, and is incorporated herein by reference.
Eggigd Etag egg Postrios Offkers Chairman of the Board, Chief Executive Officer of Entergy Corporation 1985-Present Edwin Lupberger(s) 57 Chamnan of the Board, Chief Executive Officer of AP&L LP&L, 1993-Present MP&L, and NOPSI Chamnan of the Board, Chief Executive Ofricer of GSU 1994-Piment Chamnan of the Board of System Energy and Entergy Enterprises 1986-Present Chamnan of the Board of Entergy Operations 1990 Present Chamnan of the Board of Entergy Services 1985-Present ' Chief Executive Officer of Entergy Services and Entergy Enterpnses 1991-Present 1984-Prenant Duector of Entergy Enterprises Chief Executive Officer of Entergy Power, Inc., Entergy Power 1993-Present Development Corporation, and Entergy-Ridenand Power Corporation 1985 1991 President of Entergy Corporation C.hamnen of the Board of Entergy Power 1990-1993 President of Entergy Services and Entergy Enterprinos 1990 1991 Chauman of the Board of System Fuels 1986-1990 . 1986-1992 Director of System Fuels
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, , . ._.m ._ _
d'8Mg Agg Position Etd2d Jerry L Maulden 57 President and Chief Operstmg Omcer of Entergy Corporataan 1993-Present Vice Chairman and Chief Operstmg Omccr of AP&L, OSU, LPAL, MP&L, and NOPSI 1993-Present Dtrector of AP&L 1979-Present Dxector of GSU 1993-Present Directs ofLPAL and NOPSI ~ 1991-Present Director of MP&L 1988-Present Director ofEntergy Operations 1990-Present Director of System Energy 1987-Present Vice Chairman of Entergy Services 1992 Present Chatrman of the Board of AP&L 1989-1993 ChiefExecutive Omccr of AP&L 1979-1993 Chairman of the Board and Chief Executive Omcer of LPAL and NOPSI 1991 1993 Chasrman of the Board and Chief Executive Oscar of MP&L 1989-1993 Group Presidect, System Executive - Tran=nimaion, Distribution, and Customer Semce of Entergy Corpwatum 1991 1993 Senior Vice President, System Executive - Arkansaa/ Mississippi / Missouri Division of Entergy Corporation 1988-1991 Director of System Fuels 1979-1992 Oroup President, System Executive Tran=niasion, Distribution, and Customer Semce of Entergy Services 1991 1992 Director of Entergy Enterprises 1984-1991 Jeny D. Jackson 49 Executive Vice President - Finance and External Affairs of Entergy Corporation 1990-Present Executive Vice President - Finance and External Affairs, Secretary and Directs of AP&L, LPAL, MP&L and NOPSI 1992-Present ' Executive Vice President Finance and External Affaars of GSU 1993-Present President and Chief Admmistrative Omcer of Entergy Services 1992-Present Secretary ofEntergy Corporation 1991-Present Director of System Entergy 1993-Present Director ofEntergy Services 1990-Present Executive Vice President - Finance and External Affairs of Entergy Services 1990 1992 Directs of Entergy Power 1990-1992 President ofEntergy Enterprises 1991-1992 Director of Entergy Enterprises ' 19 @ 1992 Senior Vice President, System Executive Legal and External Affairs of Entergy Corporation and Entergy Semces 1987-1990 Donald C. Hintz 51 Senior Vice President and Chief Nuclear Omccr of Entergy Corporation 1993-Present Senior Vice President Nuclear of AP&L 19%Present Senim Vice President-Nuclear of GSU 1993-Present Senior Vice President - Nuclear of LPAL 1992-Present Director of AP&L, LPAL, NOPSI, System Energy, Syntan Fuels, and Entergy Semces 1992-Present Di:Sctor of GSU and MP&L 1993-Present Chief Executive Omcer and President of System Energy and Entergy Operations 1992-Present Directs of Entergy Operations 1990-Present Chief Operating Omcer and Executive Vice President of Entergy Operations 19 % 1992 Oroup Vice Presient -Nuclear ofLP&L 1990 1992 Chief Operating Omcer and Executive Vice President of System Energy 1989-1990 Senior Vice President - Power Production of Wisconsin Public Semce 1988-1989 Donald flunter 60 Senior Vice President of Entergy Corporation 1992-Present 1 Senior Vice President and Director of Entergy Services 1992-Present Senior Vice President - Fossil Operations of AP&I., LPAL, MP&L, NOPSI, and Entergy Services 1990-1992 , President and Chief Operating Omcer of LPAL 1989-1990 l Chief Operating Officer ofNOPS! 1989-1990 Executive Vice President of LP&L and NOPSI 1987-1990 President, Chief Executive Officer, ud Director of System Fuels 1990-1992 Director ofEntergy Enterprises 1991-1992
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i l 1 1 Position EgIlod h Aag Senior Vice President of Entergy Corporation 1987 Present Jack L. King (b) 54 Chief Operating Omcer, President, and Director of Entergy Enterprises 1992-Present Chairman of the Burd of Entergy Systems and Service,Inc., Entergy 1992-Present Argentma SA, and Entergy S A Chief Executive Omcer and President of Entergy Power Development 1992-1993 Corporation Director of AP&L, LP&L MP&L, NOPSI, Entergy Power, and Entergy 1990-1992 Services Chairman of the Board of Entergy Power 1993-1993 ; Chief Executive Omcer of Entergy Power 1990-1993 Chamnan of the Board, Chief Executive Omcer, and President of 1992-1993 Entergy-Richmond Power Corporation President of Entergy Power 1990-1993 Executive Vice President - Operations of Entergy Services 1990-1992 Chamnan of the Board of System Fuels 1990-1992 Senior Vice President, System Executive - Operations of Entergy 1987-1990 Services Chief Executive Omcer and President of Entergy Systems and Service, Inc., Entergy Argentina S.A., and Entergy SA 1992 1993 50 Senior Vice President and Chief Financial Omccr of Entergy Gerald D. McInvale Corporation AP&L, LP&L, MP&L, NOPSI, System Energy, Entergy 1991-Present Operations, Entergy Services, and Entergy Enterprises 1993-Present Senior Vice President and Chief Financial Omccr of GSU Senior Vice President, Chief Financial Omccr, Director, and Treasurer of 1993-Present Entergy Power Director ofSystem Fuels 1992-Present Treasurer of Entergy Enterprises 1992-Present Director of Entergy Systems and Service,Inc. 1993-Present . Vice President, Director, and Treasurer of Entergy Power Development 1993-Present i Corporation and Entergy-Richmond Power Corporation President Executive Information Strategies (consulting firm), Dallas, l
)
1990-1991 Texas I Senior Vice President and Chief Financial Omcer of Frito-Lay,Inc. 1987-1990 (Subsidiary of PepsiCo, Inc.) Dallas, Texas Michael O. Thompson 53 Senior Vice President and Chief Legal Omcer of Entergy Corporation 1992-Present and Entergy Services Senior Vice President, Chief Legal Omcer, Director, and Secretary of , 1993-Present l Entergy Pour Senior Vice President, Chieflegal Omcer, and Secretary of Entergy l l 1992-Present Enterprises l Via President, Director, and Secretary of Entergy Power Development Corporation and Entergy-Richmond Power Corporation 1992-Present Director of Entergy Systems and Service,Inc. 1992-Present 1993-Present Secretary of Entergy Systems and Service,Inc. Assistant Secretary of Entergy Corporation 1993-Present l
- Senior Partner of Friday, Eldredge & Clark (law firm) 1987-1992 4 Vice PresMent - Federal GovernmerAal Affairs of Entergy Corporation l S. M Henry Brown, Jr. 55 '
1989-Present and Entergy Ser ices Director -Public Affairs Carolina Power & Light Company 1988-1989 Charles L. Kelly 57 Vice President - Corporate Communications and Public Relations of 1992-Present Entergy Corporation Vice President - Corporate Communications and Public Relations of 1991-Present Entergy Services Vice President Corporate Communications of AP&L 1981 1991
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UJat Agg Position fH12A Lee W. Randall 44 Vice President and Chief Accounting Officer of Entergy Corporation, AP&L, LP&L, MP&L, NOPSI, System Energy, Entergy Operations, and Entergy Services 1991-Present Vice President, Chief Accounting Officer, and Assistant Secretary of OSU 1993-Present Assistant Secretary of AP&L, LPAL, MP&L, NOPSI, Entergy Operations, and Entergy Services 1991-Present Senior Vice President Finance and Admmistration and ChiefFinancial Officer of AP&L 1988-1991 Secretary of AP&L 1989-1991 Assistant Treasurer ofAP&L 1988-1991 i Olenn E. Harder 43 Treasurer of Entergy Corporation and Entergy Services 1993-Present Vice President - Financial Strategies and Treasurer of AP&L, LPAL, MP&L, NOPSL System Energy, and Entergy Operations 1993-Present Vice PreAdent - Financial Strategies and Treasurer of GSU 1993-Present Vice President - Financial Strategies of Entergy Services 1991-Present Treasurer and Assistant Secretary of System Fuels 1993-Present Vice Paesident Admmistrative Services and Regulatory Affairs of System Energy 1991-1993 Vice President Accounting and Treasurer of System Energy 1986-1991 Vice President - Accountmg and Treasurer of Entergy Operations 1990-1991 Vice President - Administrative Services and Regulatory Affairs of Entergy Operations 1991 1991 ARKANSAS POWER & LIGHT COMPANY Dimtors Michael B. Bemis(c) 46 Executive Vice President - Customer Service and Director of AP&L, LPAL, MP&L, and NOPSI 1992-Present Executive Vice President - Customer Serme of OSU 1993-Present Executive Vice President - Customer Service of Entergy Senices 1992-Present Director of System fuels 1992-Present President and Chief Operating Officer of LPAL and NOPSI 1992-1992 President and Chief Operstmg Officer of MP&L 1989-1991 Secretary of MP&L 1991-1991 John A. Cooper, Jr.(d) 55 Director of Entergy Corporation 1985-Present Director of AP&L 1992-Present Chairman of the Board of Cooper Communities,Inc., Bella Vista, AR 1900-Present Chairman of the Board of COFAM,Inc. 1991-Present Cathy Cunningham(e) 48 Director of AP&L 1983-Fresent Self employed in real estate development and contractmg, Heber Springs, West Helena and Helena, AR 1982-Present Richard P. Herget, Jr.(f) 54 Director of AP&L 1981-Present Vice Chairman of Rebsamen Insurance, Little Rock, AR 1992-Present Managmg Director of Marsh & McLennan, Inc. (Insurance) 1987-1992 , Tommy H. Hillmarig) 57 Director of AP&L 1985-Present 1 J President of Winrock Farms, Inc. (Agriculture), Carlisle, AR 1980-Present Cha2rman of Riceland Foods,Inc. 1985-1993 Donald C. Hintz 51 See the information under the Entergy Corporation Officers Sect 2on ! above, mcorporated herem by reference. 1 Kancaster flodges, Jr.(h) 55 Director of Entergy Corporation 1984-Present Director of AP&L 1981-Present Attorney-at-law. Sole Practitioner, Newport, AR 1981-Present Jerry D. Jackson 49 See the informataan under the Entergy Corporation Officers Section above, mcorporated herein by reference. R. Drake Keith 58 Presidst and Director of AP&L 1989-Present Chief Operating Officer of AP&L 1989-1992 Secretary ofAP&L 1991-1992 l Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section I above, incorporated herein by reference.
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Position Egdg.d ZiAEtt Att 57 See the information under the Entergy Corporation Omcers Section JerryL Maulden above, mcorporated herein by reference. 1982-Present Dr. Raymond P. Miller, Sr.(i) 57 Director of AP&L 1970-Present Physician, Little Rock, AR 1977-Present Roy L. Murphy (j) 66 Director of AP&L Chairman of the Board of Mid South Engmeermg Co. (consulting 1969-Present engineers), Hot Sprmgs, AR 1 % 9-1991 President of %d-South Enginecrmg Co. 1971-Present William C. Nolan, Jr.(k) 54 Director of AP&L Attorney-at-Law,Nolan & Alderson, Attorneys,El Dorado, AR 1%9-Present Directs of Entergy Corporation 1977-Present Robert D. Pugh(1) 65 1971-Present Directcr of AP&L Director of Entergy Operations 1990-Present Chairman of the Board of Portland Bank and Portland Bankshares,Inc. 1991-Present Chairman of the Board of Portland Gin Company (Agricultural and Agri-1981-Present Busmess) Portland, AR 1985-Present Woodson D. Walker (m) 43 Director of AP&L Attorney-st-Law, Walker, Roaf, Campbell, Ivory & Dunkim, P.A., Little 1977-Present Rock, AR 1981-Present Gus B. Walton, Jr. 52 Director of AP&L Vice President, Secretary, and part owner of Frederick Poe Travel Service,Inc. (Travel Service), Little Rock, AR 1983-Present 1980-Present Michael E. Wilson (n) 51 Director of AP&L Chairman of the Board and Chief Executive Omcer ofIm Wilson & Company (Agricultural and Agri-Business), Wilson, AR 1987-Present President and Director of Delta Valley & Southern Railway Company 1979-Present Offirm
$7 See the information under the Entergy Corporation Omcers Section Edwin Lupberger above, incorporated herein by reference.
