ML19308A811

Answers to Attorney General Question Transmitted W/Pa Morris 710225 Ltr.Submitted as Amend 26 to Application for OL

ML19308A811
Person / Time
Site:	Oconee
Issue date:	03/29/1971
From:	Thies A DUKE POWER CO.
To:
References
NUDOCS 7912120602
Download: ML19308A811 (44)

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OCONEE NUCLEAR STATION UNI'1S 1, 2 and 3 D a> w LICENSE APPLICATION Docket Nos. 50-269,_-270, and -287

' 5:kq fy yp ANSWERS TO ATTORNEY GENERAL'S QUESTION ATTACHED TO DR. PETER A. MORRIS' LETTER OF FEBRUARY 25, 1971 I

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• Submitted as Amendment No. 26

' March 29, 1971 f

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w March 29, 1971 Dr. Peter A. Morris, Director Division of Reactor Licensing Atomic Energy Commission Washington, D. C. 20545 Re: Oconee Units 1, 2 and 3 Docket Nos. 50-269, -270, and -287

Dear Mr. Morris:

Duke Power Company is filing . herewith Amendment No. 26 to its Application for Licenses for the Oconee Nuclear Station, which is under construction pursuant to provisional construction per-mits CPPR-33 -34, and -35 issued by the Commission on November 6, 1967. This filing includes three (3) signed original copies of the Amendment with attachments and twelve (12) copies of

" Answers to Attorney General's Questions attached to Dr. Peter A. Morris' letter of February 25, 1971."

Sincerely, s/A. C. Thies A. C. Thies

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, DUKE POWER COMPANY OCONEE NUCLEAR STATION UNITS 1, 2 and 3 LICENSE APPLICATION Docket Nos. 50-269, -270, and -287

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ANSWERS TO ATTORNEY GENERAL'S QUESTION ATTACHED TO DR. PETER A. MORRIS' LETTER OF FEBRUARY 25, 1971 O R s /

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Submitted as Amendment No. 26 March 29, 1971 i

i Ouestion No. 1:

State separately for hydroelectric and thermal generating resources applicant's 4

most recent peak load and dependable capacity for the same time period. State

, applicant's dependable capacity at time of system peak for each of the next

-- ten years for which information is available. Identify each new unit or re-l source.

'" ' Answer:

, Duke Power Company's most recent peak load occurred during the hour ending at 7 p.m., January 19, 1971. The load, installed generating capacity, and powar available under firm purchase contracts at that time were:

6 399 MW Peak iaad 5 882 MW Dependable thermal capacity 862 MW Hydro capacity, dependable rating under adverse stream flow conditions 145 MW Purchase from AEPA 21 MW Purchase from SCE&C 3 MW Dependable capacity purchase from miscellaneous small hydro plants 6 913 MW Total Dependable Capacity For each of the next ten years, the estimated system peak load and dependable capacity resources including additions scheduled or planned are:

6 913 dnJ Present Dependable Capacity 1971 Scheduled Additions 209 MW Combustion Turbines (10 Units) 140 MW Keowee Hydro 78 MW Fir- Purchase (CP&L Asheville No. 2 Unit) 886 5fW Oc nee No. 1 ,

m 8 226 ?nJ 1971 Peak Load Dependable Capacity 6 856 MW 1971 Estimated summer peak load 7 005 MW 1971-72 Estimated winter peak load 1972 Scheduled Additions:

590 MW Cliffside No. 5 886 MW Oconee No. 2 (20) MW . Firm purchase reduction (CP&L Asheville No. 2 Unit) l 9 682 'tW 1972 Peak Load Dependable Capacity 7 516 MW 1972 Estimated summer peak load 7 651 MW 1972-73 Estimated winter peak load 1-1 1

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1973 Scheduled Additions:

886 MW Oconee No. 3

- (79) MW Retirement (Buzzard Roost, Tiger, Gwd. Mills)

(18) MW Firm purchase reduction (CP&L Asheville No. 2 Unit) 10 471 MW 1973 Peak Load Dependable Capacity

= 8 237 MW 1973 Estimated summer _ peak load

. 8 374 MW 1973-74 Estimated winter peak load 1974 Scheduled Additions:

305 MW Jocassee Hydro

-. 1 143 MW Belews Creek No. 1 (18) MW Firm purchase reduction (CP&L Asheville No. 2 Unit) 11 901 MW 1974 Peak Load Dependable Capacity 9 027 MW 1974 Estimated summer peak load

, 9 101 MW 1974-75 Estimated winter peak load ir-1975 Scheduled Additions:

1 143 MW Belews Creek No. 2

, (22) MW Firm purchase reduction (CP&L Asheville No. 2 Unit) 9 13 022 MW 1975 Peak Load Dependable Capacity 9 890 MW 1975 Estimated summer peak load 9 917 FnJ 1975-76 Estimated winter peak load 1976 Scheduled Additions:

1 150 MW McGuire No. 1 14 172 inJ 1976 Peak Load Dependable Capacity 10 833 15J 1976 Estimated peak load 1977 Scheduled Additions:

