ML18230A831
| ML18230A831 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 03/23/1977 |
| From: | Nightingale D State of NC, Utilities Commission |
| To: | Office of Nuclear Reactor Regulation, State of NC, Utilities Commission |
| References | |
| Download: ML18230A831 (14) | |
Text
L~' E iV E Of MAR 23 1S77 CHIEF CLERK N. C. UTILITIES COMMISSION DOCKET NO. E-2, SUB 297 BEFO"E THE NORTH CAPOLIiNA UTILITIES COMMISSION IN THE MATTER OF APPLICATION OF CAROLINA POl!ER AND LIGHT COMiPANY FOR INCREASE IN ITS RATES AND CHARGES UocKeT+ ~y g~g/y jg~
COBtfol Date of Documenn:
RKGU T a Y OCKHFILK TESTIMONY OF DENNIS J. NIGHTINGALE UTILITIES ENGINEER DIVISION OF ENGINEERING Staff, North Caro1ina Utilities Commission March 23, 1977
DOCKET NO. E-2, SUB 297 1 g. Hill you state your name and address for the record?
2 A. My name is Dennis J. Nightingale. My business address is One West 3 . Morgan Street, Raleigh, North Carolina 27602.
5 g. What is your position with the North Carolina Utilities Commission Staff?
7 A. I am a Utilities Engineer in the Electric Section of the Engineering 8 Division.
10 g. Hill you briefly discuss your education and experience?
ll A. I received my Bachelor of Science Degree in Electrical Engineering 12 from Northeastern University in June, 1971. Upon graduation, I 13 joined the Division of Power Supply and Reliability: Bureau of Power 14 of the . ederal Power Commission. My primary responsibility there 15 was the analysis and evaluation of the adequacy and reliability of 16 electric power planning by utilities, power pools and the nine 17 regional reliability counci ls. In the performance of my duties, I 18 have prepared several Bureau of Power Staff reports, represented 19 the Federal Power Commission on both the FEA's Inter-agency Task 20 Group on Power Plant Reliability and on a Florida Public Service
'1 Commission and Florida Coordinating Group's Joint Study using loss 22 of load probability to ascertain the time frame for bulk power inter-23 connections between Florida and Georgia. I also testified before 24 the Atomic Safety and Licensing Board on the need for power (AEC 25 Docket Nos. 50-346, 50-334, 50-413 and 50-414). In October, 1975, 26 I joined the Staff of the North Carolina Utilities Commission. As
1 a member of the Commission Staff, I have testified on the reasonable-2 ness of current plant in service and construction program for Carolina 3 Power and Light Company (Docket No. E-2, Sub 264), the need for new 4 generating facilities for both Duke Power Company (Docket Ho. E-7, 5 Sub 166) and Carolina Power and Light Company (Docket Ho. E-2, Sub 241),
6 and Docket Ho. E-100, Sub 22 in the matter of investigation, analysis 7 and estimation of the need for future generating capacity for North 8 Carolina. I have also assisted in the preparation of Commission g testimony before the Environmental Protection Agency (EPA Docket Ho.
10 AHNC 512 NR). Currently, I am a member of the Institute of Electrical
]1 and Electronics Engineers (IEEE).
12
]3 g. What is the subject of your testimony in this proceeding7 14 A. t<y testimony is concerned with the reasonableness of Carolina Power 15 and Light Company's current plant in service and construction pro-16 gram.
17 18 g. How did you proceed with.your investigation of CP&L's current capacity 19 and future construction program'?
20 A. The analysis of CPSL's current capacity and future construction pro-21 gram relied heavily on the information contained in the Commission's 22 "Report of Analysis and Plan; Future Requirements for Electricity 23 Service to North Carolina," dated February, 1977. This report pro-24 vides an independent long-term forecast of North Carolina utility 25 peak loads and a plan for generation capacity requirements. Three 26 basic conclusions of this report were that a reserve criterion ranging
1 between 15 and,20 percent for the summer peaking season ana a reserve 2 of not less than 20 percent for the winter peaking season would pro-3 vide adequate and reliable electric service, that nuclear facilities 4 have an economic advantage over other types of base load generating 5 facilities and that the utilities in North Caroli ra should have 6 approximately 1/2 base, 1/3 intermediate and 1/6 peaking capacity.