57 See the information under the Entergy Corporation Omccrs Section Jerry L Maulden above, mcorporated herein by reference. 58 See the information under the AP&L Dtrectors Section above, R. Drake Keith mcorporated herein by reference. 46 See the information under the AP&L Directors Section above, Michael B. Bemis tocorporated herein by reference. 49 See the information under the Entergy Corpcration Omccrs Section Jerry D. Jav m above, mcorporated herein by reference. 48 Executive Vice President Fossil Operations of AP&L, LP&L, MP&L, Frank F. Gallaher 1993-Present NOPSI, and Entergy Services 1994-Present President ofGSU 1993-Present Director of GSU Chairman of the Board of System Fuels 1992-Present 1992-Present Director of Entergy Services Senior Vice President - Fossil Operations of AP&L, LP&L, MP&L, NOPSI, and Entergy Services 1992 1993 Vice President and Chief Engineer of MP&L 1985-1990 Vice President System Plannmg of Entergy Services 1990 1992 51 See the information under the Entergy Corporation Omccrs Section Dor.ald C. Hintz above, incorporated herein by reference. 50 See the information under the Entergy Corporation Omccrs Section Gerald D. McInvale above, tacorporated herein by reference. Michael R. Niggli 44 Senior Vice President - Marketing of AP&L, GSU, LP&L, MP&L, 1993-Present NOPSI, and Entergy Services Vice President - Customer Service of LP&L,NOPSI, and Entergy 1993-1993 Services Vice President Strategic Planning of Entergy Services 1990-199'l Vice President - Fuels Management of Entergy Services 1988-1990 Vice President and Directer of Entergy Enterprises 1991 1992
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fi,s.ms Agg Posttion Eilied Cecil L. Alexander (o) 58 Vice President - Governmental AfTairs of AP&L 1991-Present Vice President - Public Affairs of AP&L 1989-1991 Vice President - Governmental Relations of AP&L 1985-1989 Glenn E. Harder 43 See the information under the Entergy Corporation Officers Section above, incorporated herein by reference. Richard J. Landy 48 Vice President Human Resources and Administration of AP&L, LPAL, MP&L, NOPSI, Entergy Services, and EOI 1991-Present Vice President - Human Resources and Admmistration of GSU ' 1993-Present Vice President - Human Resources and Administration of System Energy 1986-1990 Vice President Human Resources and Admmistration of Entergy Operations 1990-1991 James S. Pilgnm 58 Vice President Customer Service of AP&L 1994-Present Vice President - Northern Region, Operations Customer Service of Entergy Services 1993-Present Director, Cethus Region TDCS Customer Service 1993-1994 Central Dithi9 Panager ofMP&L 1991-1993 Northern Divuius Manager of MP&L 1988-1991 Lee W. Randall 44 See the information under the Entergy Corporation Officers Section above, mcorporated herein by reference. C. Hiram Walters 57 Vice President Customer Service of AP&L 1993-Present Vice President - Customu Service of LP&L 1994-Present Vice President - Central Region of Entergy Services 1993-Present Vice President - Customer Service of MP&L 1984-1991 Senior Vice President - Customer Service of Entergy Services 1991-1992 CULF STATES UTILITIES COMPANY Dirntort Robert H. Barrow (p) 72 Director of GSU 1984-Present General of United States Manne Corps. 1%9-Present Frank F. Gallaher 48 See the information under the AP&L Officers Section above, mcorporated herein by reference. Frank W. Harrison Jr.(q) 65 Director of GSU 1990-Present Independent Geologist,IAfayette,IA 1959-Present Donald C. Hintz 51 See the information under the Entergy Corporation Officers Section above, mcorporated herein by reference. William F. Klausing 65 Director of GSU 1991-Present Senior Vice President and Manager ofIrving Trust Company's Public Utilities Division, New York, NY 1985-1989 Edwin Lupberger 57 See the information under the Entergy Corporation Officers Section above, mcorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corpontion Officers Section above, mcorporated herein by reference. Paul W. Murnil(r) 59 Director of Entergy Corporation 1993-Present Director of GSU 1978-Present Director of Entergy Operations 1994-Present Eugene IL Owen(s) 64 Director of Entergy Corporation 1993-Present Director of GSU 1989-Present Chamnan of the Board and Chief Executive Officer of Owen and % tite, Inc. (engineenng consulting firm) 1956-Present Churman of the Board and President of Utility Holdings,Inc.,(holding company for Baton Rouge Water Company, Parish Water Company ; and leuisiana Water Company) Baton Rouge, IA 1986 Present President of Parish Water Company, Inc., Baton Rouge, LA 1987-Present j President of Baton Rouge Water Company, Baton F.ouge, IA 1987-Present President of Louisiana Water Company, Baton Rouac, LA 1982-Present ; I
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1 i Agt Position Eid2A UElf 1990-Present M. Bookman Peters 60 Director ofGSU 1961-Present Certified Public Accountant 1990-Present Financial Consultant Chauman of the Board and Chief Executive Ofncer of First City Texas-Bryan, N.A., Bryan, TX 1 % 2-1990 Regional Director of First City Bancorpcration of Texas, Inc. 1981 1990 Ducctor of GSU 197Mresent Monroe J. Rathbone, Jr.(t) 68 General Surgeon 19's 8-Present Medical Ducctor of Our Lady of the Lake Regional Medical Center, Baton Rouge, LA 1983-Present 1988-Present Sam F. Segnar(u) 66 Director of GSU Chairman and Chief Executive OfEcer of Sam F. Segnar (Interests which include construction, development, heavy equipment, aviation, and insurance),' Die Woodlands,TX 1989-Present Charman of the Board of Collecting Bank, N.A., Houston, TX 1989-1992 Director of Entergy Corporation 1993-Present Bismark A. Stemhagen 59 1974-Present Duector of GSU Chairman of the Board of Stemhagen Oil Company,Inc.,(oil and 1984-Present gasoline distributor), Beaumont, TX Chairman of the Board of Starmart Holdings,Inc. 1991-Present 1975-Present James E. Taussig,11 57 Director of GSU Director of Varibus Corporation 1980-Present Director and President of Taussig Corporation (real estate development and investments), lake Charles, LA 1978-Present Director and President of Taussig Properties Corporation,(real estate brokerage), Lake Charles,IA 1968-Present Chairman of the Board and Director of Calcasieu Financial Services Corporation. (consumer finance and awrtgage lender) Lake Charles, 1978-Present LA MSin 57 See the information under the Entergy Corporation Officers Section Edwin Lupberger above, mcorporated herem by reference. 57 See the information under the Entergy Corporation OfLcers Section Jerry L. Maulden above, tacorporated herein by reference. 48 See the information under the AP&L OfHcers Section above, F ank F. Gallaher mcorporated herein by reference. 46 See the information under the AP&L Directors Section above, Michac!B Bemis mcc,rporated herein by reference. 49 See the information under the Entergy Corporation Officers Section Jerry D. Jackson above, mcorporated herein by reference. 51 See the information under the Entergy Ccrporation Officers Section Donald C. Ihntz above, mcorporated herein by reference. 50 See the information under the Entergy Corporation Officers Section Gerald D. McInvale above, tncorporated herein by reference. Michael R. Niggli 44 See the information under the AP&L Officers Section above, mcorporated herein by reference. Vice President and Secretary of GSU 1989-Present leslie D. Cobb 59 l Director of GSG&T,Inc. 1990-Present 1988-Present l Director of Prudential Oil and Gas, Inc. Secretary of GSGAT,Inc. 1987-Present Secretary of Prudential Oil and Gas, Inc. 1988-Present Secretary-Treasurer of Southern Gulf Railway Co. 1993-Present 1979-1989 Corporate Secretary of GSU i 43 See the information under the Entergy Corporation Officers Section Glenn E. liarder above, mcorporated herein by reference. ' Richard J. Landy 48 See the information under the AP&L OfHeers Section above, mcorporated herein by reference. 44 See the information under the Entergy Corporation Of11cers Section l Lee W. Randall above, mcorporated herein by reference. l 4
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l
l Ennis Att Position Etlied Calvin J. IIebert 59 Vice President - Customer Semce of GSU 1993-Present Senior Vice President - Division Operations of GSU 1992-1993 Senior Vice President External Affairs of GSU 1986-1992 Bobby J. Willis 57 Vice President and Controller of GSU 1985-Present President and Tressurer of Prudential Oil & Gas, Inc. 1987-Present President and Controller of Varibus Corporation 1986-Present Director of GSG&T,Inc. 1992-Present Director of Prudential Oil & Gas, Inc. 1987-Present Director of Varibus Corporation 1986 Present LOUISIANA POWER & LIGIIT COMPANY Dfrettors Michael B. Bemis 46 See the infonnation under the AP&L Directors Section above, mcorporated herein by reference. John J. Cordaro 60 President and Director of LP&L and NOPSI 1992-Present Group Vice President - External Affairs of LP&L and NOPSI 1989-1992 Donald C. Itintz 51 See the infonration under the Entergy Corporation Omcers Section above, incorporated herein by teference. William K. Ilood(v) 43 Director ofLPAL 1989-Present Manages the daily operations of four automobile dealerships and various related companies 1972-Present Jeny D. Jackson 49 See the information under the Entergy Corporation Omcers Section above, mcorporated herein by reference. Tex R. Kilpatrick 60 Director ofITAL 1972-Present Chainnan and Chief Executive OfHeer of Central American and Ashley Life Insurance Company 1993-Present President of Central American Life Insurance Company, West Maroe, IA 1957-Present Joseph J. Krebs, Jr. 63 Director of LPAL 1983-Present Chairman and Chief Executive Omcer of J. J. Krebs & Sons, Inc. (Engineering, Planning and Surveymg) 1977-Present Director ofNOPSI 1983-1992 Edwin Lupberger 57 See the information under the Entergy Corporation Of5cers Section above, mcorporated herein by reference. Jerry 1. Maulden 57 See the information under the Entergy Corporation OfHeers Section ' above, incorporated herein by reference. Il Duke Shackelford(w) 67 Director of Entergy Corporation 1981-Present Director ofLPAL 1972-Present Planter 1950-Present President of Shackelford Company,Inc. 1973-Present President of Bonita Gin,Inc. 1991-Present President of Louisiana Cotton Warehouse Co., Inc. (Agricultural and Agri-Business) 1978-Present President of Shackelford Gin,Inc. 1976-1991 Chauman, Union Oil Mill, Inc. (Agricultural and Agri-Business), Bonita, LA 1981 1989 Wm. Chiford Smith (x) 58 Director ofEntergy Corporation 1983-Present Director ofLP&L 1981-Present Director ofEntergy Operations 1990-Present President of T. Baker Smith & Son, Inc. (Consultants Civil Engineer and land Survey) 1%2-Present Omcers , Edwin Lupberger 57 See the information under the Entergy Corporation OfIlcers Section above, mcorporated herem by reference. Jeny L. Maulden 57 See the information under the Entergy Corporation Officers Section above, mcorporated herein by reference. John J. Cordaro 60 See the information under the LP&L Directors Section above, incorporated herem by reference.
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1 Ef.,ghs Agg Position Esms 46 See the information under the AP&L Directors Section above, Michael B. Bemis mcorporated herein by reference. 49 See the information under the Entergy Corporation Omcers Section Jerry D. Jackson above, mcorporated herein by reference. 48 See the information under the AP&L Omccra Section above, Frank F. Gallaher mcorporated herem by reference. 51 See the information under the Entagy Corporation Officers Section Donald C. Ilintz above, mcorporated herein by reference. 50 See the information under the Entergy Corporation Omccrs Section Gerald D. McInvale above, mcorporated herein by reference. 44 See the information under the AP&L Omcers Section above, Mchael R. Niggli mcorporated herein by reference. 1991-Present 53 Vice President - Rates and Regulatory Affairs of LP&L and NOPSI Shelton G. Cunnin@m, Jr. Vice President - Entergy Corporation /GSU Transition Regulatory Affairs 1993-Present of Entergy Services 1992-1993 Vice President - Regulatory Affairs of Entergy Services Senior Vice President - Rates and Regulatory Affairs of LP&L and 1989-1991 NOPSI 1992-Present Richard C. Guthrie 51 Vice President Governmental Affairs of LP&L and NOPSI 1986-1992 Vice President - Public Affairs of LPAL and NOPSI 43 See the information under the Entergy Corporation Omcers Section Glenn E. liarder above, mcorporated herein by reference. 48 See the information under the AP&L Omccrs Section above, Richard J. Landy mcorporated bercin by reference. 1994-Present James D. Bruno 54 Vice President Customer Service of LP&L and NOPSI 1993-Present Vice President - Metro Region of Entergy Services 1991-1993 Region Director - Metro Region 1988-1991 Vice President - Division Manager - Orleans Division 1993-Present William E. Colston 58 Vice President - Customer Service of LP&L 1993-Present Vice President - Southern Region of Entergy Services 1988-1991 Vice President Division Manager of LP&L 1991 1992 Regional Director of LP&L 44 See the information under the Entergy Corporation Omcers Section Ixe W. Randall above, mcorporated herein by reference. 57 See the information under the AP&L Omccrs Section above, C. Ihram Walters mcorporated herein by reference. MISSISSIPPI POWER & LIGHT COMPANY Dirntort 46 See the information under the AP&L Dtrectors Section above, Mchael B. Bemis mcorporated herein by reference. 1981-Present Frank R. Day (y) 62 Director of MP&L Chairman of the Board and Cnief Executive Omccr of Trustmark 1981-Present National Bank, Jackson, MS Chairman of the Board and Chief Executive Omcer ofTrustmark 1981-Present Corporation (Bank Holdmg Company) 1972-Present Chauman of the Board of Smith County Bank, Taylorsville, MS 1985-1992 Chairman of the Board of the Bank of Edwards, Edwards, MS 1972 1993 President of Snuth County Bank,Taylorsville, hG 1989-Present John O. Enmench, Jr. 64 Director of MP&L 1973-Present Editor & Publisher of Greenwood Commonwealth, Greenwood, MS 1966-Presc st Norman B. Gillis, Jr.(r) 66 Director of MP&L 1950-Present Attorney-at-Law, Gillis & Gillis, Attorneys, McComb, MS 51 See the information under the Entergy Corporation Omccrs Section Donald C. Ilintz above, mcorporated herets by reference. 49 See the information under the Entergy Corporation Omcers Section Jerry D. Jackson above, mcorporated herem by reference.
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r F.Aas Ast E211 tina P.tried Robert E. Kenmngton,II 61 Director of MP&L 1974-Present Chamnan of the Board of Grenada Sunburst System Corporation (Bank ibiding Company) and of Sunburst Bank, Grenada, MS 1975-Present Chief Executive Omcer of'Nnaut Sunburst Systen Corporut on (Bank Holding Company) and oiSun urst Bank, Grenada, MS 1975-1992 Edwin Lupberge- 57 See the information under the Entergy Corporation Omcers Section above, incorporated herein by reference. Jerry L. Maulden 57 See the information under the Entergy Corporation Omcas Section , above,inW.e4 herein by referenu. ' Donald E. Memers(aa) 58 President and Director ofMPAL 1992-Present Senior Vice President, System Executive Servica Division of Entergv , Corporatior 1938-1990 President and Chief Operating Omcer of LPAL and NOPSI 1990-1991 Chief Operating Omcer and Secretary of MP&L 1992-1992 President and Chief Executive Omccr of Entergy Services, System Fuela, and Entergy Enterprises 1987-1990 John N. Paltner, Sr.(bb) 59 Director of Entergy Corporation 1992-Pmsent Director ofMP&L 1987-Present Chamnan of the Board and Chief Executive Omcar of Vdile Telecommunication Technologies Corporation 1989-Present Dr. Clyda S. Rent 52 Director of MP&L 1991-Present President of Mississippi University for Women, Columbus, MS 1989-Present Vice President of Queens College, Charlotte, NC 1984-1989 E. B. Robinson, Jr.(cc) 52 Directo ofMP&L 1984-Present Chairman of the Board and Ch'ef Executive Officer ofDeposit Guaranty Corporation and Depe .h Guaranty N:,cional Bank, Jackson, MS 1984-Trement Dr. Walter Washington 70 Director of Entergy Corporation and MPAL 1977-Preamt , President ofAlcorn State University,Imman, MS 1969 Preemt Robert M. Wilhems, Jr. 58 Director of MP&L 1976-Present Partner . Reeves-Williams (Building and Development) Southhaven, MS 1969-Presamt N FAinIMpberger 57 See the information under the Entern Corporation Oscars Section ! above, mcorporated herein by referenu. Jerry L. Maulden 57 See the information under the Entergy Corporation Omcers Section above, scorporated herein by reference.
' Donald E. Memers 58 See the information under the MP&L Directors Section above, mcorporated herein by reference.
Michael B. Bemis 46 See the information under the AP&L Directors Section above, mcorporated herein by reference. JerryD Jackson - 49 See the information under the Entergy Corporation Omcers Section above, mcorporated herein by reference. Frank F. Gallaher 48 S2e the information under the AP&L Oscars Section above, mcorporated herein by reference. Gerald D. McInvale 50 See the information under the Entergy Corporation Omcers Sectaan above, mcorporated herein by reference. Michael R.Nigsli 44 See the informatica under the AP&L Omccre Section above, incorporated herein by reference. Bill F. Cossar 55 Vice President . Governmental Affairs of MP&L 1987-Present lohnny D. Ervin 44 Vice President . Customer Service of MP&L 1991-Present Vice President Eastem Region of Entergy Services 1991-Present i Director of Ent:rgy Enterprises 1991-1992 Vice President . Marketing of LPAL and NOPSI 1990-1991 Vice President . Division Manager of LP&L 1988-1990 Glenn E. Harder 43 See the information under the Entergy Corporation Omcers Section above, mcorporated herein by reference. Richard J. Landy 48 See the information under the AP&L Omcers Section above, ir+.ad herein by reference. Lee W. Randall 44 See the information under the Entergy Corporation Omcers Section above, mcorporated herein by reference. 319-
l 1 Agg Pedt!on EsIi9.1 E. gag NEW ORLEANS PUBLIC SERVICT . . l Directors i 46 See the information under the AP&L Directors Section above, Michael B. Bemis mcorporated herein by reference. 1978-Precent ; James M. Cair(dd) 60 Director ofNOPSI 1 Vice Chairman of Entergy Corporation and Entergy Services 1991-1993 1978-1993 Director of LP&L Director of System Energy 1978-1993 Director of Entergy Operations 1990-1993 Director of Systems Fuels 1978-1993 Senior Vice President, System Executive, Louisiana Division of Entergy 1988-1991 Corporation ) 1989-1991 Chairman of the Board of LP&L 1983-1991 ChiefExecutive OfEccr ofLP&L 1990-1991 l Chairman of the Board ofNOPSI 1989-1990 Chief Executive Omcer ofNOPSI 1978-1990 President ofNOPSI Chief Administrative OfHeer of Entergy Services !991 1992 Director of Entergy Services 1975-1993 Director ofEntergy Entaprises 1984 1991 60 See the information under the LP&L Directors Section above, John J. Cordaro j mcorporated herein by reference. Director of Entergy Corporation 1983-Present Brooke H. Duncan(ee) 70 1967-Present Director ofNOPSI I Director of Entergy Operations 1992 Present President and Chief Executive OfEcer of Jno. Warner Hardware,Inc. 1980-Present President of The Montegut Corporation (formerly The Foster Company 1966-Present Inc., a canvas fabricator) 1992-Present , Di.NormanC Francis (f!) 62 Director ofNOPSI ' President of Xavier University oflouisiana 1968-Present 51 See the information under the Entergy Corporation OfEcers Section Donald C. Hintz above, mcorporated herein by reference. 49 See the information under the Entergy Corporation Omccrs Section Jerry D. Jackson , above, mcorporated herein by reference. 57 See the information under the Entergy Corporation 05cers Section Edwin Lupberger above, mcorporated herein by reference. 57 See the information under the Entergy Corporation Omcers Section Jeny L. Maulden above, incorporated herein by reference. 1991-Present Anne M. Milling 53 Director ofNOPSI 1969-Present l John B. Smallpage 68 Director of NOPSI Chairman of the Board and Secretary ofIkmovan Marme,Inc., New 1970-Present Orleans, LA 1978-Present l Charles C. Teamer, Sr.(gg) 60 Director ofNOPSI Vice President for Fiscal Affairs of Dillard University, New Orleans, LA 1965 Dresent l l des.tn Edwin Lupberger 57 See the information under the Entergy Corporation Omcers Section above, incorporated herein by reference. 57 See the information under the Entergy Corporation Omccrs Section Jerry L. Maulden above, mcorporated herein by reference. 60 See the information under the LP&L Directors Section above, John J. Cordaro incorporated herein by reference. 46 See the information under the AP&L Directors Section above, Michael B. Bemis mcorporated herein by reference. 49 See the information under the Entergy Corporation Omcers Section Jerry D. Jackson above, mcorporated haem by reference. j 48 See the information under the AP&L OfEccrs Section above, Frcnk F. Gallaher incorporated herein by reference.
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?!.s.ms Agg Poiltion Period Gerald D. McInvale 50 See the information under the Entergy Corporation Omcers Section above, mcorporated herein by reference. I Michael R. Niggli 44 See the informabon under the AP&L Omcers Section above, mcorporated herein by reference.