1 150 MW McGuire No. 2 15 322 inJ 1977 Peak Load Dependable Capacity 11 862 FN 1977 Estimated peak load 1978 Scheduled and Planned Additions:

s. 305 MW Jocasse Hydro (scheduled) 1 150 MW No. l Unit at New Plant X (planned)

, 16.777 MW 1978 Peak Load Dependable Capacity 12 985 'IW 1978 Estimated peak load 1979 Planned Additions:

1 150 MW No. 2 Unit at Plant X 17 927 31W 1979 Peak Load Dependable Capacity 1-2

14 209 MW 1979 Estimated peak load 1980 Planned Additions l 300 MW No. 1 Unit at New Plant Y

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, 19 227 MW 1980 Peak Load Dependable Capacity

. 15 542 MW 1980 Estimated peak load i

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Question No. 2:

State applicant's estimated annual load growth for each of the next 20 years

or for the period applicant utilizes in system planning.

li Answer:

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, , _ Applicant's generation planning currently extends throu3h 1982. Estimated

j annual peak loads and growth for the 1971-1982 period are

il Estimated- Annual Growth

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Year Peak Load-MW MW '%

1971 6 856 572 9.1 i,- 1972 7 516 660 9.6 i 1973 8 237 721 9.6 1974 9 027 790 9.6 1975 9 890 363 9.6 1976 10 833 943 9.5

_ 1977 11 862 1 029 9.5 1978 12 985 1 123 9.5 r- 1979 14 209 1 224 9.4

) 1980 15 542 1 333 9.4 1981 16 994 1 452 9.3

,_ _ 1982 18 575 1 581 9.3 ll Ana i

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1 e r-Ouestion No. 3 fi j F- State estimated annual load growth of companies or pools upon which the economic

!! justification of the subje-+. unit is based for each of the next 20 years or for

- the period applicant utilizes in system planning. Identify each company or l r. ,

pool member.

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l Answer:

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il Economic justifica* ' ,f the Oconee generating units was based on load growth

! solely within Duke Power Company's service area and was completely independent i -~ of any pooling or coordination arrangements with interconnected companies.

The three Oconee generating units are sized to be about 12.9, 11.8, and 10.8 i' percent respectively of the estimated 1971, 1972, and 1973 peak loads. In r- 1959, 1960, and 1961, Duke installed the last three units at its Allen steam electric station. These three units had capabilities of 11.6, 10.8, and 10.5 percent respectively of the peak load experienced during the year of installation.

' f-- During the period between completion of the Allen Station and the present, Duke l,. constructed its four-unit Marshall steam electric station. The Marshall units

ranged in size from 8.7 to 12.1 percent of the Duke area peak load during the

} -- year brought in service. The size and timing of the Oconee units are a con-tinuation of Duke's practice of building the most economical units for sup-i' plying its service area.

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Question No. 4

-. For the year the subject unit would first come on line, state estimated annual load growth of any coordinating group or pool of which the applicant is a member (other than the coordinating group or pool ref erred to in the applicant's response to Item 3) which has generating and/or transmission planning functions.

Identify each company or pool member whose loads are indicated in the response i , hereto.

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j Answer

Duke Power is a member of the Southeastern Electric Reliability Council and also of the Virginia-Carolinas Reliability Agreement. The purpose of each organization is to augment further the reliability of the members bulk power supply systems. Both organizations provide for review of matters pertaining to reliability, but do not have generation and transmission planning respon-

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sibilities, and hence are not coordinating groups under the definition of

" coordination" as contained in the question. However, in response to the F.P.C. Order 383-2 load growth information for the Virginia-Carolinas group

'f the Southeastern Electric Reliability Council filed September 1, 1970, h the Federal Power Commission shows an annual loed growth for the area of 9.8 percent. Members of the Virginia-Carolinas Sub-region group of SERC are Duke Power Company, Carolina Power & Light Company, Virginia Electric and Power Company, South Carolina Electric & Gas Company, Yadkin, Inc.,

Southeastern Power Administration and South Carolina Public Service Authority.

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Question No. 5:

State applicant's minimum installed reserve criterion (as a percentage of load) 1/ for the period when the subject unit will first come on line. If applicant

. shares reserves with other systems, identify the other systems and provide

__ minimum installed reserve criterion (a's a percentage of load) 1/ by contracting parties or pool for the period when the proposed unit will first come on line.

r- Answer:

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Duke Power's criteria for reserves in MW and as a percent of the peak load for winter season each year, would require reserves equal to 2393 Fni or 34.1 per-cent in 1971, 2509 dni or 32.7 percent in 1972, and 2599 FGi or 31.1 percent in 1973. Existing firm purchase contracts would reduce the required company

,_ owned reserves by 247 MW in 1971, 227 Ini in 1972, and 209 MW in 1973. All

load levels are considered in the determination of adequate reserves. The l criteria, however, expresses required reserve in capacity in excess of peak load requirements and as a percent of peak load.

The high reserve levels indicated are considered prudent in view of the industry's experience with operation of large units and of nuclear plants.

- In spite of the high reserve required, these plants offer the most economical alternative for meeting our load growth.