8 In its report the Commission concluded that between 1976 and 1986 9 Carolina Power and Light Company would experience an annual peak load 10 growth of 6.86 percent. Based on this load growth and its summer/
ll winter reserve criterion the Commission developed a capacity construc-12 tio'n schedule for CP&L as shown in DJf! Exhibit No. 1. This capacity 13 schedule would give CP&L about 50 percent base capacity, 32 percent 14 intermediate capacity and 18 percent peaking capacity for 1977. DJN 15 Exhibit No. 1 also contains CP&L's proposed capaci ty construction 16 schedule (from Harris Exhibit No. 2) which results in a capacity mix 17 of about 55 percent base capacity, 29 percent intermediate capacity 18 and 16 percent peaking capacity for 1977.
19 20 The significant difference between these construction schedules is 21 the timing of commercial operation for various units. Based on its 22 reserve criterion the Commission's construction schedule has delayed Brunswick No. 1 one year while advancing the Mayo Creek and Harris 24 units approximately one year. Since the timing of the Brunswick unit is of special importance to this proceeding further investigation into the need for the Brunswick unit was undertaken.
r
1 The load data used in the Commission's analysis and plan included 2 the Summer of 1976. Peak load estimates were calculated from this 3 point and reserve levels were calculated using these load estimates.
4 DJN Exhibit No. 2, Part A, shows the peak load estimates for the years 5 1977-1979 and poss-.'ble'eserve margins depending on the commercial 6 operation of Brunswick No. 1. The reserves shown on Part A of this 7 exhibit indicate that CPSL would satisfy the Commission's reserve 8 criterion in 1977 without the Brunswick unit, but would not meet 9 this criterion if the unit were not operating in 1970; Since ~
10 analysis was performed, CPIIL experienced a new winter peak load of 11 5,509 re.
A more reasonable load scenario would be to apply the annual 6.86 per-14 cent growth factor to both CPSL's 1976 Summer and 1976-77 Winter 15 peaks to forecast future summer and winter peak loads. Par t B of DJN Exhibit No. 2 contains the reserve margins using this assumption.
17 This app. oach indicates a need for Brunswick No. 1 in the Winter of 18 1977-78.
19 20 g. Have you studied any of the costs associated with delaying Brunswick 21 No. 1. from 1977 to 1978?
22 A. Yes, I have looked at some of the possible costs associated with 23 delaying the Brunswick unit one year.
25 The first cost I looked at was an additional year of allowance for funds used during construction if the plant was not declared com-27 mercial. Using an eight (8) percent factor to CPSL's estimated
1 331.4 m'illion dollar cost results in an additional cost of 26.5 2 million dollars. This raises the installed cost from about 404 3 dollars per K>J to about 436 dollars per KW. Using a fixed charge 4 rate of si.xteen (16) percent over thirty (30) years, the additional 5 26.5 million dollar cost results in an additional annual cost of about 4.3 million dollars.
8 Another cost studied was the cost of replacing the energy which 9 could have been generated by the new Brunswick unit. In looking at 10 this cost various assumptions were made in determining the amount 11 of energy the Brunswick unit could produce and .he costs associated 12 with energy from other sources.
14 With regards to the amount of energy the new Brunswick unit could 15 produce in 1977 it was assumed that the new unit would not exceed 16 the current licensed. capacity ratirg (790 mw) of Brunswick No. 2.
17 The second assumption involved the selection of a capacity factor 18 for the unit. There is a high degree of uncertainty surrounding 19 the availability of any new unit during its first year of operation.