James D. Bruno 54 See the information under the LP&L Omccrs Section above, mcorporated herein by reference. Shelton G. Cunningham, Jr. 53 See the information under the LP&L Omccrs Section above, tacorporated herein by reference. ) Richard C. Guthrie 51 See the information under the LPAL Omcers Section above, incorporated l herein by reference. Glenn E. Harder 43 See the information under the Entergy Corporation Omcen Section above, mcorporated herein by reference. Richard L Landy 48 See the information under the AP&L Omcers Section above, mcorporated herein by referet.ce. Lee W. Randall 44 See the information under the Entergy Corporation Omcers Section above, mcorporated herein by reference. SYSTEM ENERGY RESOURCES, INC. Dirteten Donald C. Hmtz 51 See the information under the Entergy Corporation Officers Section above, mcorporated herein by reference. Jerry D. Jackson 49 See the information under the Entergy Corporation Omcers Section above, mcorporated herein by reference. Edwin Lupberger 57 See the information under the Entergy Corporation Omcers Section above, incorporated herein by reference. Jeny L Maulden 57 See the information under the Entergy Corporation Omcers Section above, mcorporated herein by reference. Offkers Edwin Lupberger 57 See the information under the Entergy Corporation Omccrs Section above, mcorporated herein by reference. Donald C. Hintz 51 See the information under the Entergy Corporation 05cers Section above, mcorporated herein by reference. Gerald D. McInvale 50 See the information under the Entergy Corporation Omcers Section above, mcorporated herein by reference. Glenn E. Harder 43 See the mformation under the Entergy Corporation Omcers Section above, incorporated herein by reference lee W. Randall 44 See the information under the Entergy Corporation Omccrs Section above, incorporated herein by reference. Joseph L. Blount 47 Secretary of System Energy and Entergy Operations 1991-Present Vice President Legal and External Affairs of Entergy Operations 1990-1993 Vice President Legal and External Afrairs of System Energy 1989-1990 Assistant Secretary for System Energy 1987-1991 General Counsel and Assistant to President of System Energy 1986 1989 Assistant Secretary for Entergy Operations 1990-1991 (a) Mr. Lupberger is a director of First Commerce Corporation, New Orleans, LA, International Shipholding Corporation, New Orleans, LA, and First National Bank of Commerce, New Orleans, LA. (b) Mr. King is a director of First Pacific Networks, Inc. ("FPN") and Systems and Service International, Inc. ("SASI"). Entergy Enterprises owns 9.95% of the common stock of FPN, and a subsidiary of Entergy Enterprises, Entergy Systems and Service, Inc., owns 9.95% of the common stock of SASI. (c) Mr. Bemis is a director of Deposit Guaranty National Bank, Jackson, MS and Deposit Guaranty Corporation, Jackson, MS.
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I (d) Mr. Cooper is a & rector of Wal Mart Stores, Inc., Bentonville, AR and J. B. Hunt Transport Services, ! Inc.,lowell, AR. l (c) Ms. Cunningham is a & rector of First National Bank of Phillips County, Helena, AR. i (f) Mr. Herget is a & rector of Union National Bank and Union Modern Mortgage Cc.rporation, Little Roc AR. (g) Mr. Hillman is a director of Riceland Foods, Inc., Hazen, AR, Hazen First State Bank, Harmt, AR, Bank of North Arkansas, Melbourne, AR, First National Bank of Stuttgart, Stuttgart, AR, Investark Bankshares, Inc., Stuttgart, AR, and Carlisle Bankshares,Inc., Carlisle, AR. (h) Mr. Hodges is a director of Worthen Bankmg Corporation, Little Rock, AR and Newport Federal Savin > and Loan Association, Newport, AR. Dr. Miller is a director of Worthen Banking Corporation, Little Rock, AR. . (i) (j) Mr. Murphy is a & rector of Arkansas Bank & Trust Company, Hot Springs, AR. Mr.Nolan is a director of First Financial Bank of El Dorado, El Dorado, AR, First Cu,m,wcial (k) Corporation, Little Rock, AR, and Murphy Oil Corporation, El Dorado, AR. i (1) Mr.Pugh is a director of Portland Bank and Portland Bankshares, Inc., Portland, AR and Wotthen National Bank of Pine Bluff, Pine Bluff, AR. r Mr. Walker is a director of Worthen Bank and Trust Company, Little Rock, AR. (m) Mr. Wilson is a director of American State Bank, Osceola, AR. (n) Mr. Alexander is a director of First National Bank of Cleburne County, Heber Springs, AR. (o) t (p) General Barrow is a director of United Companies Financial Corporation, Baton Rouge, LA. (q) Mr. Harrison is a director of Premier Bancorp, Inc., Baton Rouge, LA, Premier Bank, Baton Rouge, LA, and American Liberty Financial Corporation, Baton Rouge, LA. Dr. Murrill is a director of First Mississippi Corporation, Jackson, MS, Tidew3ter, Inc., New Orleans, LA, (r) FirstMiss Gold, Inc., Reno, NV, Piccadilly Cafeterias, Baton Rouge, LA, Howell Corporation, Houston, TX, and Zygo Corporation, Middlefield, CT. Mr. Owen is a director of Premier Bancorp,Inc., Baton Rouge, LA and Premier Bank, Baton Rouge, LA. , (s) Dr. Rathbone, Jr. is a director of American Liberty Financial Corporation and Insurance Company, Baton (t) Rouge, LA. (u) Mr. Segnar is a & rector of Hartmarx Corporation, Chicago, IL, Textron Inc., Providence, RI, Seagull l Energy Corporation, Houston, TX, Mapco, Inc., Tulsa, OK, and Pro-Bank, Woodlands and Conroe, TX Mr. Hood is a director of First Guaranty Bank, Hammond, LA. (v) (w) Mr. Shackelford is a director of Bastrop National Bank, Bastrop, LA. . 6 t
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i
(x) Mr. Smith is a 6 rector of American Bank & Trust Company of Houma, Houma, LA and American Bancshares of Houma, Inc., Houma, LA. (y) Mr. Day is a director of Trustmark National Bank, Jackson, MS, Trusenark Corporation, Jackson, MS, Smith County Bank, Taylorsville, MS, Bank of Edwards, Edwards, MS, Beii South Telecommunications, Atlanta, GA, and South Central Bell Telephone Company, Jackson, MS. , (z) Mr. Gillis is a director of Trustmark National Bank, Jackson, MS and First Capital Corporation, Jackson, MS. (aa) Mr. Meiners is a director of Trustmark National Bank, Jackson, MS, and Trustmark Corporation, Jackson, MS. (bb) Mr. Palmer is a 6rectu of Deposit Guaranty National Bank, Jackson, MS and Mobile Telecommunication Technologies (MTEL}, Jackson, MS. (cc) Mr. Robinson is a director of Deposit Guaranty National Bank, Jackson, MS, and Deposit Guaranty Corporation, Jackson, MS. (dd) Mr. Cain is a director of Whitney National Bank and Whitney Holding Corporation (bank holding company), New Orleans, LA and Delchamps, Inc., Mobile, AL. (ee) Mr. Duncan is a director of Hibernia National Bank, Hibernia Corporation, New Orleans, LA. (ff) Dr. Francis is a 6 rector of He Equitable Life Assurance Society of the United States, New York, NY, Liberty Bank and Trust, New Orleans, LA, and First National Bank of Commerce, New Orleans, LA. (gg) Mr. Teamer is a director of First National Bank of Commerce, New Orleans, LA. Each director and officer of the applicable System company is elected yearly to serve until the first Board Meeting following the Annual Meeting of Stockholders and until a successor is elected and qualified. Annual meetings are currently expected to be held as follows: Entergy Corporation - May 6,1994 j AP&L - May 25,1994 l GSU - May 24,1994 LP&L - May 23,1994 MP&L - May 26,1994 NOPSI- May 23,1994 System Energy - April 29,1994 Directorships shown above are generally limited to entities subject to Section 12 or 15(d) of the Securities and Exchange Act of 1934 or to the Investment Company Act of 1940. Section 16(a) of the Securities Exchange Act of 1934 and Section 17(a) of the Public Utility Holding Company Act of 1935 require each registrant's officers, directors and persons who own more than 10% of a registered class of such registrant's equity securities to file reports of ownership and changes in ownership concerning the securities of Entergy Corporation and its subsidiaries with the Secunties and Exclunge Commission and to furnish Entergy Corporation with copies of all Section 16(a) and 17(a) forms they file. Numerous forms relating to Sections 16(a) and 17(a) were required to be filed by officers and directors of Entergy Corporation and of GSU because of the Entergy/GSU merger. However, the following persons who became officers or directors of
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i l l GSU following the Entergy/GSU merger were late in filing their GSU Form 3: Michael B. Bemis, Frank F. Gallaher, Glenn E. Harder, Donald C. Hintz, Jerry D. Jackson, Richard J. Imdy, Edwin Lupberger, Jerry L. I Maulden, Gerald D. McImale, Michael R. Niggli, and Lee W. Randall. None of the above-named persons are the l l beneficial owners of any securities of GSU and, therefore, are sequired to file Form 3 solely by sittue of their I positions as officers or directors of GSU. Rese forms have now been filed with the Securities and Exchange Commission. Additionally, in 1992, the spouse of Duke Shackelford, a director of Entergy Corporation and LP&L, inherited 450 shares of Entergy Corporation common stock. A Form 5 was not timely filed reporting this transaction. His report has now been filed with the Securities and Exchange Commission. On June 26, 1991, the assets of he Foster Company, Inc. were sold to another company, and all undisputed creditors who notified The Foster Company, Inc. of their claims prior to the sale were paid in full. After the sale of the assets, only a shell corporation remamed. Subsequently, several claims and lawsuits were filed against the shell corporation. As a result of these actions, the shell corporation (which was renamed the Montegut Corporation on November 7,1991) Eled a petition for liquidation under the federal bankruptcy laws on November 25,1991. He matter is pending. Mr. Brooke H. Duncan, who will retire in May,1994, as a director of Entergy Corporation and NOPSI, served as President and Director of the Foster Company, Inc. and continues in those capacities with the Montegut Corporation. Item 11. Executive Comnensstion ENTERGY CORPORATION Information called for by this item concerning the directors and officers of Entergy Corporation and the Personnel Committee of Entergy Corporation's Board of Directors is. set forth under the hadmgs " Executive Compensation" and " Personnel Committee Interlocks and Insider Participation" contamed in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held on May 6,1994, which infonnation is incorporated herein by reference. AP&L, GSU, LP&L, MP&L, NOPSI, AND SYSTEM ENERGY Summary Compensation Tables The following tables include the Chief Executive Officers and the four other most highly compensated executive officers in office as of December 31,1993 at AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy. His determination was based on total annual base salary and bonuses (excluding bonuses of an extraordmary and nonrecurring nature) from all System sources earned during the year 1993. See item 10. " Directors and Executive Officers of the Registrants", incorporated herein by reference, for information on the principal positions of cenain of the executive officers named in the table below.
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r .. . AP&L, LP&L, MP&L, NOPSI, and System Entergy As shown in Item 10, most executive o5cers named below are employed by several System companies. Because it would be impracticable to a!!ocate such o5cers' salaries among the various companies, the table below includes aggregate compensation paid by all System companies. However, GSU paid none of the reported compensation for the named omcers. IAnn-Terin Compensation Annual Compensstion Awards Pavouts Other Restricted Securities (d) (e) (f) Annual Stock Underlying LTIP All Other fis,mg Xtig Salary Day,g Compensation Awards Ootions Pavouts Compensation j Michael B. Bemis 1993 $258,538 $ 161,142 5 62,372 (b) 2,500 shares 3 50,125 $ 74,619 1992 258,059 170,186 35,927 (b) 2,500 45,094 71,492 1991 245,383 87,878 (a) (b) (c) 0 (a) Glenn E. Harder 1993 $145,959 $ 59,349 5 4,236 (b) O shares 3 0 $ 17,111 1992 139,000 24,845 3,898 (b) 0 0 17,611 1991 122,321 15,291 (a) (b) (c) 0 (a) Donald C. Ilintz' 1993 $265,386 3166,560 $ 48,548 (b) 5,000 shares S 85,774 3 24,462 1992 228,024 114,822 38,364 (b) 2,500 77,i65 24,205 1991 191,653 80,326 (a) (b) (c) 0 (a) Jerry D. Jackson 1993 $288,559 $217,287 5 36,166 (b) 6,719 sharts 3 100,250 $ 25,961 1992 254,167 152,500 27,008 (b) 5,000 90,188 25,447 1991 225,000 82,575 (a) (b) (c) 31,500 (a) Edwin Lupberger** 1993 $542,077 3437,610 $ 20,327 (b) 13,438 shares $ 248,313 3 32,957 1992 527,499 374,100 39,760 (b) 10,000 180,375 33,671 , 1991 489,9 % 147,626 (a) (b) (c) 65,625 (a) ) Jerry L Maulden 1993 $ 385,000 $ 286,985 5 84,655 (b) 5,000 shares $ 100,250 $ 25,639 1992 392,233 259,316 79,280 (b) 5,000 90,188 24,920 1991 360,069 156,724 (a) (b) (c) 54,900 (a) Gerald D. McInvale 1993 $ 221,696 $ 141,811 5 4B,805 (b) 2,500 shares S 50,125 $ 22,667 1992 209,975 93,686 45,585 (b) 2,500 45,094 43,594 1991 132,356 28,280 (a) (b) (c) 0 (a) I.ee W. Randall 1993 $ 176,321 $ 57,142 3 8,014 (b) Oshares $ 0 $ 17,986 1992 168,859 37,094 6,818 (b) 0 0 19,555 l 1991 167,890 24,929 (a) (b) (c) 0 (a) l Chief Executive 05cer of Systun Energy. Chief Executive Officer of AP&L, LP&L, MP&L, and NOPSI. (a) Disclosure in this category is subject to transition rules, and amounts for 1991 are not required to be included herein. (b) Restricted stock awarded under the Equity Ownership Plan is subject to perfonnance based criteria. Restricted stock awards in 1993 are reported under the "Long-Term Incentive Plan Awards" table, and reference is made to this table for information on the aggregate number of restricted shares awarded during 1993 ard the vesting schedule for such shares. At December 31, 1993, the number and value of the aggregate restricted stock holdings were as fo!!ows: Mr. Bemis: 2,500 shares, $90,000; Mr Hintz: 4,279 l shares, $154,044; Mr. Jackson: 5,000 shares, $180,000; Mr Lupberger: 15,000 shares, $540,000; Mr. l Maulden: 5,000 shares, $180,000; and Mr. McInvale: 2,500 shares, $90,000. Accumulated dividends are a paid on restricted stock when vested. The value of stock for which restrictions were lifted in 1993, and the
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l l I applicable portion of accumulated cash dividends, are reported in the LTIP Payouts column in the above ~ table. The value of restricted stock awards as of December 31,1993 is determined by multip ying the total l number of shares awarded by the closing market price of Entergy Corporation common stock on the New York Stock Exchange Composite Transactions on December 31,1993 (536.00 per share). (c) There were no stock options granted in 1991. (d) 1991 amounts shown above include lag-Term Incentive Plan payouts earned in 1991 that were not calculable in time for inclusion in the Compensation Table in the Form 10-K for 1991. 1993 and 1992 . ' amounts include the value of restricted shares that vested in 1993 and 1992 under Entergy's Equity Ownership Plan. (c) Includes the following: (1) 1993 Executive Medical Plan premiums of $3,019 for each of the above-named executives in 1993. (2) 1993 employer contributions to the Defined Contribution Restoration Plan as follows: Mr. Bemis
$1,800; Mr. Harder $0; Mr.Hintz $886; Mr. Jackson $1,245; Mr. Lupberger $8,564; !
Mr. Maulden $5,519; Mr. Melnvale 50; Mr. Randall 50. (3) 1993 employer contributions to the Employee Stock Ownership Plan as follows: Mr. Bemis 52,682; Mr. Harder $2,682; Mr. Hintz $2,68?: Mr. Jackson $2,682; Mr. Lupberger $2,682; Mr. Maulden $0; Mr. McInvale $2,682; Mr. Randall $2,682. (4) 1993 employer contributions to the System Savings Plan as follows: Mr. Bemis $7,075; Mr. Harder $4,210; Mr. Hintz $7,075; Mr. Jackson $7,075; Mr. Lupberger $7,075; Mr. Maulden
$6,031; Mr. McInvale $6,301; Mr. Randall $5,085.
(5) 1993 reimbursements under the Executive Financial Counseling Program as follows: Mr. Bemis
$0; Mr. Hintz $0; Mr. Jackson $1,140; Mr.Lupberger $4,605; Mr. Maulden $1,350; Mr. McInvale $765.
(6) 1993 payments under the Private Ownership Vehicle Plan as follows: Mr.Bemis $9,900; Mr. Harder $7,200; Mr. Hintz S10,800; Mr. Jackson $10,800; Mr. L,upberger $7,012; . Mr. Maulden $9,720; Mr. McInvale 59,900; Mr. Randall $7,200. (7) 1993 reimbursement for movmg expenses as follows: Mr. Bemis $50,143. (f) Includes bonuses camed pursuant to the Annual Incentive Plan as well as any bonuses of an extraordmary or nonrecurring nature. 1 y
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j
GSU All of the reported compensation for the om:ers named below was paid by GSU. The listed positions were held by these omcers in 1993. See item 10. " Directors and Executive Omcers of the Registrants" for current GSU omcers. Iann-Term Comocesation Annual Comnensation Awsrds Peyouts Other Restricted Securities (c) Annual Stock Undertying LTIP All Other Name(n yeg Sala rv E2DJ.! fompensation Awa rds SARs(d) Pavouts Compensation Donald M. Clements Jr.(e) 1993 $ 130,938 5 74,345 50 (b) 11,250 shares (b) $ 4,614 Scruor Vice President - 1992 109,152 25,000 0 (b) 0 (b) 3,850 External AfTairs 1991 (e) (e) (a) (b) 0 (b) (a) Joseph L. Donnelly* 1993 $ 402,083 5 229,088 30 (b) 38,500 shares (b) 528,271 Chief Executive Officer 1992 358,938 100,000 0 (b) 32,600 (b) 40,777 1991 217,667 0 (a) (b) 9,200 (b) (s) ' Calvm J. Hebert 1993 $ 169,817 $ 44,345 5 0 (b) 5,350 shares (b) $ 61,668 Senior Vice President - 1992 159,917 0 0 (b) 8,050 (b) 32,715 Division Operations 1991 147,167 0 (a) (b) 8,000 (b) (a) Edward M. Loggins 1993 5 233,750 5 57,392 50 (b) 20,400 shares (b) 5 16.385 Senior Executive Vice 1992 218,500 0 0 (b) 9,700 (b) 27,423 President 1991 204,000 0 (a) (b) 9,700 (b) (a) Jack L. Schenck 1993 $ 158,688 5 44,345 5 0 (b) 10,700 shares (b) $ 11,225 Sr. Vice President & 1992 145,329 20,000 0 (b) 4,700 (b) 7,732 Chief Financial Officer 1991 107,550 0 (a) (b) 4,700 (b) (a)
- Chief Executive Officer of GSU as of December 31,1993.