Under the agreement whereby each of the four companies which formerly com-prised the CARVA Pool voluntarily withdrew from the pool, Duke will share

. reserves with VEPCO, CP&L, and SCE6C until April 30, 1973. The reserve criteria of those companies is not known to Duke Power. The actual reserve level will depend on the completica dates of several capacity additions now under construction on all four systems, but will undoubtedly be substantially less than Duke's current criteria.

if Indicate whether loads other than peak loads are considered.

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n Question No. 6:

Describe methods used as a basis to establish, or as a guide in establishing the criteria for applicant's and/or applicant's pool's minimum amount of installed reserves. (e.g., (a) single largest unit down, (b) probability

'_,. methods such as loss of load one day in 20 years, loss of capacity once in

five years, (c) other methods and/or (d) judgment. List contingencies

! . other than risk of forced outage that enter into the determination.]

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Answer

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Duke Power's criteria for reserves includes allowances at the time of peak load for:

l. Load increases brought on by severe weather. (Peak load estimates are based on average weather.)

2. The unscheduled outage of the largest generating unit.

3. Forced outages or reductions in capability of other generating units, based on operating experience.

4. Forecast error or the outage of additional generation equi-Valent to the largest unit.

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Question No. 7:

Indicate whether applicant's system interconnections are credited explicitly or implicity in establishing applicant's installed reserves.

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Answer:

Except for the firm purchases referred to in Question 5, Duke Power's inter-j~ connections are not explicitly credited with reserve capability. Although i

Duke's interconnections have a combined capability of the same order of magni-tude as its reserve requirements, they cannot be assigned a firm reserve

. .. responsibility simply because reserves throughout the eastern half of the country are so short that firm reserve of any significant amount is not available from other systems.

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Question No. 8:

List rights to receive emergency power and obligations to deliver emergency power, rights or obligations to receive or deliver deficiency power or unit

. power, or other coordinating arrangements; by reference to applicant's

,- . Federa) Power Commission (FPC) rate schedules (i.e. ABC Power & Light Company, FPC Rate Schedule No.15 including supplement 3-5) 2f, and also by reference

- to applicant's state commission filings. Where documents are not on file with I

. the FPC, supply copies, or where not reduced to writing describe arrangements.

. I" Identify for each such arrangement the participating parties other than appli-

cant. Provide one line electrical and geographic diagrams of coordinating groups or power pools (with generation or transmission planning functions) of which applicant's generation and transmission fac114 *ies constitute a part.

ii Answer:

i 1. Duke Power Company FPC Rate Schedule No.10, Interconnection Agreement be-tween Duke Power Company and Carolina Power & Light Company, dated June 1,

T~ 1961, Service Schedules A, B, C, D, E, and F. Certificate of Concurrence

,i filed by Carolina Power & Light Company.

p 2. Duke Power Company FPC Rate Schedule No. 8, Interconnection Agreement be-tween Duke Power Company and South Carolina Electric & Gas Company dated

l- Augus t 28, 1956, Service Schedules A, B, C, D, and E. Certificate of

, _, Concurrence filed by South Carolina Electric & Gas Company.

3. Duke Pmaer Company FPC Rate Schedule No. 9, including Supplements 2 and 3.

Interchange Contract between Duke Power Company and Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, and Southern Services, Inc. , dated June 1,1961, Service Schedules A, B, C, E, and F. Southern Company FPC Rate Schedule 25 including Supplements 1, 3, 5 and 6.

4. Duke Power Company FPC Rate Schedule No. 4 including Supplements 1, 3 and

4. Interchange Agreement between Duke Power Company and Appalachian Power Company dated February 28, 1949, Service Schedules A, B1, C, and E.

Appalachian Power Company FPC Rate Schedule 18 including Supplements 4 and 6.

5. Duke Power Company FPC Rate Schedule No. 10 including Supplement 3. Standby Concurrent Exchange Agreement between Duke Power and Carolina Power and Light Company, dated January 1,1957. Carolina Power & Light Company FPC Rate Schedule No. 45 including Suppiement 1.

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6. Wheeling Agreement between Duke Power Company and South Carolina Electric and Gas Company. South Carolina Electric & Gas Company FPC Rate Schedule L ~ No. 20.

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$/ List separately and identify certificates of concurrence.

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7. 1971 Generator Installation Agreement between Duke Power Company and Carolina Power & Light Company. Carolina Power & Light Company FPC Rate Schedule No.98.

. 8. Duke Power Company FPC Rate Schedule No. 11 including Supplements 1, 2, i r- .

3, and 4 Interconnection Agreement between Duke Power Company and Yadkin, Inc. Yadkin, Inc. FPC Rate Schedule No. 4 including Supplements 1, 2, 3,

- and 4.

!"~ 9. Duke Power Company FPC Rate Schedule No. 130 including Supplements 1 and 2.

I Contract between Duke Power Company and the Southeastern Power Administra-

! tion,- Department of Interior, United States Government.

10. Letter Agreement between Duke Power Company and South Carolina Electric and Gas Company whereby Duke agrees to furnish up to 101 MW of standby power to

! ,- " South Carolina Electric and Gas Company beginning as of the commercial oper-ating date of South Carolina Electric and Gas Company's 611 MW 1973 generating i- unit addition and terminating aa of the installation date of a second unit of aimilar or larger size. South Carolina Electric & Gas Company's letter dated July 7,1970~; accepted by Duke as of July 9,1970.