20 Brunswick No. 2 had a capaci ty factor around 35 percent its first 21 year of operation. Because of the experience CPAL has gained with 22 the operation of Brunswick No. 2, its sister unit Brunswick No. 1 23 should not experience the same events and therefore should have a 24 better (higher) capacity factor during its first year of operation.
25 For this analysis it was assumed that Brunswick No. 1 would generate 26 at a 65 percent capacity factor. This assumption results in a 27 probable energy generation of 4,498,260 megawatt hours.
1 Assuming nuclear energy has a production cost (fuel plus 0 5 H 2 expenses) of 4 mills/KHH, the cost of this nuclear energy would 3 . be slightly urider 18.0 million dollars (DJN Exhibit No. 3). If 4 we further assume that the nuclear fuel cost is approximately 5 3.5 mills/KHH then the cost of fuel for this energy would be about 6 15.7 million dollars.
8 CPSL could pick up this "lost" energy by generation on its own 9 system or by purchasing energy from neighboring utilities. If 10 the assumption was made that CP8L would generate this energy 11 internally they should use the lowest cost, generally the most 12 efficient, units available. The other end of the cost spectrum 13 would occur if the most expensive energy producing units (combus-14 tion turbines) had to be used.
15 16 The cheapest energy on CPSL's system would probably come from exist-17 ing base load nuclear units. Since nuclear base load units operate 18 as long as physically possible they would not be available to supply 19 any make up energy. The next cheapest energy would come from CPSL's 20 coal fired units.
22 For this'analysis it was -assumed that CPEL would use its ten (10) 23 most efficient coal units, as r: ported in the 1975 FPC Form 1, to 24 supply make up energy. DJN Exhibit No. 3 shows the assumptions 25 used to calculate the cost of the coal fired make up energy. The 26 energy cost would be about 51.0 million dollars, or about 33.0
million dollars more than the estimated cost of the energy from the Brunswict unit. The fuel cost increase would be approximately 33.0 million dollars.
Under the assumption that the probable'runswic'nergy was supplied by combustion'urbines the cost as shown in DDN Exhibit No. 3 would be approximately 222.4 million dollars. This is a 204.4 million dollar d;fference from the estimated Brunswick energy cost. The fuel cost increase would be about 197.7 million do'.lars.
10 ll It is doubtful that the make up energy would be supplied by just 12 coal fired units or by just combustion turbines.. Depending on load 13 variations a combination of both types of units will be required to 14 supply the energy which the Brunswick unit would have provided to 15 the system. However, these two scenarios do provide upper and lower bounds on the additional energy costs associated with a one year 17 delay of the Brunswick unit.
18 19 Purchase power from neighboring utilities is another alternative 20 to the energy the Brunswick unit could provide. Neighboring utilities, 21 specifically Duke and Vepco, appear to have sufficient'eserves to 22 sell large blocks of power to CP8L during the next year. It seems 23 unlikely that CP8L would be able to purchase large amounts of in-1 24 expensive base generation. CP8L would probably purchase intermediate 25 or low cost peaking capacity. A cost of 15 mills/KWH was assumed 26 to approximate the cost of purchase energy. Using this assumed
1 v'alue,, purchase energy would cost approximately 67.5 million dol-2 lars to replace the Brunswick energy. That is about 49.5 million 3 . dollars above the estimated cost of the Brunswick ruclear energy.
5 g. Did you calculate the cost to the consumer of placing the Brunswick 6 unit into service one year earlier than needed for system reliability?
7 A. Using an original cost factor of 9.69 percent, calculated from the 8 requested rates in Exhibit I of CPSL's Application,and multiplying 9 this by the cost of the Brunswick unit (331.4 million dollars) the 10 gross increase in cost to the consumer for Brunswick No. 1's first 11 year of operation would be about 32.1 million dollars; 12 13 g. Would you please summarize your testimony?