(a) Disclosure in this category is subject to transition rules, and amounts for 1991 are not required to be included herein. (b) GSU does not have a Restricted Stock Awards program or a Long-Term Incentive Plan Awards program. (c) Includes the following: (1) 1993 payments by GSU of excess life insurance cost as follows: Mr. Clements $682; Mr. Donnelly $16,146; Mr. Hebert $240; Mr. Loggins $9,140; Mr. Schenck $3,816. (2) 1993 company contributions to the GSU unft Plan as follows: Mr. Clements $3,932; Mr. Donnelly $7,075; Mr. Hebert $5,095; Mr. Loggins $7,075; Mr. Schenck $4,776. (3) 1993 company contributions to the GSU Non qualified Accrued Contnbutions Plan as follows: Mr. Donnelly $5,050; Mr. Loggms $170. (4) Above market camings on compensation deferred during the period December 1985-December 1986, as follows: Mr. Donnelly 50; Mr. Hebert $56,333; Mr. Loggms $0; Mr. Schenck $2,633. (d) These SARs were attached to shares of GSU common stock. At December 31,1993, the SARs were exercised and cash was received by the named executives. See additional disclosure in the " Aggregated Option /SAR Exercises in 1993 and December 31,1993 Option Values" table. (e) No compensation figures are provided for Mr. Clements for year 1991 because he w2s not an officer of GSU until June,1992. All of his 1992 compensation is shown. (f) Mr. Clements, Mr. Donnelly, Mr. Loggins, and Mr. Schenck have subsequently resigned as officers of GSU. Herefore, they are not listed above as GSU officers in Item 10. " Directors and Executive Officers Of The Registrants"
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Option /SAR Grants in 1993 He following tables summanze option /SAR grants during 1993 to the executive officers named in the Summary Compensation Tables above. He absence, in the table below, of any named officer indicates that no options /SARs were granted to such officer. AP&L, LP&L, MP&L, NOPSI, and System Entergy IndMdusI Grants Potential Realizable Value
% of Total Options at Assumed Annual Number of Granted to Exercise Rstes of Stock Securitles Employees Price Pdce Appreciation Underlying In (per Espiration for Ontion Terin(c)
Options 1993 shareVs) Date 5% 10 % p'E51 Granted (s) 02/01/03 5 54,635 5138,456 2,500 34% $34.75 Michael B. Bemis 02/01/03 109,270 276,913 5,000 6.8% 34.75 Donald C. Hintz 0241/03 109,270 276,913 Jerry D. Jackson 5,000 68% 34.75 09/02/03 42,973 108,901 1,719 (b) 2.3% 39 75 02/01/03 218,541 553,826 10,000 13.6 % 34.75 Edwin Lupberger 85,945 217,802 3,438 (b) 4.7% 39.75 09/02/03 02/01/03 109,270 276,913 5,000 6.8% 34.75 Jerry L. Maulden 02/01/03 54,635 138,456 2,500 34% 34.75 Gerald D. McInvale (a) Options were granted on February 1,1993, pursuant to the Equity Ownership Plan. All options granted February 1,1993 have an exercise price equal to the closing price of Entergy Corporation common stock on the New York Stock Exchange Composite Transactions on January 29,1993. Rese options becanu: exercisable on August 1,1993. (b) Pursuant to the Equity Ownership Plan, if a participr.nt exercises an option during the term of employrnent and pays all or any portion of the price through the surrender of shares of Entergy Corporation common stock, the Personnel Committee may grant to such participant an additional option to purchase the number of shares so surrendered. Any such additional option shall have an exercise price equal to the fair market value of Entergy Corporation common stock as of the date ofits grant. On September 2,1993, Messrs. Jackson and Lupberger exercised stock options and the additional options inAW above were granted pursuant to this reload feature of the Equity Ownership Plan. He reloaded stock options become exercisable six months from the grant date and have an exercise price equal to the closing price of Entergy Corporation common stock on the New York Stock Exchange Composite Transactions on September 1993. Calculation based on the stock option exercise price over a ten-year period assuming annual compounding. (c) The columns present estimates of potential values based on simple mathematical assumptions. He act value, if any, an executive officer may realize is dependent upon the market price on the date of option exercise. l
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l
GSU l IndMduer Crsnts Potential Realizable
% of Total Velue Number of SARs at Assumed Aamuel Securities Greated to Eserdse Rates of Stock Undert%ag Employees Price Pdce Appreciation SARs la (per Espirstlos for SARs Tern If. beg Granted (a) 1993 share) Date(n) 5% (a) 10% (a)
Donald M Clements, Jr. I1,250 5.8% 316.50 . . . Joseph L Donnelly 58,500 19.8 % 16.50 . . . Calvin J. Hebert 5,350 2.7% 16.50 . . . Edward M @ 20,400 10.5 % 16.50 . . . Jack L Schenck 10,700 5.5% 16.50 . . . (a) According to the terms of the Stock Appreciation Plan as nW effective on the merger date of December 31,1993, all SARs issued and granted more than 6 months prior to the merger date were deemed exercised and payment was made to the named executives. Thus, all SARs were exercised and all value reahzed on the SARs as of December 31,1993. 1 1 j l
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Aggregated Option /SAR Exercises in 1993 and December 31,1993 Option Values The following tables summanze the number and value of options exercised during 1993, as well as, the number and value of unexercised options /SARs as of December 31,1993 held by the executive officers named in the Summary Compensation Tables above. The absence, in the tables below, of any named officer indicates that such officer did not exercise any options in 1993 and held no unexercised options /SARs as of December 31,1993. AP&L LP&L, MP&L, NOPSI, and System Entergy Number of Securities Underlying Value of Unexercised Unezercised Options In-the-Money Options Value as of December 31.1993 as of December 31.1993(e) Shares Acquired Eteretsable U Esercisable Unetercisable Enjpg on Eterrise Reellred(b) _ nescrcisable(c) 5,000 0 $19,063 0 Michael B. Bemis 0 0 7,500 0 22,188 0 Donald C. Hintz 0 0 123,369 7,692 1,719 23,412 0 Jerry D. Jackson 2,308 15,386 3,438 46,836 0 Edwin Lupberger 4,614 46,717 10,000 0 38,125 0 Jerry L Maulden 0 0 0 5,000 0 19,063 0 Gerald D. McInvale 0 Based on the difference between the closing price of Entergy Corporation common stock on the New York (a) Stock Exchange Composite Transactions on December 31,1993, and the option exercise price. Based on the difference between the closing price of Entergy Corporation common stock on the New York (b) Stock Exchange Composite Transactions on the exercise date of September 2,1993, and the option exercise price. (c) Stock options granted on September 2,1993 are not exercisable for a period of six months from the date of grant. GSU Number of Securities Underlying Value of Unesercised Unesercised SARs In-the-Money SARs Shares Acquired Value es of December 31.1993 (c) as of Decernber 31.1993 (c) Etercliable Uneterclieble Esercisable Unetercisable Name on Esercise (e) Reallred (b)
$$4,469 0 0 0 0 Donald M. Clements, Jr. 12,750 1,166,625 0 0 0 0 Joseph L Donnelly 165,500 238,925 0 0 0 0 Calvin J. Hebert 41,100 342,900 0 0 0 0 Edward M. loggins 61,100 0 0 0 0 Jack L. Schenck 43,500 255.875 (a) Amount represents the number of SARs exercised during 1993.
(b) Value realized is equal to the difference between the closing price of GSU common stock on the New York Stock Exchange Composite Transactions, on the grant date and such price on the date of exercise. (c) There were no outstanding SARs at December 31, 1993. See additional disclosure regarding SAR exercises in the Option /SAR Grants in 1993 table.
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l
Leng-Term Ine::ntive Plan Awards in 1993 AP&L, LP&L, MP&L, NOPSI, and System Energy He following table summanzes awards of restricted shares of Entergy Corporation common stock under the Equity Ownership Plan in 1993 to the executive officers of these companies named in the Summary Compensation Table above. The absence, in the table below, of any named officer indicates that no restricted shares were awarded to s"ch officer in 1993. Estimated Futurs Payouts Under Perforinance Non-Stock Price-Based Plans (s) Number Period Until of Maturstlos Below h ih!IE1 Or Pavout Th reshold(b) Threshold (c) Terretfd) Martmum(e) Edwin Lupberger 5,000 01/01/93-12/31/03 0 5,000 5,000 5,000 (a) Restricted shares awarded will vest incrementally over a period not to exceed 10 > tars, subject to the attainment of specific stockholder cammgs goals and cost contamment goals for the Star. Restrictions are lifted based upon assigned weighted averages of these performance measures, with the specific relative percentage weight of such measures varying dependmg upon the individual. The value an executive officer may realize is dependent upon both the number of shares that vest and the future market price of Entergy Corporation common stock. (b) If goals are met at less than the 50% level of achievement in a given year, no restrictions will be lifted that year. Hus, if this level of perform .nce is reached in each year, no shares will vest. (c) If goals are met at the 50-99% level of achievement in a given year,20% of the restrictions will be lifted that year. Hus, if this level of performance is reached in each year, all shares will vest within 5 years. (d) If goals are met at the 100-149% level of achievement in a given year,25% of the restrictions will be lifted that year. Hus, if this level of performance is reached in each year, all shares will vest within 4 years. (e) If goals are met at the 150% level of achievement (the maxunum percent achievable) in a given year,33 1/3% of the restrictions will be lifted that year. Hus, if tids level of performance is reached in each year, a!! shares will vest within 3 years.
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l l l Pension Plan Tables ; I AP&L, LP&L, MP&L, NOPSI, and System Energy Retirement Income Plan Table ; Annual Covered Years of Service l 15 20 25 30 35 Compensation 10
$15,000 $ 22,500 $ 30,000 $ 37,500 $ 45,000 $ 52,500
$100,000 45,000 60,000 75,000 90,000 105,000 200,000 30,000 67,500 90,000 112,500 135,000 157,500 300,000 45,000 90,000 120,000 150,000 180,000 210,000 400,000 60,000 112,500 150,000 187,500 225,000 262,500 500,000 75,000 146,250 195,000 243,750 292,500 341,250 650,000 97,500 AP&L, LP&L, MP&L, and System Energy each individually sponsors or participates in a Retirement Income Plan (a denned benefit plan) that provides a benefit for employees at retirement from the System based upon (1) generally all years of senice begmnmg at age 21 through termmation, with a forty-year maximum, times (2) 1.5% for each year of senice, times (3) the fmal average salary. NOPSI is a participating employer in LP&L's Retirement Income Plan. System Energy is a participating employer in the Retirement Income Plan sponsored by Entergy Corporation. Final average salary is based on the highest 60 months of covered compensation in the last 120 months of senice. He normal form of benefit for a single employee is a lifetime annuity and for a married employee is a 50% joint and survivor annuity. Other actuarially equissient options are assilable to each retiree.
Retirement benefits are not subject to any deduction for Social Security or other offset amounts. He amount of the named individuals' annual compensation covered by the plan as of December 31,1993 is represented by the base i salary column in the Summary Compensation Table of AP&L, LP&L, MP&L, NOPSI, and System Energy, ne manmum benefit under each Retirement Income Plan is limited by Sections 401 and 415 of the Internal Revenue Code; however, AP&L, LP&L, MP&L, NOPSI, and System Energy have elected to participate in the Pension Equalization Plan sponsored by Entergy Corporation. Under this plan, certain executives, including the named executive officers, would receive an amount equal to the benefit payable under the Rctimucat Income Plans, without regard to the limitations, less the amount actually paysbh under the Rettrement hwome Plans. Each Retirement Income Plan was amended effective February 1,1991 to provide a nummum accrued benefit as of that date to any employee who was vested as of that date. For purposes of calculating such nummum accrued benefit, each eligible employee was deemed to have had an additional five years of service and age as of that date. He additional years of age did not count toward eligibility for early retirement, but served only to reduce the early retirement discount factor for those employees who were at least age 50 as of that date. De credited years of senice under the Retirement Income Plan (without gising effect to the five additional i years of senice credited pursuant to the February 1, 1991 amendment as discussed above) as of December 31,1993 for the following executive officers named in the Summary Compensation Table of AP&L, LP&L, MP&L, NOPSI, and System Energy were: Mr. Bemis 11; Mr. Harder 15; Mr.Maulden 28; Mr. Randall 14. The credited years of senice under the respective Retirement Income Plant, as amended, as of December 31,1993 for the following executive officers named in the Summary Compensation Table, as a result of l entering into supplemental retirement agreements, were as follows: Mr. Hintz 22; Mr. Jackson 14; I Mr. Lupberger 30; Mr. McInvale 21.
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\_______--_--__-____________-_______________
In addition to the Retirement income Plan discussed above, AP&L, LP&L, MP&L, NOPSI and System Energy participate in the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries (SRP) and the Post-Retirement Plan of Entergy Corporation and Subsidiaries (PRP). Participation is limited to one of these two plans and is at the invitation of AP&L, LP&L, MP&L, NOPSI, and System Energy. The participant may receive from the appropriate System company a monthly benefit payment not in excess of.025 (under the SRP) or .0333 (under the PRP) times the participant's average basic annual salary (as defined in the plans) for a maximum of 120 months. As of January 31,1994, Mr. Hintz has entered into a SRP participation contract, and all of the other executive officers of AP&L, LP&L, MP&L, NOPSI, and System Energy named in the Summary Compensation Table (except for Mr. McInvale) have entered into PRP participation contracts. System Executive Retirement Plan Table (1) Annual Covered Years of Service Comnensation 10 15 20 25 30+
$ 200,000 $ 60,000 $ 90,000 $100,000 $110,000 $120,000 300,000 90,000 135,000 150,000 165,000 180,000 400,000 120,000 180,000 200,000 220,000 240,000 500,000 150,000 225,000 250,000 275,000 300,000 600,000 180,000 270,000 300,000 330,000 360,000 700,000 210,000 315,000 350,000 385,000 420,000 1,000,000 300,000 450,000 500,000 550,000 600,000 (1) Benefits shown are based on a target replacement ratio of 50% based on the years of senice and covered compensation shown. The benefits for 10,15, and 20 or more years of service at the 45% and 55% replacement levels would decrease (in the case of 45%) or increase (in the case of 55%) by the following percentages: 3.0%,
4.5%, and 5.0%, respectively. In 1993, Entergy Corporation adopted the System Executive Rettrement Plan (SERP). AP&L, LP&L, MP&L, NOPSI, and System Energy are participating employers in the SERP. He SERP is an unfunded defined benefit plan offered at retirement to certam senior executives, which would currently include all the executive officers named in the Summary Compensation Table of AP&L, LP&L, MP&L, NOPSI, and System Energy. Participating executives choose, at retirement, between the retirement benefits paid under provisions of the SERP or those payable under the executive retirement benefit plans discussed above. Covered pay under the SERP includes final annual base salary (see the Summary Compensation Table of AP&L, LP&L, MP&L, NOPSI, and System Energy for the base salary covered by the SERP as of December 31,1993) plus the Target Incentive Award (i.e., a percentage of final annual base salary) for the participant in effect at retirement. He Target Incentive Awstd as of December 31,1993, was: 58% for Messrs. Jackson, Lupberger and Maulden; 48% for Messrs. Benus, Hintz and McInvale; and,35% for Messrs. Harder and Randall. Benefits pai.1 under the SEPJ are calculated by multiplying the covered pay times target pay replace.nent ratios (45%, 50%, or 55%, dependent on job rating at retirement) that are attained, accord 5g to plan design, at 20 years of credited service, ne target ratios are increased by 1% for each year of senice over 20 years, up to a maximum of 30 years of senice. In accordance with the SERP formula, the target ratios are reduced for each year of senice below 20 years. He normal form of benefit for a single employee is a lifetime annuity and for a married employee is a 50% joint and sunivor annuity. All SERP payments are guaranteed for ten years. Other actuarially equivalent options are available to each retiree. SERP benefits are offset by any and all defined beneSt plan payments from the company and from prior empicycrs. SERP benefits are not subject to Social Security offsets.
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i Eligibility for and receipt of benefits under any of the executive plans described above are contingent upon several factors. The participant must agree that, without the speciSc consent of the System company for which such participant was last employed, he may take no employment after retirement with any entity that is in competition with or similar in nature to, AP&L, LP&L, MP&L, NOPSI, and System Energy or any af6 hate thereof. Eligibility for benefits is forfeitable for various reasons, including siolation of an agreement with AP&L, LP&L, MP&L, NOPSI, and System Energy, resignation of employment, or term: nation for cause. ) GSU Employees' Trusteed Retirement Plan Table Annual Covered Years of Service 20 25 30 35 Comnensation 10 15
$ 30,335 $ 37,918 $ 45,502 $ 53,086 $100,000 $15,167 $ 22,751 46,335 57,918 69,502 81,086 150,000 23,167 34,751 62,335 77,918 93,502 109,086 200,000 31,167 46,751 73,803 92,254 110,705 129,156 "
235,840
- 36,902 55,353
- Maximum 1993 annual covered compensation imposed by Section 401 of the Internal Revenue Code.
" Maximum 1993 annual beneSt imposed by Section 415 of the Internal Revenue Code is $115,641 payable at age 65.