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Question No. 9:

r List non-af filiated 3/ electric utility systems with peak loads smaller than applicant's which serve either at wholesale or at retail adjacent to areas served by applicant. Provide a geographic one line diagram of applicant's l,_ generation and transmission facilities (including sub-transmission), indicating i

the location of adjacent systems and as to such systems indicate (if available) their load, their annual load growth, their generating capacity, their largest thermal generating unit size, and their minimum reserve criteria.

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Answer:

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. Adjacent non-affiliated electric systems are tabulated on the following two pages. The approximate location of each system is shown by number (column 2 of tabulation) on the attached Duke Power Company transmission map (page 9-4).

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i 3/ Systems not in the same holding company system.

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4 ADJACENT NON-AFFILIATED SYSTEMS Ident. Annual Load G ener a t i ng Largest Thermal No. Lnad Hw Growthjf__ Capacity Mw Unit Mw Minimum Reserve Criteria Sout h Carolina E lec tr ic & Gas Company I 1,600 Unknown 1,863 38 .000 Unknown South Carolina Public Service Auttority 2 650 Unknown B60 160.000 Unknown Carolina Pcuer & Light Company 3 3.400 Unknown 3,240 700.000 Unknown yadkin, I ncor por at ed 4 195 Fixed Indust- 201 0 Supplied by Adjacent Utilities rial Load or by load reduction Nantahala Power & Light C&wpsny 5 Unknown unknown 2.245 0 Not available Lockhart Pouer Company 6 36.080 4.9 17.300 0 Depends on supplier Southeastern Power Adninistration 7 Unknown U nknown 544.000 0 Not available Heath Spr inqs Light & Power Company 8 1.620 4.5 0 0 Depends on suppIler The Electric Company 9 3.464 8.8 0 0 Depends on supplier City of Albenarle 10 27.648 7.8 0 0 Depends on supplier Town of Bostic 11 .600 Unknown 0 0 Depends on supplier Town of Cherryville 12 4.620 5.9 0 0 Depends on supplier Concord Board of Water & Lights 13 35.200 8.4 0 0 Depends on supplier Town of Cornelius 14  !.176 6.3 0 0 Depends on supplier Town of Dallas 15 4.260 8.5 0 0 Depends on supplier Town of Davidson 16 2.808 6.9 0 0 Depends on supplier Town of Drexel 17 1.648 7.7 0 0 Depends on supplier .

Town of Forest City 18 7.488 6.9 0 0 Depends on s upplier City of Gastonia 19 55.248 9.8 0 0 Depends on supoller Town of Granite Falls 20 3.744 8.9 0 0 Depends on supplier City of High Point 21 64.800 8.8 0 0 Depends on suppiler City of Huntersville 22 1.440 7.6 0 0 Depends on supplier City of Kings Kountain 23 9.630 8.0 0 0 Depends on supplier Town of Landis 24 4.080 6.9 0 0 Depends on supplier City of Lexington 25 40.662 8.1 0 0 Depends on supplier Town of Lincolnton 26 6.804 4.9 0 0 Depends on supplier Town of Maiden 27 5.220 11.3 0 0 Depends on suppIIer City of Monroc 28 31.752 12.9 0 0 Depends on supplier City of Morganton 29 23.220 10.0 0 0 Depends on supplier City of Newton 30 7.776 7.4 0 0 Depends on supplier Town of Pineville 31 1.968 9.1 0 0 Depends on supplier 9-2

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Page 2 ADJACENT NON-AFFILI ATED SYSTEMS l dent. Annual Load Generating Largest Thermal No. Load Mw Growth % Capacity Mw Unit Mw Minimum Reserve Criterla City of Shelby 32 22.122 6.2 0 0 Depends on supplier City of Statesville 33 45 360 7.6 0 0 Depends on supplier University of North Carolina 34 41.760 16.2 12 500 10.000 Depends on supplier

. Abbeville Water & Electricity 35 5.880 Unknown 3.924 1.192 Depends on supplier City of Clinton 36 13.329 12.9 0 0 Depends on supplier Town of Due West 37 1.296 6.4 0 0 Depends on supplier City of Easley 38 17.'495 8.1 0 0 Depende on suppIler Commissioners of Public Works, GafIney, SC 39 14.256 9.3 0 0 Depends on supplier Comissioners of Public Works, Greenwood, S C 40 24.200 11.2 0 0 Depends on supplier Comissioners of. Public Works, Greer, S C 41 15.200 5.2 0 0 Depends on suppIler Commissioners of Public Works, Laurens, S C 42 10.912 7.2 0 0 Depends on supplier City of Newberry 43 12.150 9.9 0 0 Depends on supplier Town of Prosperity 44 .960. 5.2 0 0 Depends on supplier City of Rock Hill 45 42.360 9.2 0 0 Depends on suppIler.

Town of Seneca . .