14 A. CPSL's current installed capcity closely approximates the Commission's 15 recommended capacity breakdown. The addition of Brunswick No. 1 16 slightly alters. the proportions of base and intermediate generating 17 -capacity. -
In determining the need for the Brunswick unit two load 18 scenarios were studied. In both cases there was no need, based on 19 the Cormnission's reserve criterion for adequate and reliable electric 20 service,, shown for Brunswick No. for the Summer of 1977. The second 1
21 scenario'did, however, indicate a need for this unit in the Winter of 22 1977-78.'3 24 Calculations of some of the possible costs associated with a one year 25 delay of Brunswick No. 1 indicated that a delay could increase the 26 capital cost approximately 26.5 million dollars (about a 4.3 million
dollar additional annual cost) or from 404 dollars per K'H to 436 dollars per KW. There would also be an additional fuel expenditure 3 ranging from 33.0 to 197.7 million dollars due to the delay of the Brunswick unit.
E These costs of delaying the unit should be compared to the cost to the consumer fo. the Brunswick units first year of operation. Based on CP&L's rate of return request on original cost investment the gross increase in cost to the consumer for the first yea'r of opera-10 tion would be about 32.1 million dollars.
12 lt should be noted that the fuel cost and production statistics 13 utilized in these computations are estimates from various sources and do not tie directly to the rate case numbers, though they com-15 pare closely.
17 g. Ooes this conclude your testimony?
18 A. Yes.,
19 20 21 22 23 25 26
OJH EXHIBIT HO. 1 CPSL Construction Schedule 1977-1986 Year NCUC 2/77 CPSL 12/76 1977 Brunswick 1 1978 Brunswick l.
1979 1980 Roxboro 4 Roxboro 4
'1981 Mayo Creek 1982 1"'arris 1983 1 Mayo Creek 1 1984 Mayo Creek 2* Harris 1 1985 Har ris 2 Mayo Creek 1 1986 Peaking Uni ts Harris 2 "The Mayo Creek units were not specifically listed in the Commission's construction schedule in the February I
report.
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DJN EXHIBIT NO. 2 Possible CPSL Reserve Margins Percent Reserves Peak Brunswick Installed Surteer of Load
, MW 1977 1978 1979 PART A 1977 S 5,472 35.8 21. 3 21. 3 W 5,472 42.1 27.6 27. 6 1978 S 5,848 27.1 27.1 13.6 W 5,848 32.9 32.9 19.4 1979 S 6,249 19.4 19.4 19.4 W 6,249 24.4 24.4 24.4 PART B 1977 S 5,472 35.8 21.3 21.3 W 5,887 32.0 18.6 18.6 1978 S
5,848',291 27..1 27.1 13.6 W 23. 6 23.6 11.0 1979 S 6,249 19.4 19.4 19.4 W 6,722 15.6 15.6 15.6
DJN EXHIBIT NO. 3 Energy Replacement Cost for Brunswick No. 1 Dollars 1000's Assumption: 65 percent capacity factor Probable Energy - eneration 790,000 x e65 x 8,760 = 4,498,260,000 KWH
- 1) Cost of Brunswick production assume nuclear production cost of 4 mills/KWH 4,498,260,000 x 4 x 10" 17,993
- 2) Probable coal production (10 most efficient units - 1975) assume heat rate of 9,862 BTU/KWH~
assume coal cost of 1104/MBTU estimate 0 8 M expense at .5 mills/fQ)H 4,'498';260,000 x.9,862 x 1 1 x 10-6 48, 798 4,498,260,000' 5 x 10"4 2,249 5,047
- 3) Probable turbine production assume heat rate of,l8,250 oil cosi of 2Q4/MBTU BTU/KWH'ssume estimate 0 a M expense at 2 mills/KM) 4;498,260,000 x 18,250 x 2.6 x 10 213,442 4,498,260,000 x 2 x 10-3 8,987 222, 39
- 4) Probable purchase power assume a 15 mill/KWH charge 4,498,260,000 x 15 x 10 3 67,474
- Numerical average of 10 most efficient units reported in CP8L's 1975 FPC Form 1 Heat rate based on Darlington County GT heat rate for 1975