GSU has an Employees' Trusteed Rettrement Plan that provides a benefit for employees at retirement from GSU based upon generally all years of senice tegmmng at age 21 through termmation, with a thirty-6ve year maxtmum, times (2) 1.2% of that portion of the participant's average final compensation not in excess of his average Social Security wage base, plus 1.6% of the part of such compensation in excess of such aver Smurity wage base. This amount is reduced by the total amounts payable under a cenain group annuity contract Average final compensation is based on the 60 consecutive months during the last ten years of credited se which produce the highest average or during all months of credited senice if such senice is less than 60 mo The normal form of benefit for a single employee is a single life annuity and the actuarial equivalent 50% joint and sunivor annuity of the employee is married. The above table illustrates annual retirement bene 6ts expressed terms of single life annuities based on the base salary and service shown and retirement at age 65. The am the named individuals' annual compensation covered by the plan as of December 31,1993 is represented by the base salary column in the Summary Compensation Table of GSU. The credited years of senice under the Employees' Trusteed Retirement Plan as of December 31,1993 f the following executh officers named in the Summary Compensation Table were: Mr. Clements,14 years; Mr. Donnelly,14 years; Mr. Hebert,29 years; Mr. I.oggins,33 years; Mr. Scherick,12 years. In addition to the Employees' Trusteed Retirement Plan discussed above, GSU prosides, among other benefits to officers, an Executive Income Security Plan for key managerial personnel. The plan prosides participants with certain retirement, disability, termination, and sunivors' bene 6ts. To the extent that su are not funded by the employee benefit plans of GSU or by vested benefits payable by the participants' former employers, GSU is obligated to make supplemental payments to participants or their sunivers. The pla that upon the death or disability of a participant during his employment, he or his designated sunivers w (i) during the first year following his death or disability an amount not to exceed his annual base salary, an thereafter for a number of years until the participant attams or would have attained age 65, but not less than nine years, an amount equal to one-half of the participant's annual base salary. The plan also prosides supple
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i
retirement benefits for hfe for participants retiring after reaching age 65 equal to 1/2 of the panicipant's average fmal compensation rate, with 1/2 of such benefit upon the death of the participant being payable to a suniving spouse for life. GSU nmW and restated the plan effective March 1,1991, to provide such benefits for life upon termmation of employment of a participating officer or key managerial employee without cause (as defmed in the plan) or if the participant separates from employment for good reason (as defmed in the plan), with 1/2 of such benefits to be payable to a suniving spouse for life. Further, the plan was amended to provide medical benefits for a participant and his family when the participant separates from senice. These medical benefits generally continue until the participant is eligib!c to receive medical benefits from a subsequent employer; but in the case of a participant who is over 50 at the time of separation and was participating in the plan on March 1,1991, medical benefits continue for life. By virtue of the 1991 amendment and restatement, benefits for a participant cannot be modified once he becomes eligible to participate in the plan. Compensation of Directors Employees of any Entergy System company who serve on the Board of Directors of any Entergy System company receive no compensation as directors. Directors of AP&L, LP&L, MP&L, and NOPSI who are not employees of a System company are paid an attendance fee of $1,000 for attendance at meetings of their respective Board of Directors, $1,000 (except for the chairman of such committee who is paid $1,500) for attendance at meetings of committees of the Board and $1,000 for participation, on behalf of their respective company, in any inspection trip or conference not held on the same day as a Board or committee meeting. All non-employee directors are also compensated on a quarterly basis in the form of fixed aw2rds of Entergy Corporation common stock pursuant to the Stock Plan for Outside Directors (Directors Plan) and cash based on 1/2 the value of the stock awarded pursuant to the Directors Plan. "Ihis level of directors' compensation is set to enable Entergy Corporation to attract and retain persons of outstandmg competence to serve on the Boards of Directors. Directors are paid a portion of their compensation in the fonn of Entergy Corporation's common stock in order to assure that directors will have a personal interest in the performance of the stock of Entergy Corporation. Non-employee directors are awarded 50 shares of Entergy Corporation common stock quarterly, which may be authorized but unissued shares or shares acquired in the open market System Energy has no non-employee directors. Retired non-employee outside directors of AP&L, LP&L, MP&L, and NOPSI with a muumum of five years of senice on the respective Boards of Directors are paid $200 a month for a term correspondmg to the number of years of senice. Retired directors with over ten years of senice receive a lifetime benefit of $200 a month. Directors of GSU or its subsidiaries, who are not officers of GSU are paid the following fees: $15,000 per year retainer, an additional retamer of $2,400 to the director who serves as Chairman of the Executive Committee, $700 pet day per Board meetmg attended plus out-of-pocket expenses, 5600 per day per committee meeting attended p!us out-of-pocket expenses, and an additional fee of $150 per meeting to each director who sen'es as Chairman of the Executive, Audit, Compensation, Nominating Committees, the Board Committee on Nuclear Safety, the Business Policy Committee, or any other Committee composed of members of the Board. Also, when an outside director attends a specific business activity on behalf of GSU, at the request of the Chairman of the Board of Directors, he receives a fee of $600 per day plus out of-pocket expenses. Outside directors of GSU may elect to defer 25 percent,50 percent or 100 percent of their director's compensation. Under this nonqualiSed plan, a director's deferred compensation will accrue simple interest at the greater of (1) a rate equivalent to that payable by GSU on its average daily short-term debt during a preceding period or (2) a rate equivalent to that received by GSU on its average daily short-term investments during the precedmg year. Directors may select deferred compensation payments to commence after death, upon permanent disability, after a certain age on a specific date, or after cessation of directorship of GSU, and may select payment
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in a lump sum or in annual installments. In 1993, two GSU directors participated in the deferred compensation plan. In 1991, the GSU Compensation Committee of the Board of Directors approved a retirement plan for directors of GSU. Under this plan all directors who serve continuously for a period of years will receive a percentage of their retamer fee in effect at the time of their retirement for life. Le retirement benefit will be 30 percent of the retamer fee for senice of not less than Sve nor more than nine years,40 percent for senice of not less than ten nor more than fourteen years, and 50 percent for fifteen or more years of service. For those d rectors who retire prior to the retirement age as specified in the GSU Bylaws, the benefits will be reduced. He plan also provides disability retuuncnt if the director has served at least five years prior to the disability. He benefits payable under this plan are general unsecured obligations of GSU and no funds or other amendments have been reserved or set aside by GSU to provide a source of payment or fundmg. In 1983, the GSU Board of Directors approved a proposal to have hospital and medical coverage through GSU's insuran:e carrier made available to members of the GSU Board. Under the terms of this proposal, (i) hospital and medical coverage will be secondary to coverage by a director's primary place of employment and/or Medicare, if applicable, (ii) two-thirds of the cost of providing the coverage to the director will be paid by GSU and the remaining one-third by the director, (iii) that portion of the premium paid by GSU will be reported as taxable income to the director as required by the Internal Revenue Service, and (iv) a director may retain his coverage after leaving the Board, if he has served five or more full elected terms on the Board. Under this plan in 1993, insurance premiums were paid to Provident Companies on behalf of the following directors: $1,424 for Gen. Barrow, $119 for Mr. Harrison, 53,944 for Mr. Peters, and $1,424 for Dr. Rathbone, Jr. In 1984, the GSU Board of Directors approved a plan whereby Coopers & Lybrand would make available their senices to provide counseling and tax service individually to all directors for the purpose of assisting them with the establishment of individual Keogh plans and directed that the necessary changes be made in the compensation, benefit plans and other supplemental arrangements of management directors to enable them to participate also in such Keogh plans. In 1993 Coopers & Lybrand provided tax senices to Dr. Murrill in the amount of $9,254. Dr. Murrill received in 1993 and will continue to receive payments from GSU under a retirement agreement and has received papnents for consulting senices, but none of such payments to him is for services as a director. For 1994, GSU adopted the Entergy System's compensation plans for outside directors. Employment Contracts and Termination of Employment and Change-in-Control Arrangements GSU GSU has agreed to employ Mr. Donnelly to serve at the pleasure of the Board at a salary fixed by the Board, and to assure (i) a pension bene 6t equivalent to that which would be provided by GSU's Employees' Trusteed Retirement Plan if he were given credit for prior service of 21.16 years, less credits for accrued benefits under certain GSU plans and social security, and calculated without application for the limit imposed by law on benefits that may be paid under qualified plans, (ii) payment upon temunation of employment in certain events of a severance benefit equivalent to one year's base salary, (iii) payment after retirement of a death benefit equivalent to three times his highest annual base salary during the three years precedmg retirement, (iv) certain financial consulting and other services, and (v) a contingent pension benefit for his spouse equal to fifty percent of his retirement benefit. Except for certain credits described above, these benefits are in addition to those he would be entitled to under GSU plans in which he is a participant. To the extent benefits to which Mr. Donnelly may become entitled are not funded through GSU plans, they will represent general obligations of GSU. In the event of a change of control of GSU and a termmation by Mr. Donnelly of his employment for good reason (as defmed in the
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l l a . _ _ - _ _ _ _ _ _ _ _ _ .
l 1 Executive Continuity Plan), the agreement provides he is not entitled to the severance benefit but is entitled to the pension benefit without regard to his age. Effective as of January 5,1994 Mr. Donnelly resigned from his offices i as Chairman of the Board of Directors, President, Chief Executive Officer, and Director of GSU, and agreed that l he would retire as an employee of GSU as of April 1,1994. On January 22,1994, Mr. Donnelly resigned as Vice i Chairman and Director of Entergy Corporation and entered into a three-year consulting contract providing for an ; annual fee of $200,000. 1 GSU established on January 18,1991, an Executive Continuity Plan for elected and appointed officers providing for severance benefits equal to 2.99 times the officer's annual compensation upon termmation of employment for reasons other than cause or upon a resignation of employrnent for good reason within two years ! after a change in control of GSU. Benefits are prorated if the officer is within three years of normal retuement age ; (65) at termination of employment. He plan further provides for continued participation in medical, dental and life insurance programs for three years following termmation unless such benefits are available from a subsequent employer. 'Ihe plan provides for outplacement assistance to aid a termmated officer in securmg another position. Upon consummation of the Entergy/GSU merger on December 31,1993, GSU made a contribution of $16,330,693 to a trust equivalent to the then present value of the maxunum benefits which might be payable under the plan. If and to the extent the benefits are not thereafter paid to the participants, the balance in the trust will be retumed to GSU. As a result of the Entergy/GSU merger, GSU is obligated to pay benefits under the Executive Income Security Plan to those persons who were participants at the time of the merger and who later termmated their employment under circumstances described in the plan. For additional description of the benefits under the Executive Income Security Plan, see the " Pension Plan Tables - GSU" section noted above. Personnel / Compensation Committee Interlocks and Insider Participation The following persons served as members of the Personnel Committee of AP&L's, LP&L's, MP&L's, NOPSI's and System Energy's Board of Directors and the Compensation Committee of GSU's Board of Directors in 1993: AP&L - John A. Cooper, Jr.*, Edwin Lupberger, Roy L. Murphy, Woodson D. Walker GSU - Monroe J. Rathbone, Jr., M.D., Sam F. Segnar*, Bismark A. Steinhagen LP&L - Tex. R. Kilpatrick*, Edwin Lupberger, Wm. Clifford Smith MP&L - Norman B. Gillis, Robert E. Kenmngton,11*, Edwin Lupberger, Robert M. Wilhams, Jr. NOPSI- Edwin Lupberger, Anne M. Milling, John B. Sma!!page* System Energy - System Energy does not have a Personnel Committee of the Board of Directors. The compensation of System Energy's executive officers (with the exception of one officer) is set by the Personnel Committee of Entergy Corporation's Board of Directon. No officers or employees of System Energy participated in deliberations concerning compensation in 1993.
- Denotes Chairman of the Personnel / Compensation Committec Mr. Lupberger is currently and was during 1993 an officer of AP&L, LP&L, MP&L, and NOPSI and also served as an executive of5cer of their subsidiary, System Fuels, from 1981-1990.
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Mr. Jackson, Executive Vice President - Finance and Extemal Affairs and Secretary of AP&L, served until May 13,1993 on the compensation committee of the Board of Directors of Cooper Communities, Inc., whose chairman is John A. Cooper, Jr., a disector of AP&L. During 1993, T. Baker Smith & Son, Inc. performed land surveying services for, and received payments of approximately $153,000 from, LP&L. Mr. Wm. Clifford Smith, a director of LP&L and a member of LP&L's Personnel Committee, is President of T. Baker Smith & Son, Inc. Mr. Smith's children own 100% of the voting l stock of T. Baker Smith & Son,Inc. Item 12. Security Ownershio of Certain Beneficial Owners and Manseement Entergy Corporation owns 100% of the oum= ding common stock of registrants AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy. The infonnation with respect to persons known by Entergy Corporation to be bene 6cial owners of more than 5% of Entergy Corporation's common stock is included under the heading " Voting Securities Outstandmg" in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held May 6,1994, which information is incorporated herein by reference. The registrants know of no contractual arrangements which may, at a subsequent date, result in a change in control of any of the registrants. The directors, the executive officers named in the Summary Compensation Tables, and the directors and officers as a group for Entergy Corporation, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy, , respectively, beneficially owned directly or indirectly the following cumulative preferred stock of a System l company and common stock of Entergy Corporation
)
l l l I i
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l As of December 31.1993 Entergy Corporation Common Stock Preferred Stock (s) Amount and Nature Amount and Nature of of Beneficial Beneficial Ownershio(b) Ownershio(b) Sole Voting Sole Voting Other and Other and Beneficial i Investment Beneficial Investment Ownership l h Power (c) Ownershio Power (c) (d)(e)(n(e)(1)(m) Entergy Corporation i W. Frank Blount* - - 2,134 - 1 John A. Cooper, Jr.' 6,000 (a) - 5,484 - Joseph L. Donnelly"* - - 126 1,477 i Brooke H. Duncan* - - 2,100 - Lucie J. Fjeldstad* - - 1,284 - Dr. Norman C. Francis * - - 100 - . Donald C. Hintz" - - 1,519 13,462 Kaneaster Hodges, Jr.* - - 2,000 . Donald Himter" - - 1,917 10,499 , Jerry D. Jackson" - - 5,220 16,888 Robert v.d. Luft* - - 1,384 - Edwin Lupberger" - - 7,867 40,147 Jerry L Maulden" - - 21,998 25,190 , Adm. Kmnaird R. McKee* - - 2,500 - Paul W. Murrill* - - 1,300 . . James R. Nichols' - - 2,423 - Eugene H. Owen* - 3,500(a) 558 - John N. Palmer, Sr.* - - 11,907 - Robert D. Pugh* - - 4,500 6,000 (b) H. Duke Shackelford* - - 6,200 3,950 (h) Wm. Clifford Smith * - - 2,905 - l Bismark A. Steinh gen * - - 5,803 - Dr. Walter Washington * - - 442 4,017 All directors and executive officers 6,000 3,578 109,931 185,511 AP&L 3 Michael B. Bemis" - - 5,999 12,297 i John A. Cooper, Jr.* 6,000 (a) - 5,484 - Cathy Cunningham* - - 1,200 1,000 (i) ;
~
Richard P. Herget, Jr.' - - 725 - . Tommy H. Hillman* - - - 200 (j) Donald C. Hintz" - - 1,519 13,462 Kaneaster Hodges, Jr.* - - 2,000 - Jerry D. Jackson" - - 5,220 16,888 R. Drake Keith*" - - 2,048 11,306 Edwin Lupberger" - - 7,867 40,147 Jerry L. Maulden" - - 21,998 25,190 l Raymond P. Miller, Sr.* ;
- - 500 -
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b
~
As of D=-":- 31.1993 Entergy Corporation C: -- Stock P.la-d Stock (a) Amount and Nature ; l Amount and Nature of ofBeneficial
": :5d=! Owneraktatb) Ownershin(b)
Sole Voting Sole Voting Other
- i and Other 'and Beneficial -
Investment Beneficial Investmes* Ownership , N!amg Power (c) Ownershin Power (c) (dMcMfMEMIMm) AP&L (cont'd) Roy L. Murphy * - - 400 - l William C. Nolan, Jr.* - - 476 - Robert D. Pugh* - - 4,500 6,000 (h) Gus B. Walton, Jr.* - - 20,127 - l
~
Michael E. Wilson * - - 255 - 6,000 - 90,107 173,388 i All directors and executive officers GSU - Robert H. Barrow * - - 61 - Joseph L. Donnelly" - - 126 1,477 Frank F. Gallaher* - - 1,913 7,691 3 Frank W. Hamson, Jr.' - - 769 - Calvin J. Hebert" - - 1,016 - - Donald C. Hintz'" - - 1,519 '13,462 l William F. Klausing* - - 334 - Edward M. Loggms" - - 125 2,120 Jerry L. Maulden*" - - 21,998 . 25,190 Paul W. Murrill* - - 1,300 - l I Eugene H. Owen* - 3,500(a) 558 - M. Bookman Peters * - - 558 - Monroe J. Rathbone, Jr.* - - 278 -
- - 641 Jack L. Schenck" -
l Sam F. Segnar* - - 279 - Bismark A. Stemhagen* - - 5,803 - l
-- 906 -
James E. Taussig,11* - l All directors and executive officers - 3,500 67,210 165,108 LP&L
- 5,999 12,297 Michael B. Benus" -
- 1,131 7,831 John J. Cordaro"* -
Donald C. Hintz" - - 1,519 13,462 William K. Hood' 800 (a) - 1,750 -