46 9.072 8.6 U 0 Depends on suppIler Comissioncrs of Public Works,. Westminster, S C 47 2.916 3.2 0 0 Depends on supplier Blue Ridge E.M.C. 48 7l.884 9.3 .175 0 Depends on supplier Crescent E.M.C. 49 44 606 10.6 9 0 Depends on supplier Davidson E.M.C. 50 27.566 10.7 0 0 Depends on suppIIer Haywood E.M.C. 51 3. 50 16.6 0 0 Depends on supplier Pee Dee E.M.C. 52 2.539 14.8 0 0 Depends on supplier Piedmont E.M.C. 53 10.924 10.8 0 0 Depends on supplier Ruther fordtor. E ,M.C. 54 48.580 12.9 0 0 Depends on suppIler Surry-Yadkin E.M.C. 55 19.440 9.1 0 0 Depends on supplier Union E.M.C. 56 31.426 8.8 0 0 Depends on supplier Blue Ridge Electric Cooperative 57 34.463 9.8 0 0 Depends on supplier Broad River Electric Cooperative 58 10.920 12.2 0 0 cepends on supplier Laurens Electric Cooperative 59 23.948 15.5 0 0 Depends on supplier Little River Electric Cooperative 60 8.805 17.9 0 0 Depen's on supplier York Electric Cooperatise 61 17.878 12.1 0 0 Depends on supplier Clemson University 62 11.520 9.5 0 0 Depends on supplier Notes:

1. Growth rates for Lockhart Power Company, Heath Springs Light & Power Company The Electric Company, Clemson University, Municipal Systems, Coop. Systems and Univ of N. C. based on deliveries f rom Duke Power Company. Loads for these same systems are also based on metered demands of Duke deliveries.

2. Loads, Generating Capacity and Largest Thermal Uni ts shown for SCE&G Co, SCPSA and CP&L Co are Duke estimates.

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Question No.10:

_ List separately those systems in Item 9 which purchase from applicant (a) all j bulk power supply and (b) systems which purchase partial bulk power supply

, requirements. Where information is available to applicant, identify those Item 9 systems purchasing part or all of their bulk power supply requirements

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from suppliers other than applicant.

Answer:

(1) Systems which purchase all bulk power supply from Duke Power Company:

The Electric Company City of Lexington Heath Springs Light & Power, Conpany Town of Lincolnton City of Albemarle Town of Maiden Town of Qierryville City of Monroe Concord Board of Water & Lights City of Newton Town of Cornelius Town of Pineville Town of Dallas City of Shelby Town of Davidson City of Statesville Town of Forest City Clemson University City of Gastonia City of Clinton Town of Granite Falls Town of Seneca City of Huntersville Commissioners of Public Works, i City of Kings Mountain Westminster, S. C.

Town of Landis Davidson E.M.C.

Surry-Yadkin E.M.C. Town of Due West Town of High Point

.,_ (2) Systems which purchase partial bulk power requirements:

i-Piedmont E.M.C. Town of Prosperity Lockhart Power Company City of Rock Hill S. C. Electric & Gas Company Blue Ridge E.M.C.

. Yadkin, Inc. Crescent E.M.C.

Town of Bos tic Haywood E.M.C.

Town of Drexel Pee Dee E.M.C.

City of Morganton Rutherfordton E.M.C.

University of North Carolina Union E.M.C.

Abbeville Water and Ilectricity Blue Ridge Electric Cooperative City of Easley Broad River Electric Cooperative Commissioners of Public Works, Laurens Electric Cooperative Gaffney, S. C. Little River Electric Cooperative Crmmissioners of Public Works, York Electric Cooperative l L. G reenwood, S. C. Commissioners of Public Works, Commissioners of Public Works, Laurens, S. C.

, Greer, S. C.

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All systems in tabulation (2) except Lockhart Power Company, SCE&G, and Yadkin, Inc. , purchase a part of their bulk power supply from SEPA. The Haywood, Pied-

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mont, and Pee Dee E.M.C's and the Broad River, Little River, and Blue Ridge Electric Coops also purchase a part of their requirements from suppliers other than SEPA and Duke Pouer. SCE&G, through reserve equalization with Duke, CP&L, and VEPCO and under a reserve exchange contract with SCPSA has purchased power at various times. Yadkin, Inc. , is interconnected with CP&L and has purchased from that company. CP&L, also through reserve equalization has purchased power j_

at various times. SCPSA purchases a part of its supply.

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Question No. 11:

State as to all power generated and sold by applicant the most recent average cost of bulk power supply experienced by applicant (a) at site of generating facilities, (b) at the delivery points from the primary transmission (back-bone) system, (c) at delivery points f rom the secondary transmission system, and (d) at delivery points from the distribution system, in terms of dollars per kilowatt per year, in mills per kilowatt-hour, and in both the kilowatt costs and kilowatt hour costs divided by the kilowatt hours. If wholesale

. sales are made at varying voltages, indicate average cost at each voltage.

Answer:

~

The informatic equested in Item 11 requires a fully distributed cost of service study, tch Duke Power Company has never made or had made for it.

). However , Duke .- er Company has such a cost of service study underway, being conducted by Commonwealth Services, Inc., an independent public utility con-salting firm. It is estimated that this study will be completed by the end of 1971. Duke Power Company is under orders to file the study with the North Caroline. Utilities Commission when it is completed.

Commonwealth Services, Inc., has made a cost allocation of the Company's cost of service between wholesale and retail customers, and the same is on file with the Company's application for a wholesale rate increase, now pending before the Federal Power Commission in Docket No. E-7557.

Duke Power Company's cost (as of December 31, 1969) of its generation and bulk transmission system is set forth in Duke Power Company Rate Schedule F.P.C. No. 10, Service Schedule C. Limited Term Power and Enerev. Appendix A; a copy of which is included as a continuation of the answer to Question No. 11.

4 a

11-1

p SERVICE SCHEDULE C LIMITED TERM POWER AND ENERGY

. Section 1 - Duration

}

1.1 This Service Schedule, a part of and under an agreement dated June 1,1961, , between Duke Power Company and Carolina Power & Light Company , shall become effective September 1, 1970, and shall continue in effect for an initial period ending April 30, 1973, and thereafter until terminated as provided for in Section 1. 2 below.

1. 2 Either party upon at least three years' prior written notice to the other party may terminate this schedule at the expiration of said initial period 6r thereafter.

Section 2 - Power and Energy Delivery 2.1 Either party by giving the other party notice may reserve electric power (herein called Limited Term Power) for yearly periods, or for shorter periods where the availability of Limited Term Power depends I

upon the in-service dates of new generating equipment or by mutual agree-ment, in such amounts and at such times as the other party may have and is -

willing to make available as Limited Term Power.

2. 2 If the party receiving the request for Limited Term Power does not have it available from its own resources, it may, if requested, arrange to purchase Limited Term Power from a third party for resale to the party making the request, under the terms specified in Section 3.

2. 3 To reserve Limited Term Power, the party desiring such power i

_y_ Question 11-2

shall specify in its notice to the other party the number of kilowatts and the period for which it desires to reserve such power. The party receiving such notice shall signify the amount and period of time it is willing to make I

such power available. All notices and acceptances shall be in writing and signed by officers of the companies, and these notices and acceptances shall constitute binding agreements between the parties under the terms of this service schedule.

2. 4 During the period that Limited Term Power has been contracted for as provided in Section 2,3 above, the party which agreed to supply such power shall deliver electric energy (herein called Limited Term Energy) to the other party upon call and in amounts up to the number of kilowatts con-tracted for. However, in the event of breakdown or other emergency condi-tions on the system of the supplying party resulting in loss of generating capacity in excess of 25% of the rated capacity of its largest generating unit, the supplying party may reduce the rate of delivery of such energy under that portion of Limited Term Power being made available from its own generation sources in the ratio Giat the total amount.of capacity so 1 cst bears to the rated capacity of its largest generating unit. The delivery of energy under that portion of Limited Term Power being made available from its own genera-tion sources may be discontinued when the largest generating unit (or the newest of such largest units if there are more than one of identical size) on the system of the supplying party is out of service for scheduled maintenance.

If a portion of the Limited Term Power contracted for hereunder is purchased by the supplying party from a third party for resale to the receiving party,

and that portion is interrupted or reduced by the third party under provisions 2 Question 11-3 l

[ similar to those outlined above, then the supplying party may interrupt or reduce its deliveries to the receiving company by like announts.

r--

l ,

2. 5 Subject to the provisions of Section 2. 4, the supplying party l[ will deliver Limited Term Power in accordance with schedules designated

, _ - by the receiving party.

2. 6 The losses associated with the transmission of capacity and energy under this agreement, either on the system of the rupplying party,

. or on the system of a third party which may be supplying Limited Term Power to the supplying party hereunder for resale to the receiving party, will be borne by the receiving party. Compensation for such losses will 4

be accomplished by scheduling coincidental delivery of loss compensation.

Section 3 - Rates and Characs 3.1 For capacity purchased from a third party by the supplying party for resale to the receiving party hereunder, the receiving party will pay the supplying party a rate per kilowatt equal to the rate per kilowatt paid to the third party by the supplying party. For capacity made available from the system of the supplying party, the purchasing party will pay the supplying party a rate per kilowatt equal to the Annual Demand Charge Rate calculated for the system of the supplying party in accordance with the formula set forth p in Appendix A to this Agreement. The Demand Charge Rate will be calculated I

D as of December 31, ?969, and December. 31 of each calendar year thereafter L

when Limited Term Power is being scld. The initial Demand Charge Rate shall be effective during 1970, and thereafter the Demand Charge Rate for i

each calendar year shall become effective as of January 1, subject to recalcu-3 Question 11-4

lation in 1970 and subsequent years upon the occurrence of any of the follow-ing incidents (such recalculation to be made as of the date of each incident, j

except that initial billing may be on an estimated basis subject to adjustment

'r

when final accounting becomes available):

i

. (a) A new generating unit is placed in service or an existing unit is retired on the system of the supplying party; (b) A new transmission facility of sufficient size as to affect the Annual Demand Charge rate is placed in service on the system of the supplying party; (c) A change occurs in the status of a transmission facility on the system of the supplying party which would affect the Annual Demand Charge rate; or (d) A new issue of bonds or preferred stock is made, or an outstanding issue of bonds or preferred stock is retired i

on the system of the supplying party.

It is intended that changes in (a) above involving major units will be made effective as of the first day of commercial operation of the unit involved.