- 5,220 16,888 Jerry D. Jackson" -
' Tex R. Kilpatrick* - - 1,478 . 993 (k)
Jossph J. Krebs, Jr.* - - 453 -
- 7,867 40,147 Edwin Lupberger** -
21,998 25,190 Jerry L. Maulden" - -
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As of December 31.1993 Entergy Corporation i Common Stock Preferred Stock (a) Amount and Nature ! Amount and Nature of of Beneficial Beneficial Ownershio(b) Ownershio(b) Sole Voting Sole Voting Other and Other and Beneficial ' Investment Beneficial Investment Ownership Hg!mg Power (c) Ownership Power (c) (d)(e)(f)(r)(1)(m) LP&L (cont'd) H. Duke Shackelford* - - 6,200 3,950 (h) i Wm. Clifford Smith' - - 2,905 - All directors and executive officers 800 - 65,553 170,286 MP&L Michael B. Bemis" - - 5,999 12,297 Frank R. Day * - - 2,050 - John O. Emmerich, Jr.* - - 500 - Norman B. Gillis, Jr.* - - 100 - Donald C. Hintz* - - 1,519 13,462 Jerry D. Jackson" - - 5,220 16,888 Edwin Lupberger" - - 7,867 40,147 Jerry L. Maulden" - - 21,998 25,190 Gerald D. McInvale" - - 1,152 7,949 Donald E. Meiners*" - - 830 11,962 John N. Palmer, Sr.* - - 11,907 - Dr. Clyda S. Rent * - - 450 - E. B. Robinson, Jr.* - - 300 - Dr.WalterWa Wgena* - - 442 4,017 Robert M. Williams, Jr.' - - 500 1,200 All directors and executive officers - - 64,928 169,626 > NOPSI Michael B. Bemis" - - 5,999 12,297 James M. Cain' - - 1,215 8,421 ' John J. Cordaro"* - - 1,131 7,831 Brooke H. Duncan* - - 2,100 - Nonnan C. Francis * - - 100 - Donald C. Hintz* - - 1,519 13,462 t Jerry D. Jackson" - - 5,220 16,888 Edwin Lupberger" - - 7,867 40,147 Jerry L. Maulden" - - 21,998 25,190 Gerald D. McInvale" - - 1,152 7,949 John B. Smallpage' - - 500 - -
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As of December 31.1993 Entergy Corporation j Common Stock Preferred Stockfa) Amount and Nature Amount and Nature of ofBeneficial Beneficial C..w-Ais(b) Ownershin(b) Sole Voting Sole Voting Other and Other and Beneficial Investment Beneficial Investment Ownership b'g!!g Power (c) Ownershio Power (c) (d)(e)(f)(e)0)(m) , NOPSI(cont'd) Charles C. Teamer, Sr.* - - 324 - All directors and executive officers - - 53,022 170,390 System Energy ' Glenn E. Harder" - - 58 3,568 Donald C. Hintz" - - 1,519 13,462 Jerry D. Jackson * - - 5,220 16,888 Edwin Lupberger" - - 7,867 40,147 Jerry L. Maulden* - - 21,998 25,190 Gerald D. McInvale' ' - - 1,152 7,949 Lee W. Randall" - - - 4,094 All directors and executive officers - - 38,348 113,313 j
- Director of the respective Company
" Named Executive Officer of the respective Company
"* Officer and Director of the respective Company I (a) Stock ownership amounts refer to Preferred Stock, $100 Par Value, (except for the 6,000 shares of ; AP&L's $0.01 Par Value ($25 liquidation value), Preferred Stock held by John A. Cooper Trust; 3,500 l shares of AP&L's 50.01 Par Value ($25 liquidation value), Preferred Stock held by Eugene H. Owen; and , 800 Shares of LP&L's $25 Par Value Preferred Stock held by William K. Hood). Mr. Cooper disclaims 1 any personal interest in these shares (b) Based on information furnished by the respective individuals. The ownership amounts shown for each individual and for all directors and executive officers as a group do not exceed one percent of the outstanding securities of any class of security so owned. (c) Includes all shares which the individual has the sole power to vote and dispose of, or to direct the voting j and disposition of. j (d) Includes, for the named persons, shares of Entergy Corporation common stock held in the Employee Stock Ownership Plan of the registrants as follows: Michael B. Bemis,666 shares; James M. Cain, 802 shares; John J. Cordaro, 940 shares; Glenn E. Harder, 686 shares; Donald C. Hintz, 703 shares; Donald Hunter, 703 shares; Jerry D. Jackson, 703 shares; R. Drake Keith, 703 shares; Edwin Lupberger, 770 shares; I
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i l l l Jerry L. Mau'. den,743 shares; Gerald D. McInvale,103 shares; Donald E. Meiners, 516 shares; and Lee l W. Randall, 739 shares. l (e) Includes, for the named persons, shares of Entergy Corporation common Stock held in the System Savings Plan as follows: Michael B. Bemis, 4,131 shares; James M. Cain 7,619 shares; John J. Cordaro,1,391 shares; Glenn E. Harder,2,882 shares; Donald C. Hintz, 980 shares; Donald Hunter 2,296 shares; Jerry D. Jackson,1,774 shares; R. Drake Keith, 3,429 shares; Edwin Lupberger, 5,553 shares; Jerry L. Maulden, 9,447 shares; Gerald D. McInvale, 346 shares; Donald E. Meiners, 3,946 shares; and Lee W. Randall, 3,355 shares. (f) Includes, for the named persons, unvested restricted shares of Entergy Corporation common stock held in the Equity Ownership Plan as follows: Michael B. Bemis, 2,500 shares; John J. Cordaro, 3,000 shares; Donald C Hintz, 4,279 shares; Donald Hunter, 2,500 shares; Jerry D. Jackson, 5,000 shares; R. Drake Keith, 2,500 shares; Edwin Lupberger,15,000 shares; Jerry L. Maulden, 5,000 shares; Gerald D. McInvale,2,500 shares; and Donald E. Meiners,2,500 shares. (g) Includes, for the named persons, shares of Entergy Corporation common stock in the form of unexercised stock options awarded pursuant to the Equity Ownership Plan as follows: Michael B. Bemis, 5,000 shares; John J. Cordaro 2,500 shares; Donald C. Hintz, 7,500 shares; Donald Hunter, 5,000 shares; Jerry D. Jackson, 9,411 shares; R. Drake Keith,4,674 shares; Edwin Lupberger,18,824 shares; Jerry L. Maulden, 10,000 shares; Gerald D. McInvale, 5,000 shares; and Donald E. Meiners, 5,000 shares. (h) Includes, for the named persons, shares of Entergy Corporation common stock held by their spouses. 'Ibe named persons disclaim any personalintere:rt in these shares as follows: Robert D. Pugh 6,000 shares; and H. Duke Shackleford,3,950 shares. (i) Reflects 500 shares of Entergy common stock owned by a Profit Sharing Plan at Cunningham Butane Gas Company and 500 shares of Entergy common stock not owned solely by Cathy Cunningham of which she has shared voting and investment power. (j) Reflects 200 shares owned by Tommy Hillman Farms, Inc. (k) Tex R. Kilpatrick is President of Central American Life Insurance Company which owns 993 shares of Entergy common stock. (1) Includes, for the named person, shares of Entergy Corporation comrron stock held in the GSU 'Ihrift Plan as follows: Jack L. Schenck,302 shares. (m) Includes, for the named persons, shares of Entergy Corporation common stock held in the GSU Employee Stock Ownership Plan as follows: Joseph L. Donnelly,1,477 shares, Edw3rd M. Loggms, 2.120 shares; and Jack L. Schenck,339 shares. Item 13. Certain Relationships and Related Transactions. Information called for by this item concerning the directors and officers of Entergy Corporation is set forth under the headmg "Certain Transactions" in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held on May 6,1994, which information is incorporated herein by ' reference. See Item 11. " Executive Compensation - Personnel / Compensation Committec Interlocks and Insider 1 Participation" for information on certain transactions required to be reported under this item. ,
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ne System companies do not have policies whereby transactions involving executive ofEcers and directors of the System are approved by a majority of disinterested directors Hawever, pursuant to the Entergy Corporation Code of Conduct, transactions involving a System company and its executive ofEcers must have prior approval by .; the next higher repvrting level of that individual, and transactions involving a System company and its directors must be reported to the secretary of the appropriate Sym company. b i V i
.I s
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3 l PART IV Item 14. Exhibits. Financial Statement Schedules, and Reports on Form 8-K. (a)l. Financial Statements and Independent Auditors' Reports, incorporated herein by reference, for Entergy, AP&L, GSU, LP&L, MP&L, NOPSI, and System Energy are listed in the Index to Financial Statements (see pages 57 and 58) (a)2. Financial Statement Schedules Independent Auditors' Reports on Financial Statement Schedules, incorporated herein by reference (see pages 349 and 350. Financial Statement Schedules are listed in the Index to Financial Statement Schedules, incorporated herein by reference (see page S-1) (a)3. Exhibits Exhibits for Entergy, AP&L, GSU, LP&L, MP&L, NOPSI, and Symrn Energy are listed in the Exhibit Index, incorporated herein by reference (see page E-1), Each management contract or compensatory plan or arrangement required to be filed as an exhibit hereto is identified as such by footnote in the Exhibit Index. (b) Reports on Form 8-K QSU A current report on Form 8-K, dated November 30,1993, was filed with the SEC on December 1,1993, reporting information under Item 7 " Financial Statements and Exhibits". A current report on Form 8-K, dated January 18,1994, was filed with the SEC on January 18, 1994, reporting information under item 5 "Other Materially Important Events". A current report on Form 8-K, dated February 1,1994, was filed with the SEC on February 8,1994, reporting information under Items 2 and 7. Entern Comoration. AP&L. GSU. LP&L. MP&L and NOPSI Current Reports on Form 8-K, dated December 31,1993, were filed by these companies on January 3, 1994 reporting the consummation of the Entergy Corporation - GSU merger under item 5 (in the case of AP&L, LP&L, MP&L and NOPSI), Items 2 and 7 (in the case of Entergy Corporation and GSU).
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EXPERTS All statements in Part I of this Annual Report on Form 10-K as to matters oflaw and legal conclusions, based on the belief or opinion of System Energy or any System operatir4 company or otherwise, pertauung to the titles to properties, franchises and other operating rights of certain of the registrants filing this Annual Report on Form 10-K, and their subsidiaries, the regulations to which they are subject and any legal pruiny to which they are parties are made on the authority of Friday, Eldredge & Clark,2000 First Commercial Building,400 West Capitol, Little Rock, Arkansas, as to AP&L and as to Entergy Services in regards to flood litigation; Monroc & Lemann (A Professional Corporation),201 St. Charles Avenue, Suite 3300, New Orleans, Louisiana, as to LP&L and NOPSI; and Wise Caner Child & Caraway, Professional Association, Heritage Building, Jackson, Mississippi, as to MP&L and System Energy. The statements attributed to Clark, Thomas & Winters, a professional corporation, as to legal conclusions with respect to GSU's rate regulation in Texas under Item 1. " Rate Matters and Regulation - Rate Matters - Retad Rate Matter:: - GSU" and in Note 2 to Entergy Corporation and Subsidiaries Consolidated Financial Statements and GSt/s Financial Statements, " Rate and Regulatory Matters," have been reviewed by such firm and are included herein upon the authority of such firm as expens. The statements attributed to Sandlin Associates regarding the analysis of River Bend Construction costs of GSU under Item 1. " Rate Matters and Regulation - Rate Matters - Retail Rate Matters - GSU" and in Note 2 to Entergy Corporation and Subsidiaries Consolidated Financial Statements and GSU's Financial Statements, " Rate and Regulatory Matters", have been reviewed by such firm and are included herein upon the authority of such firm as experts.
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g ENTERGY CORPORATION ,
. SIGNATURES i
i, Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of tiu undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. ENTERGY CORPORATION j By LEE W. RANDALL Lee W. Randall, Vice President ; and Chief Accounting Officer Date: March 14,1994 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by , the following persons on behalf of the registrant and in the capacities and on the dates iade='d "Ihe signature of . each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. Sirnature Iills 'D.ats l i f LEE W. RANDALL Vice President a:ad March 14,1994 12e W. Randall Chief Accounting Officer (Principal Accounting Officer) Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director, Principal , Executive Officer); Gerald D. McInvale (Senior Vice President and Chief Financial Officer, 3 Principal Finucial Odicer); W. Frank Blount, John A. Cooper, Jr., Brooke H. Duncan, Lucie J. Fjeldstad, F===*~ Hodges, Jr., Robert v.d. Luft, Kmn=rd R. McKee, Paul W. Murrill, '
- James R. Nichels, Eugene H. Owen, John N. Palmer, Robert D. Pugh, H. Duke Shackelford, Wm. Clifford Smith, Bismark A. Steinhagen, and Walter Wasidngton (Directors).
By: thE W. RANDALL March 14,1994 (Ime W. Randall, Attorney-in-fact)
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i ARKANSAS POWER & LIGHT COMPANY SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant I has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. ARKANSAS POWER & LIGHT COMPANY l By LEE W. RANDALL Lee W. Randall, Vice President and Chief Accounting Officer Date: March 14,1994 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. Siensture _ Tit!s Rais LEE W. RANDALL Lee W. Randall Vice President and Chief March 14,1994 Accounting Officer (Principal Accounting Officer) Edwin Lupberger (Cluirman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Otrald D. McInvale (Senior Vice President and Chief Financial Officer; Principal Financial Oflicer); Michael B. Bemis, John A. Cooper, Jr., Cathy Cunningham, Richard P. Herget, Jr., Tommy H. Hillman, Donald C. Hintz, Kaneaster Hodges, Jr., Jeny D. Jackson, R. Drake Keith, Jerry L. Maulden, Rapnond P. Miller, Sr., Roy L. Murphy, William C. Nolan, Jr., Robert D. Pugh, Woodson D. Walker, Gus B. Walton, Jr., Michael E. Wilson > (Directors). By: LEE W. RANDALL March 14,1994 (lee W. Randall, Attorney-in-fact)
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i
l 1 l GULF STATES UTILITIES COMPANY l SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters hasing reference to such company and any subsidiaries thereof. GULF STATES UTILITIES COMPANY By LEE W. RANDALL Lee W. Randall, Vice President and Chief Accounting Officer Date: March 14,1994 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. Sirnature Ij.t.11 .4 8.11 LEE W. RANDALL Vice President a xi March 14,1994 Ixe W. Randall Chief Accounting Officer (Principal Accounting Officer) Edwin Lupberger (Chairman of the Board, Chief Executive Officer and Director; Principal , Executive Officer); Gerald D. McInvale (Senior Vice Presider:t and Chief Financial Officer; Principal Financial Officer); Robert H. Barrow, Frank F. Gallaher, Frank W. Harnson, Jr., ; Donald C. Hintz, Jerry L. Maulden, Paul W. Murrill, Eugene H. Owen, M. Bookman Peters, 1 Monroe J. Rathbone, Jr., Sam F. Segnar, Bismark A. Steinhagen, James E. Taussig, II. l (Directors). j i By: LEE W. RANDALL March 14,1994 (Lee W. Randall, Attorney-in-fact)
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i i
LOUISIANA POWER & LIGHT COMPANY f SIGNATURES Pursuant to the requinments of Secten 13 or 15(d) of the Securities Exchange Act of 1934, the registrant ;
~
has duly caused this report tc *;c signed on its behalf by the undersigned, thereunto duly authorized. De signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. LOUISIANA POWER & LIGHT COMPANY By i FF W. RANDALL Iee W. Randall, Vice President , and Chief Ace =*ia: Officer l Date: March 14,1994 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. He signature of each of the undersigned shall be deemed to relate only to matters having .4.m.c4 to the above-named company and any subsidsanes thereof. Sinnature lillt D.Ali 1 LEE W. RANDALI,,_ ; I4e W. Randall Vice President and Chief March 14,1994 l Accounting Officer l (Principal Accounting Officer) l, Edwin Lupberger (Chauman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Senior Vice President and Chief Financial Officer; Principal Financial Officer); Michael B. Bemis, John J. Cordarc, Donald C. Hmtz, William K. Hood, Jerry D. Jackson, Tex R. Kilpatrick, Joseph J. Krebs, Jr., Jerry L. Maulden, H. Duke ShekNord, Wm. Clifford Smith (Directors). By: LEE W. RANDALL March 14,1994 (i.ee W. Randall, Attorney-in-fact)
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1 l MISSISSIPPI POWER & LIGHT COMPANY SIGNATURES t Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the urdersigned, thereunto duly authorized. He signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. MISSISSIPPI POWER & LIGHT COMPANY By LEE W. RANDALL Lee W. Randall, Vice President and Chief Accounting Officer Date: March 14,1994 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. Sienature Iitig p_ gig LEE W. RANDALL Lee W. Randall Vice President and Chief March 14,1994 , Accounting Officer - (Principal Accounting OfEccr) Edwin Lupberger (Chauman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Senior Vice President and Chief Financial Of5cer, ; Principal Financial OfScer); Michael B. Bemis, Frank R. Day, John O. Emmerich, Jr., Norman B. Gillis, Jr., Donald C. Hintz, Jerry D. Jackson, Robert E. Kennington, II, Jerry L. Maulden, Donald E. Meiners, John N. Palmer, Sr., Clyda S. Rmt, Walter Wahingena : Robert M. Williams, Jr. (Directors). i By- LEE W. RANDALL March 14,1994 (im W. Randall, Attorney-in-fact)
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NEW ORLEANS PUBLIC SERVICE INC, SIGNATURES i l Pursuant to the requirements of Section 13 or 15(d) of the Secunties Fveh=ay Act of 1934, the registrant l has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorned %e signature of the undersigned company shall be deemed to relate only to matters having mL.,a to such company and any subsidiaries thereof. i NEW ORLEANS PUBLIC SERVICE INC. By i FF W. RANDA1 i Lee W. R and=11, Vice Premdent and Chief Accounting 05cer Date: March 14,1994 Pursuant to the requitanents of the Securities Evehans Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the c=p=r6= and on the dates indicated. He signature of each of the undersigned shall be deemed to relate only to matters having reference to the above named wwy and any subsidiaries thereof. Sienature Illig Ents LEE W. RANDALL Lee W. Randall Vice President and Chief March 14,1994 Accounting 05cer j (Principal Acemating 05cer) , Edwin Lupberger (Chairman of the Board, Chief Executive OEcer and Director, Principal , Executive Omcer); Gerald D. McInvale (Senior Vice President and Chief Finane=1 OEcer, ; Principal Financial Omcer); Michael B. Berms, James M. Cain, John J. Cordaro, Brooke H. Duncan, Norman C. Francu, Donald C. Hintz, Jeny D. Jackson, Jerry L. Maulden, Anne M. Milling, John B. Smallpage, Charles C. Teamer, Sr. (Directors). By: LEE W. RANDALL March 14,1994 (lee W. Randall, Attorney-in fact)
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SYSTEM ENERGY RESOURCES, INC. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 'Ibe signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. l SYSTEM ENERGY RESOURCES,INC. i l l By LEE W. RANDALL l Iee W. Randall, Vice President and Chief Accounting OfHeer Date: March 14,1994 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been eigned below by the following persons on behalf of the registrant and in the capacities and on the dates indW'4 The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof. Sirnature Title Datt j LEE W. RANDALL Lee W. Randall Vice President and Chief March 14,1994 Accounting Officer (Principal Accounting Officer) Donald C. Hintz (President, Chief Executive Officer and Director; Principal Executive Officer); Gerald D. McInvale (Senior Vice President and Chief Financial Officer; Principal FinancialOfficer); Edwin Lupberger (Chairman of the Board), Jerry D. Jackson, Jerry L. Maulden (Directors). By: LEE W. RANDALL March 14,1994 (Lee W..Randall, Attomey-in-fact)