Changes involving internal combustion turbine generators or small steam or hydro units of 25,000 KW cr less may, at the option of the owning party be made effective as of the first of the month next following the date of commercial operntion or the date of retirement, for purposes of calculating Annual Demand

.*e Charge rates hereunder. Payment for capacity shall begin with the initial date of the period of delivery and shall contmue until the terminal date of such period of delivery, without any adjustment for periods when +he delivery of energy is interrupted as provided in Section 2. 4 above.

1 4 Question 11-5

3. 2 When energy delivered hereunder is generated on the system

- of the supplying party, the receiving party will pay for such energy at a rate per kilowatt-hour calculated as follows:

(a) For the 12-month period ending April 30,1971, and for periods subsequent to April 30, 1973, the calculated average production cost (including operating and maintenance costs) of the energy produced by all plants on the system of the supplying party for the month in which the delivery is being billed, plus 10% of such average cost.

(b) For the periods from May 1,1971, through April 30, 1973, two rates as follows: (i) the calculated average production cost (including operation and maintenance costs) of the energy produced by those I-C turbine generators scheduled for 1971 installation which have been installed and made available for use hereunder on the system of the supplying party, plus 109 thereof,

, and (ii) the calculated average production cost (including operating i

! and maintenance costs) of the energy produced by all other units on the system of the supplying party, plus 10%, for the month in

which the delivery is being billed. The amount of energy to be billed under (i) above will be the amount of energy gener'ated on the I-C turbine generators in (i) as a result of the delivery of Limited Term Energy hereunder. The amount of energy to be billed under (ii) above will be the excess, if any, of total

Limited Term Energy delivered during the month over the amount l

l -

3 Question 11-6

I F.

j billed in (1) above. Billing each month will be on an

~

estimated basis, subject to adjustment when all production

[!

costs for the billing month are available. If a party is selling

~

! . Limited Term Power to more than one company at the same

~

time, the amount of energy to be billed under (i) will be pro-rated between the purchasers of such energy in the ratio of the r-

'li amounis of Limited Term Energy delivered to each during the

[ time in which the proration is being made.

When energy delivered hereunder is purchased from a

I_

l third party by the supplying party for resale to the receiving party, the receiving party will pay the supplying party at a rate equal to the cost of such energy per kilowatt-hour plus 10%

ll 4

3. 3 Where applicable, taxes will be added to billings under Sections 3.1 and 3. 2, including but not limited to:

l Support of South Carolina Public Service Commission Sales Tax or Energy Gross Receipts Taxes

i

'~

Sales Tax or Use Tax or Fuel South Carolina Generation Tax Any new or additional applicable taxes imposed after the date of this Service Schedule shall be included in billings hereunder.

9 e

6 Question 11-7

k .~

APPENDIX A GENERAL EXPLANATION OF DETERMINATION OF CAPACITY CHARGES

~

AND ENERGY CHARGES-LIMITED TERM POWER SERVICE SCHEDULE The selling company will invoice the buying company for capacity and energy used on

_ . or before the tenth day of the month, payable by the twentieth day of the month, for capacity and energy used in the preceding month. Cost will be estimated if not known and adjusted at a later date. The charges will be calculated as follows:

A. Capacity (Fixed) Charge Calculation:

1. The monthly demand charge is the sum of one-twelfth of the annual production

r capacity "Earge and the annual transmission capacity charge.

2. The annual capacity charges will be calculated always as of the previous year

_ end and recomputed during year whenever either a generating unit is placed

]. in service or retired, or transmission facidty of sufficient size as to affect

' the annual demand charge rate, is placed in service or retired, or whenever 7

there is a new issue or retirement of long-term debt or capital stock. The annual capacity charges will be recomputed the first of the subsequent month lI of such incident, except in the case of a generating unit above 25,000 KW which shall require recomputation as of the date of such incident. At the time of any recomputation, the annual capacity charge rate shall be adjusted to reflect all additions and retirements of bulk transmission facilities, since the last previous computation.

t'~ 3. The met..od of computing the annual production capacity charge per KW is to divide the sum of the production annual fixed charges, including return on investment, depreciation, income taxes, property ano other taxes related to plant investment, and insurance, by the sum of all production plant capability, 9 stated in KW, under the most adverse operating conditions (Major nlants-

, FPC Form 1, pages 432 and 433, line 10, and small plants per company records).

3 4. The same procedure is used for computing the annual transmission capacity charge except that transmission O & M expensc is included as a fixed charge

? and all transmission amounts are adjusted to eliminate (1) costs not associated L with bulk transmission and (2) transmission investment currently being shared by former CARVA Pool members under termination agreement. Long-term firm purchase of KW capacity will be added to production capability determined under A. 3 above, to arrive at transmission charge per KW.

5. The annual fixed charges are computed or determined as follows:

5.1 Return on Investment This item of annual fixed charge is computed by multiplying the total functional (Prod. & Trans. ) investment by the latest embedded weighted composite cost of capital.

Question 11-8

A. 5. (cont) 5,1.1. Investment -

Investment consists of book plant balances in accounts 101-106 less accumulated depreciation (accounts 108-110) plus net

-- nuclear fuel investment in plant account 120 and allocated por-tions of normal working capital, consisting of

(a) Minimum bank balances in account 131.

(b) 60 Day production fuel supply in account 151.