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h EXIIIBIT 23(a) INDEPENDENT AUDITORS' CONSENT . We consent to the incorporation by reference in Post Effective Amendment Nos. 2, 3, 4A, and 5A on Form S 8 to Registration Statement No. 33-54298 of Entergy Corporation on Form S-4, and the related Prospectuses, of our reports dated February 11,1994 (which express an unqualified opinion and include explanatory paragrapi s as to uncertainties because of certain regulatory and litigation matters), appeanng in this Annual Report on Form 10-K of Entergy Corporation for the year ended December 31,1993. We also consent to the incorporation by reference in Registration Statements Nos. 33-36149, 33-48356 and 33-50289 of Arkansas Power & Light Company on Form S-3, and the related Prospectuses, of our reports dated February 11,1994, appeanng in this Annual Report on Form 10-K of Arkansas Power & Light Company for the year ended December 31,1993. We also consent to the incorporation by reference in Registration Statements Nos. 33-46085, 33-39221 and 33-50937 of Louisiana Power & Light Company on Form S-3, and the related Prospectuses, of our reports dated February 11,1994, appeanng in this Annual E coort on Fonn 10-K ofI.ouisiana Power & Light Company for the year ended December 31,1993. We also consent to the incorporation by reference in Registration Statements Nos. 33-53004,33-55826 and ' 33-50507 of Mississippi Power & Light Company on Form S-3, and the related Prospectuses, of our reports dated February 11,1994, appeanng in this Annual Report on Form 10-K of Mississippi Power & Light Company for the year ended December 31,1993. We also consent to the incorporation by reference in Registration Statement No. 33-57926 of New Orleans l Public Service Inc. on Form S-3, and the related Prospectus, of our reports dated February 11,1994, appearing in this Annual Report on Form 10-K of New Orleans Public Service Inc. for the year ended December 31,1993. W
, e also consent to the incorporation by reference in Registration Statement No. 33-47662 of System Energy Resources, Inc. on Form S-3, and the related Prospectus, of our reports dated February 11,1994 (which express an unqualified opinion and include an explanatory paragraph as to an uncertainty resulting fmm a regulatory proceedmg), appeanng in this Annual Report on Forra 10-K of System Energy Resources, Inc. for the year ended December 31,1993. - DELOTITE & TOUCHE New Orleans, Louisiana March 14,1994 I
f' l W M
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EXHIBIT 23(b) CONSENT OFINDEPENDENT ACCOUNTANTS We consent to the incorporation by reference in the i%& statements of Gulf States Utilities , Company on Form S-3 (File Numbers 33-49739 and 33-51181) and Form S-8 (File Numbers 2-76551 and 2 98011) of our reports, dated February 11,1994, on our audits of the Ananaal statenants and financial statement schedules of Gulf States Utilities Company as of December 31,1993 and 1992, and for the years aided December 31,1993,1992 and 1991, which reports include, explanatary paragraphs related to rate-related contingencies, legal preMage and changes in accounting for moome taxes, postratirement benefits, unbilled revenue and power plant materials and supplies and are included in this Annual Report on Form 10-K. COOPERS & LYBRAND Houston, Texas March 14,1994 i t i h i e i l
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l l l 1 r w w e ,s-. m - - -- - - - - - - - - . . _ - - - - - - - - - . - - -
EXHIBIT 23(c) CONSENT OF EXPERTS We consent to the reference to our firm under the headmg " Experts" in this Annual Report on Form 10-K. We further consent to the incorporation by reference of such reference to our firm into Arkanw Power & Light Company's ("AP&L") Registration Statements (Form S-3, File Nos. 33-36149, 33-48356 and 33-50289) and related Prospectuses, pertammg to AP&L's First Mortgage Bonds and Preferred Stock. , Very truly yours, FRIDAY, ELDREDGE & CLARK Date: March 14,1994 4 I l l l 1
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i s EXHIBIT 23(d) I CONSENT We consent to the reference to our firm under the headmg " Experts", and to the inclusion in this Annual ! Report on Form 10-K of Gulf States Utilities Company ("GSU") of the statements oflegal conclusions attributed to us herein (the Statements of Legal Conclusions) under Part I, Item 1. Business " Rate Matters and Regulation" and i in the discussion of Texas jurisdictional matters set forth in Note 2 to GSU's Financial Statements and Note 2 to Entergy Corporation and Subsidiaries Consolidated Financial Statements appeanng as Item 8. of Part II of this Form 10-K, which Statements oflegal Conclusions have been prepared or renewed by us (Clark, Thomas & Winters, a Professional Corporation). We also consent to the incorpo.h by reference in the registration - statements of GSU on Form S-3 and Form S-8 (File Numbers 2-76551,2-98011,33-49739, and 33-51181) of such i reference and Statements oflegal Conclusions. CLARK, THOMAS & WINTERS A Professional Corporation ; Austin, Texas : March 14,1994 l l l P i i r
}
i i l t i I k s
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EXHIBIT 23(e) CONSENT We consent to the reference to our firm under the headmg " Experts" and to the inchsion in this Annual ., Report on Form 10-K of Gulf States Utilities Company ("GSU") of the statements (Statements) regarding the analysis by our Firm of River Bend construction costs which are made herein under Part I, Item 1. Business " Rate l i - Matters and Regulation" and in the discussion of Texas juri dis =1 matters set forth in Note 2 to GSU'r Financial Statements and Note 2 to Entergy Corporation and Subsidianes' Consolidated Financial Statements appeanns as item 8. of Part II of this Form 10-K, which Statements have been prepared or reviewed by us (Sandha Associates). l We also consent to the incorporation by reference in the registration statements of GSU on Form S-3 and Form S-8 l (File Numbers 2-76551,2-98011,33-49739 and 33-51181) of such ..L. c4 and Statements SANDLIN ASSOCIATES Management Consultants l Pasco, Washington March 14,1994 l l l l l l
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's EXHIBIT 23(f) !
I CONSENT OF EXPERTS ; i We consent to the .Jws to our firm under the headmg " Experts" in this Annual Report on Form 10-K. We further consent to the incorporation by reference of such reference to our firm into Louisiana Power & Light Company's ("LP&L") Registration Statements (Form S-3, File Nos. 33-46085, 33-39221 and 33-50937) and the ! related Prospectuses, pertaimng to LP&L's First Mortgage Bonds and Preferred Stock, and into New Orleans , Public Service Inc.'s ("NOPSI") Registration Statement (Form S-3, File No. 33-57926) and the related Ptsp 4 pertammg to NOPSI's General and Refunding Mortgage Bonds : Vesy truly yours, l t MONROE & LEMANN Date: March 14,1994
)
i I
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l EXHIBIT 23(g) i CONSENT OF EXPERTS l We consent to the reference to our firm under the headmg " Experts" in this Annual Report on Form 10-K. We further consent to the incorporation by reference of such .4..wa to our firm into System Energy Resources, Inc.'s (System Energy) Registration Statement on Form S-3 (File No. 33 47662) and the related prospectus pertaimng to System Energy's First Mortgage Bonds, and into Minissippi Power & Light Company's ("MP& Registration Statements on Form S-3 (File Nos. 33-53004,33 55826 and 33-50507) and the related prospectuses pertauung to MP&L's Preferred Stock and General and Refundmg Mortgage Bonds Very truly yours, WISE CARTER CHILD & CARAWAY l Professional Association l By ROBERT B. MCGEHEE Robert B. McGehee l Date: March 14,1994 1
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INDEPENDENT AUDITORS' REPORT ON FINANCIAL STATEMENT SCHEDULES To the Shareholders and the Board of Directors of Entergy Corporation We have audited the consolidated financial statements of Entergy Corporation and subsidianes and the ; financial statements of Arkansas Power & Light Company, Louisiana Power & Light Company, Minninnippi Power
& Light Company, New Orleans Public Service Inc., and System Energy Resources, Inc. as of December 31,1993 and 1992, and for each of the three years in the period ended December 31,1993, and have issued our reports thereon dated February 11,1994, which report as to Entergy Corporation includes erp1===tary paragraphs as to uncertainties because of certam regulatory and litigation matters, and which report as to3 S m Energy Resources, Inc. includes an expInnarnry paragraph as to an uncertamty resultmg from a regulatory prMag; such reports are included elsewhere in this Form 10-K. Our audits also included the Ma=aci=1 statement schedules of these companies listed in Item 14(a)2. These financial statement ark ~4"1= are the insponsibility of the companies' managements. Our responsibility is to express an opinion based on our audits. We did not audit the Ennneial statements of Gulf States Utilities Company (a consolidated subsidiary of Entergy Corporation acquired on December 31, 1993), which statements reflect total assets constitutmg 31% of consolidated total assets at December 31,1993. Those statements were audited by other auditors whose report (which included exp1mantary paragraphs regaramg uncertainties because of certain regulatory and litigation matters) has been furninhad to us, and our opinion, insofar as it relates to the amounts included for Gulf States Utilities Company, is based solely on the report of such other auditors. In our opinion, based on our audits and the report of the other auditors, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
DELOITfE & TOUCHE New Orleans, Louisiana February 11,1994 I
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[ INDEPENDENT AUDITORS' REPORT ON FINANCIAL STATEMENT SCHEDULES To the Shareholders and the Board of Directors of Gulf States Utihties Company Our report en the E=M=1 statements of Gulf States Utilities Company, which includes explanatory paragraphs related to rate-related contingencies, legal prWMp and changes in accounting is included in this . Form 10-K. In connection with our audits of such financial statements, we have also audited the related financial statement schedules of Gutf States Utilities Company included in Item 14(a)2 of this Form 10-K. In our opinion, the En= Mal statement schedules referred to above, when considered in relation to the basic En=e=1 statements taken as a whole, present fairly, in all matenal tespects, the information required to be included therein. COOPERS & LYBRAND Houston, Texas February 11,1994
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INDEX TO FINANCIAL STATEMENT SCIIEDULES Schedule EA81 III Financial Statements of Entergy Corporation: Balance Sheets, December 31,1993 and 1992 S-2 Statements ofIncome - For the Years Ended December 31,1993, 1992 and 1991 S-3 Statements of Retamed Earmngs and Paid-In Capital - For the Years Ended December 31,1993,1992 and 1991 S-4 Statements of Cash Flows - For the Years Ended December 31,1993, 1992 and 1991 S-5 i V Utility Plant 1993,1992 and 1991: Entergy Corporation and Sabsidiaries S-6 Arkansas Power & Light Company S-9 Gulf States Utilities Company S-10 Louisiana Power & Light Company S-12 Mississippi Power & Light Company S-14 New Orleans Public Service Inc. S-15 . System Energy Rcsources, Inc. S-16 VI Accumulated Depreciation and Amortization of Property 1993,1992 and 1991: Entergy Corporation and Subsidiaries S-17 Arkansas Power & Light Company S-20 Gulf States Utilities Company S-21 Louisiana Power & Light Company S-23 Mississippi Power & Light Company S-24 New Orleans Public Service Inc. S 25 System Energy Resources, Inc. S-26 VIII Valuation and Qualifying Accounts 1993,1992 and 1991: Entergy Corporation and Subsidiaries S 27 Arkansas Power & Light Company S-28 Gulf States Utilities Company S-29 -l Louisiana Power & Light Campany S-30 l Mississippi Power & Light Company S-31 l New Orleans Public Serdce Inc. S-32 l X Supplementary Income Statement Information 1993,1992 and 1991: Entergy Corporation and Subsidiaries S-33 Arkansas Power & Light Company S-34 Gulf States Utilities Company S 35 Louisiana Power & Light Company S 36 Mississippi Power & Light Company S-37 New Orleans Public Senice Inc. S-38 System Energy Resources, Inc. S-39 Schedules other than those listed above are omitted because they are not required, not applicable or the required information is shown in the financial statements or notes thereto Colamns have been omitted from schedules 6?ed because the inform.nion ia not applicable. j l S-1 ) i 1
l ENTERGY CORPORATION SCHEDULE III-FINANCIAL STATEMENTS OF ENTERGY CORPORATION BALANCE SHEETS Deessaber 31, 1993 1992 (In %..a.) ASSETS
$22,861 -
Construction work in progrees 6,449,165 $4,153,966 Investment in Wholly owned Subsidiaries i Current Assets: Cash equivalents Temporary cash investments - at cost, which approxunates market 100,401 9,225 Associated e- ; n'== 52,150 110,481 Other 152,551 119,706 Total cash equivalents
- 17,012 Other"w yinvestments w
Accounts receivable: 3,086 2,805 Associated companies 2,467 2,179 Other 1,073 560 Interest receinble 1,166 481 Other 160,343 142,743 Total 93,479 32,387 Deferred Debits $4,329.096
$6,725,848 TOTAL CAPITALIZATION ANDLIABILITIES j Capitalization: !
Common stock,5.01 par value in 1993 and 55 par value in 1992: authonzed 500,000,000 shares; issued and em+=~I% 231,219,737 shares in
$2,312 $875,687 1993; issued 175,137,392 shares in 1992 4,223,682 1,327,589 Paid-in capital 2,310,082 2,062,188 Retamed eernings
- 54 1 Ass cost of treasury stock (1,943 shares in 1992) 6,536,076 4,265,410 Total common shareholders' equity l
Cuneetliabilities: 43,000 - Notes payable Accounts payable: 7,556 7,006 Associated c=9 - 10,069 9,252 Other 1,849 633 Other currentliabilities 62,474 16,891 Total 127,298 46,795_ , Deferred Crochts and Noncurrent Liabilities j _ $6,725,848 _ _ $4,329,096_ Teal i l Entergy Corporation and Subsidiaries Notes to Consolidated Fiw.ial Statements in Part II, Item 8 air incorporated berin by reference. S-2 I
l ENTERGY CORPORATION l SCHEDULE III- FINANCIAL STATEMENTS OF ENTERGY CORPORATION STATEMENTS OF INCOME l For the Years Ended December 31, 1993 1992 1991 (In Thousands) Incom.: Equityinincome of subsidiaries $557,681 $454,947 $471,250 Interest on temporary investments 18,520 20,011 39,664 t Total 576,201 474,958 510,914 Expenses and Other Deductions: Adnunistrative and general expenses 25,129 32,412 27,422 Income taxes 3,587 4,734 93 Taxes other than income (credit) (696) 167 1,156 : Interest (credit) (3,749) 8 211 Total 24,271 37,321 28,882 Net Income $551.930 $437,637 $482,032 f Entergy Corporation and Subsidiaries Notes to Consolidated Financial Statemana in Part II. Item 8 are incorporated herein by reference. l l S-3
l I ENTERGY CORPORATION 1 SCHEDULE 111 - FINANCIAL STATEMENTS OF ENTERGY CORPORATION STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL
\
For The Year Ended December 31, 1993 1992 1991 Gn'Ihousands) Retained Eanungs, January 1 52,062,188 $1,943,298 $1,775,000 551,930 437,637 482,032 Add -Net income 2,614.118 2,380,935 2,257,032 Total Deduct: 288,342 255,479 228,555 Dividends declamion common stock 13,906 59,187 80,009 Common stock retaments 1,788 4,081 5,170 Capital stock and other expenses 304,036 318,747 313,734 Total
$2.310,082 $2,062,188 $1.943,298 Retamed Earnmgs, December 31 Paid-in Capital, January 1 51,327,589 $1,357,883 51,408,640 Add:
Gain Goss)on reacquisition of (20) (1,323) 35 subsidiaries' preferred stock Issuance of $6,667,726 shares of common stock in the merger with GSU 2,027,325 - - Issuance of 174,552,011 shares of common stock at 5.01 par value net of the retirement of 174,552,011 shares of conur.on stock at $5.00 par value 871,015 - -- 4,225,909 1,356,560 1,408,675 Total Deduct: 4,389 28,127 49,391 Common stock retirements (2.162) 844 1,401 Capital stock discounts and other expenses 2,227 28,971 50,792 Total 54,223.682 $1,327,589 $1,357,883 Paid-in Capital, December 31 i Entergy Corporation and Subsidiaries Notes to Consolidated Financial Statements in Part II, Item 8 are incorporated herein by reference. S-4 l l
l ENTERGY CORPORATION , SCHEDULE III- FINANCIAL STATEMENTS OF ENTERGY CORPORATION STATEMENTS OF CASH FLOWS For the Years Ended December 31. 1993 1992 1991 (In Thousands) Operating Activities: Net income $551,930 $437,637 $482,032 Noncash items included in net income: Equity in earnings of subsidiaries (557,681) (454,947) (471,250) Deferred income taxes 3,771 3,146 (3,146) Changes in working cap;tal: Receivables (1,082) 2,875 6,812 Payables 1,367 (26,241) 1,099 Other working capital accounts $31 16,034 (1,368) Common stock dividends received from subsidiaries 686,700 487,854 231,537 Other (20,938) (15,012) (4,259) Net cash flow provided by operatmg activities 664,598 451,346 241,457 Investing Activities: Merger with GSU- cash paid (250,000) - - Investment in subsidiaries (86,221) (79,228) (114,650) Capital expenditures (22,861) - - Decrease in other temporary investments 17,012 114,651 25,355 Advance to subsidiary (24,642) (12,005) (24,163) Net cash flow provided by (used in) investing activities (366,712) 23,418 (113,458) Financing Actisities: Changes in short-term borrowings 43,000 - - Common stock dividends paid (287,483) (256,117) (228,816) Retirement ofcommon stock (20,558) (105,673) (161,640) Net cash flow used in financing activities (265,041) (361,790) (390,456) Net increase (decrease) in cash and cash equivalents 32,845 112.974 (262,457) Cash and cash equivalents at beginning ofperiod 119,706 6,732 26'9,189 Cash and cash equivalents at end of period $152,551 $119,706 $6,732 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Noncash investing and financing activities: Merger with GSU4ommon stock issued $2,031,101 - - Entergy Corporation and Subsidiaries Notes to Consolidated Financial Statements in Part II, item 8 are incorporated herein by reference. S-5
1 l ENTERGY CORPORATION AND SUBSIDIARIES f i SCHEDULE V - UTILITY PLANT 1
)
Year Ended December 31,1993 (In Thousands) l Column C Column D Column E Column F Column G ! Columa A Column B Other Changse- , Debles Balance ; Balance at Addl%as Rettroments (Credits) Acquisities at End Classification Beginning at Cast er Sales (Notes 2J) ofCSU of Period (Note 4) of Period Dectnc Utibty Plant $65,539
$90,813 516,678 $22,847 5(19,105) -
Intangible 13,685,300 84,114 23,939 20,023 54,571,911 9,033,191 Production (Note 3) 833,730 2,254,247 1,401,286 22,304 3,054 (19) Transmission 1,083,628 4,021,450 2,810,941 154,953 28,062 (10) Distribution 123,415 644,304 474,652 48,682 2,393 (52) General - - 5,144 , 5,144 - Leased to other 86,039 749,063 662,400 773 149 - leased from others (Note 1) 156,724 204,469 48,814 - 1,053 (16) Plant and Property held for future use (14,786)
- - - - (14,786)
Plantin Servee.CWIP in rate base - 71,367 71,367 Louisiana regulatory asset i Natura:Grs: - - 446 377 69 - Intar;gibic - 6,912 6,504 409 1 Transmission 41,454 141,553 97,324 3,264 489 - Distnbution - 1,332 7,541 6,194 15 General Steam Products Plant 70,615
- - - - 70,615 Producta - 4,811 4,811 Distribution 263
- - - - 263 General 533,112 179,425 5,672 (273) 50,080 Construction work in progrees 309,552 242,259 244,193 - 94,828 34%293 254,299 Nuclear fuel 381,165 1,133 - - (85) 380.117 1 Plant acquisition adjustments $23.179,708
$752,945 5331,852 5463 $7.555,528 TotalUtihty Plant $15,202.624 Notes:
(1) Includes amounts = Mated with the Grand GulfI and Waterford 3 sak and leaseback tntnsections.
$31 (2) Transfen among functional groups of accounts
$(85)
(3) Amortization of plant acquisition adjustments (12,232) Transfers to non-utahty plant (273) Transfers to preliminary survey and investigation charges (19) Transfers to construction work in progress 13.072 Transfers to electne utility plant - production 5463 Total (4) Depreciation is computed on the straight-line basis at rates based on the estirrated service hves of the various classes of property. Deprecianon provisions on average depreciabic property approlumated 3% in 1993. S-6 i
ENTERGY CORPORATION AND SUBSIDIARIES SCHEDULE V- UTILITY FLANT Year Ended Deceanber 31,1992 (In Thousands) Columa A Columa B Coluna C ColusuaD r .a- 3 Cohuna F Other Cheague. Balance at Retirammees Debies m.i.- Classificattan Beginning Addielses or Sales (Credian) at Ead (Note 4) ofPeriod at Cset (Noems54) (Neens 2 3) of Perind Electnc Utahry Plant intangible $66,118 524,339 $(234) 5122 590,813 Production 8,955,524 129,225 51,547 (11) 9,033,191 Transmission 1,363,773 46,623 9,076 (34) 1,401,286 Distnbution 2.715,057 165,786 69,887 (15) 2,810,941 General 295,033 47,921 19,464 151,162 474,652 i Leased to others 5,144 - - - 5,144 Leased from others (Note 1) 662,150 3,822 3,572 - 662A00 Plant held for future use 47,842 2 3,315 4,285 48,814 Natural Gas: Intangible 377 - - - 377 Tr-M =, 6,488 16 - - 6,504 Distribution 92,465 5,149 290 - 97,324 s General 5,630 569 5 - 6,194 Construction work in progress 305,916 3,649 -
. (13) 309,552 Nuclear fuel 290,136 86A57 120,172 (2,122) 254,299 i 1,367 1,133 i Plant acquisition adjustments - .
(234) Total Utility Plant 514,813.020 5513,558 5277,094 5153,140 $15,202,624 Notes: i (1) Includes amounts associated with the Grand GulfI and Waterford 3 sale and leaseback transactions. (2) Transfers among functional groups of secounts $164 i (3) Amortization of plant acquistion adjustments 5(234) Transfers of service companies' property to eisctric utility plant generet 151,221 from other property Transfers to construchon work in ymgrees 191 Transfers to non utility plant (21) , Transfers to prehnunary survey and invuotigation charges (205) Refund of state sales tax and reisted interest paid under protest (2,122) FERC Complaint Case Settlement 4,310 ) Total $153,140 (4) Depreciation is computed on the sursight-line basis at rates based on the estunsand sernoe lives of the various cleases of property Depreciation provmone on average , depreciable property w._ " 3.0% in 1992. l (5) Transfers to Enter 8y Sernces from General Plant $183 l 1 (6) Sales ofMissouri property $52,783 S-7
l l ENTERGY CORPORATION AND SUBSIDIARIES SCHEDULE V- UTILITY PLANT Year Ended December 31,1991 (In Thousands) Colama B Cohens C Columa D Columa E Column F Cohuna A Other Changmo-Balance at Debits Balsace l Beginales Additimes Retiresnents (Credits) at End Cimadftcation of Period at Cast er Sales (Notse 2-3) of Pertad (Note 4) Electne Utaty Plant
$17,996 $240 - $66,118
$48,362 intangible 8,955,524 ;
8,900,671 96,732 26,249 $(15,630) ' Production 1,363,773 1,290,481 't5,112 1,794 (26) Transmmmon 160,656 22,703 3 2,715,057 2,577,101 Disenbution 295,033 288,044 27,688 8,925 (11,774) General - 5,144 5,144 - Leased to others 662,150 660,291 2,798 939 - Lenned from others (Note 1) 47,842 39,426 1,053 365 7,728 Plant held for future use NaturalGas: - 377 141 236 - Intangible
- - 6,468 6,500 (12)
Transnusman 92,465 i 88,435 4,326 2% - Distribunm - 5,630 6,078 (316) 132 General 3,721 (3,693) 305,916 Construchon work in progress 305,888 - 124,717 208,547 950 290,136 Nuclear fuel 373,016
- (396) 1,367 Plant acquistion adjustnxsts 1,763 -
5270.190 5(22.838) 514.813,020 TotalUtility Plant ,$14,591.341 $514.707 Notes: (I)1ncludseamounts wwith the Grand Gulf I and Waterford 3 asic and hk transmenons-
?
$15,802 _
(2) Transfers among functional groups of accounts
$(396)
(3) Air a of plant acquisition adjustments (3,693) Transfers to r ,1. .;y survey and investigation charges 950 State sales tax and related interest paid under protest 7,694 IERC Complaint Case Settlement
- (27,393) ;
Imse recta =&ahan
$(22.838) .
Total y (4) C-y.hi is computed on the straight-line basis at rates based on the estimated i service lives of the varioos classes of prope:*y. Depreciation provisions en average depreciable property appexinated 3 0% in 1991. r S-8
I ARKANSAS POWER A LIGHT COMPANY SCHEDUI E V. UTILITY PLANT Years Ended December 31,1993,1992 and 1991 Ga Thaimends) Colume A Ceewma B Cohmus C Cahuma D Cahmus E Celumm F Osher salam. m R.uremame two sals Classiscadma Beguissag Addednas er Sales (Credes) at End (Nose 3) ofPeded at Cast (Note 2) (Neses I) of Ported Year Emeed 0 --31, 1993 Elecenc Wlay Plant I Istanebis $88,233 534,687 S22,547 $(19,105) 860,968 4 Productaan 2.131,677 48,661 3,380 - 6,952 2,178,870 Transmusman 644,321 lis,032 1,091 . 653,262 Duanbeam 1,081,852 63,222 12,263 - 1.132,811 Gemaral 117,244 11,423 870 127,718 (79) Plant beid far Amare use 6,605 . . . 6,605 Cassenusaea work is propues 174,909 22,096 . - 197,005 Nuclear Assi 102,435 50,299 59,128 . 93.606 Plaat acquasitaan adjumenumes 298 . . (38) 260 Toul W1ity Plant $4,347,534 5220,420 $104.579 5(12,270) 54,451.105 Year W Decasuber 31,1992 Electnc Wlay Plast Istanyble $64,948 S23,290 $$ . 188.233 Productaan 2,098,632 37,531 4,526 . 2,131,637 T,--
)
636,928 15.519 8,126 . 644,321 Dunnbutaan 1,079,660 56,856 54,664 . 1,081,852 Gemaral 116,611 7,749 7,116 . 117.244 Plant held far Aase me 6,625 2 . 5(22) 6,605 Comunsctaan werk in propeus 139,773 35,136 . . 174,909 Nuclear Asst 121,689 36,624 55,878 . 102,435 l Plant "t adjusannants 340 . . (42) 298 Toul Wlity Plant $4,265.206 5212,707 5130,315 S(64) 54,347,534
)
Year Ended Desamber 31,1991 Elecaric Wlity Plast l i latanyble 547,007 b17,941 . . $64,948 Productaan 2.060,032 45,319 56,719 . 2,098,632 i Tr- 625.244 12,214 530 . 636,928 j Duanbiaien 1,022,421 66,419 9,180 . 1,079,660 Gemaral 130,685 6,490 2.926 $(17,638) !!6,611 Plant held for Aase use 6,625 . . . 6.625
]
C_. work a propeus 138,185 1,588 )
. . 139,773 3 Nuclear Assi 151,793 34,883 64,987 . 121,689 !
Plant acquantian adjussammes 387 . . I (47) 340 Total Wlary Plant $4,182,379 1154.854 584.342 kl7,685) 54,265.206 h E M M { 1 (I) Assertazataan of plant acqumstaan a4istesses $(38) $(42) $(47) l Tramufem to amHaalay plant (12,232) (22) . I Innes reclammassaamo . . (17,638) Total 5(12,270) 5(64) R17,685) (2) Includes assomass asocinead wieb: 1reanfer to Estaray $srvues Auss Gameral Plant .- $183 $2,008 Sals aiMeowi Proprey . 52,783 - Tasal . $$2,966 S2,ioi'~ (3) Dayreciaties is camputed as tbs strai hs-lims 8 hemis at rates based as the estumated service lives of tbs vanais classe of pnyssey, C, pnmssess en averses 4 depsciable propety . ,, ' 3.446 in 1993,1992, and 1991. S.9 l
GULF STATES UTILITIES COMPANY SCHEDULE V- UTILITY PLANT Years Ended December 31,1993,1992 and 1991 (In Thousands) Columa B Coluna C Columa D Coloma E Columa F Other Changes - Balsace at Additions Retirements Debits Balance at Begianlag at Cost er Sales (Credits) End of Classiftention ofPeriod (Note 1). (Note 2) (Note 3) Period (Note 5) Year ended December 31,1993 Electric Utility Plant:
$4,582,874 17,354 $18,287 $(30) $4,571,911 Production 821,013 13,214 799 302 833,730 Transmission 1,034,708 64,318 15,091 (307) 1,083,628 Distri';ution 118,184 5,867 639 3 123,415 General 87,214 911 2,086 - 86,039 Capitalicases 156,657 67 - - 156,724 Property held for future use (14,786) - - - (14,786)
Plant in Service 4WIP in rate base 71,367 - - - 71,367 Iouisiana regulatory asset Natural Gas Utility Plant: 39,994 1,501 41 - 41,454 Distribution 1,166 211 45 - 1,332 General Steam Products Plant: 67,209 4,145 739 - 70,615 Production 4,818 1 8 - 4,811 Distribution 265 - 2 - 263 General 32,305 17,775 - - 50,080 Constnaction work in progress 106,565 19,261 30,998 - 94.828 Nuclear fuel 57,109,553 5134,625 568,735 5(32) $7,175,411 TotalUtility Plant Year ended December 31,1992 Electric Utility Plant:
$4,610,743 $33,232 $61,130 $29 54,582,874 Production 807,025 12,260 1,546 3,274 821,013 Tranamasion 998,406 47,281 7,698 (3,281) 1,034,708 Distribution 5,624 636 (14) 118,184 General 113,210 19,012 68,948 746 - 87,214 Capitallesses 157,293 630 3 156,657 Property held for future use (9)
(14,786) - - - (14,786) PlantIn ServiceCWlP in rate base 71,367 - - - 71,367 Louisiana regulatory ammet Natural Gas Utility Plant: 39,027 1,136 169 - 39,994 Distribution 1,062 112 8 - 1,166 General Steam Products Plant: 66,414 804 9 - 67,209 Production 4,818 4,729 89 - - l Distribution 265 1 1 - 265 ) General (4,233) - 32,305 Construction work in prog:ress 36,538 - 18,074 18,580 - 106,565 107,071 Nuclear fuel $7,109,553 57,017,376 5183,319 591.153 $11 Total Utility Plant S-10
1 l GULF STATES UTILITIES COMPANY l SCHEDULE V. UTILITY PLANT (Continued) Years Ended Deceanber 31,1993,1992 and 1991 (In Thousands) Colussa B Cohann C Coluem D Cohann E Cohann F Other G anges. Balance at Additless Retirosesses Debsta Bat ==<a at (1 aaestion Beginabig at Cast er Salso (Credits) End of (Note 5) of Period (Note 1) (Note 2) (Nc,te 3) Period Year ended December 31,1991 Electnc Utility Plant Production $4,600,833 $11,095 $1,122 $(63) $4,610,743 Tran==-a= 794,872 13,673 3,762 2,242 807,025 Distribution 964,420 46,099 9,866 (2,247) 998,406 General 108,463 4,987 259 19 113,210 Capitalienses 19,423 - 411 . 19,012 Nt purchased or sold . . . . . Property held for thture use 157,449 (156) 1 1 157,293 Plant la SernceCWIPin rate base (14,648) (138) . . (14,786) ina-ana regulatory asset (Note 4) . . . 71.367 71,367 Natural Gas Utility Plant Disenbution 38,522 593 88 . 39,027 General 970 97 5 . 1,062 Steam Producte Plant Production 66,313 333 294 62 66,414 Distribution 4,722 . . 7 4.729 General 262 5 2 - 265 Construcace work in progress 24,576 11,962 . [ 36,538 Nuclear fusi 135,285 13,958 42,172 . 107.071 TotalUtility Plant $6,901,462 $102,508 $57,982 $71,388 $7,017,376 i Notes: (1) Additions at cost, as aetadud in Column C, eaamim prunarily of constructos expsaditures, est of amouato transferred to plant-in-service, and , '- for ordinary evt===ana and improvements ofGSUs trasanuamon and distribution synessa, l (2) In 1992 GSU changed its accounting procedures to include is inventory, power plant matenals sad supplies pronously exposand or capitalized as plant in service. ne effect of the change was to decrease amounts pronously capitalized as plaat in service by $35.7 millica. ' (3) Repressets various transfers between functional accounts (4)la nuordance with a rate order in Imisaans effective March 1,1991, tire lESC required GSU to modify its treatment of certain flow through bene 6te relased to Allowance for Funde Used Dunns Construchon recorded on capital expenditures prior to 1986. Accordingly, GSU inc eased utility plant by $71.4 =ha increased accumulated depreciatiau by $8.4 =La and iniaansed the balance of accumulatal deferred iara=* tems by
$63 m b a.
(5) Depreciation is computed oc the straight-bas bn$is as rows beiscd on the e-5 ==aad servbe liws of de varmas clamana of prope:ty, Depreciation provisions on aversgo deptm:iable property appremeat d 2.7% in 1993, 1992, and 1991. S.ll
1 LOUISIANA POWER & LIGHT COMPANY SCHEDULE V UTILITY PLANT Years Ended December 31,1993,1992 and 1991 (In Thousands) Column B Column C Column D Column E Column F Columa A Other Changes-Debits Balance Balance et Additions Retirements (Credits) at End Classification Beginning of Period at Cast or Sales (Notes 1-2) of Period (Note 4) , Year Ended December 31,1993 Electric Utihty Nt - $3,190
$2,222 $968 -
Intangible 3,013.569 3,004,940 20,533 $11,903 $(1) Ptuduction 375,098 367,794 8,994 1,675 (15) Transmission 1.151,459 1,105,360 56,547 10,437 (11) Dutribution 97,447 91,834 6,615 1,029 27 General
- - 5,144 14aaed to others 5,144 -
225,083 - - - 225,083 Leased from others(Note 3) 114 - - - 114 Nt held for future use 133,536 Construction workin pmgress 67,535 66,274 - (273) 66,627 27,894 29,323 - 65,198 Nuclear fuel - 2 - - (2) Nt acquisition adjustments
$187,825 $54,367 $(275) $5,069,838 Total Utility Plant $4,936.655 Ycar Ended December 31,1992 Electric Utility Nt}}