(c) Other materials in accounts 154 and 163.

(d) 1/8 of all operating expenses for one year, except purchased power (accounts 500-557 less 555) for production and accounts 560-573 for transmission

.r with both functions also being allocated a portion of 3 A & G expense accounts 920-932).

(e) Federal income tax offset, consisting of an agreed r percentage of the annual Federal provision in account

! 409, is deducted from other working capital item.

5.1. 2.

~

Composite Cost of Capital Three costs of capital are computed: for long-term debt, preferred stock and common equity; and are weighted on F basis of capitalization ratios, and summed to arrive at

l composite cost of capital. For bonds and preferred stock, weighted annual net cost to company is computed through J' most recent issue or retirement. For common equity, the l sum of net earnings for common (excluding extraordinary items) for last three calendar years is divided by the sum of the daily weighted average common equity outstanding for the same three year period.

5. 2 Depreciation - FPC Account 403

]L Depreciation will be calculated using depreciable plant balances (including a portion of general plant), and annual depreciation rates.

When a production plant or transmission facility is added or retired, i

depreciation will be recomputed to account for the change.

5. 3 Income Taxes The income tax fixed annual charge is computed rather than alltcating actual book amounts. The computation begins with the return on

, investment amount (Para. 5.1 above), deducts the tax deductible i-interest portion and, using the current composite Federal-State tax

, rate and making adjustments for differences between book and tax depr ecia t ion, computes what the income tax would be, aseuming the p . return on inve s ment previously computed.

. 5. 4 Property and Other Taxes Related to Flant Investment-FPC Account 408 Taxes directly assignable to production plant are identified and remaining plant taxes are allocated on basis of gross book plant (accounts 10f-106) with the general plant allocated portion further allocated to remaining functions on same basis.

-2 Question 11-9

,7

I

'I A. 5 (Continued)

,p- 5. 5 Insurance - FPC Account 924 ll Total insurance expense is assigned directly where possible with the balance allocated on basis of plant investment.

r ll S. 6 Transmission O & M Expense This item is used only in computing the transmission capacity charge and consists of the last annual transmission O & M expense (accounts

< 560-573) increased by a percentage for A & G expense and payroll taxes and reduced by the portion applicable to non-bulk transmission

~

plant.

.s

6. The resulting production and transmission capacity rates per KW are

'~

multipiled by contracted KW to calculate the capacity charges for the month.

B. Energy Charge Calculation

1. The monthly energy charge is based on the actual production cost per

! net KWH of the selling company for the month in which the energy is sold.

~

2 The following costs will be used to calculate the energy charge rate:

a. FPC accounts 500-557 excluding purchased power (account 555).

ir-

~l i: b. An allocated portion of Administrative & General expense (excluding insurance) and payroll taxes.

I 3. The KWH net generation will be the net generation for all production plants with exceptions noted in the contract.

J' 41 - 4 The monthly production cost, as stated in 2 above, will be divided by the KWH net generation as stated in 3 above. To the results will be added the

]

.t 10% specified in the agreement.

5. The resulting rate per KWH, as calculated in 4 above, will be multiplied by the KWHrs of energy delivered by the selling company to calculate the L total energy charge for the month.

C. Applicable Taxes Applicable taxes not provided for elsewhere, in the capacity charge calculation or the energy charge calculation, will be included in the bill by the selling company.

I i

L Question 11-10

9 LIMITED TERM POWER SERVICE SCHEDULE I bo h Pmoee Selting Company Buying Company Month of

~ ~ ~~ ' ~ ~ ~ ' ~

Lina Account llumbers Ns. , Reference Total

~-

telling Co , Buying Co ,

(1) (2) (3) (4) (5) (6)

CAPACITY CRARCES:

Production:

1 KW 2 Cost /KW (Sch.II) 3 Cost (1 x 2) i 4 Applicable taxas (Note A) f~5 Total Production ( 3 + 4) H 447 555.1 Transmission:

r 6 KW k7 Cost /KW (Sch.II) r 8 Cost (6 x 7) 9 Applicable taxes (Note B) 10 Total Transmission ( 8 + 9) $ 454 567

[ 11 Total Capacity Charge ( 5 + 10) n ENERGY CHARCE

KWH 191d'

. [ 12 i 13 Cost /Kwh (Sch.trI

, 14 Cost (12 x 13)

' 15 Applicable taxes (Note C) 16 Total Energy (14 + 15) 3 447 555.1 L

17 Total Invoice 11 + 16) $

fote: Reference and explain taxes on lines.4, 9, 15 below:

l i

Question 11-11

LIMITED TERM POWER SERVICE SCHEDULE II I> uke Po,o en Company CALCULATION OF FIXED CHARGES as of /2s- 3 / -lf

. _ . _ . . _ _ _ _ Prndnetfnn _ Tra n< tmi n e i nn

.ine l

30 .

Re ferenc e_ _ Arno_Unt Reference Amount (1) (2) (3) , (4) 1 Return on investment l A 30 0o2 F4b A g fj f,,97, o34 l

1  !

2 Depreciation B 17 947 74l B g gif 444

_ . _ . . .. _ _ . . _ - _ _ _. ) i _ _  !

Income taxes ' f f 99T 9D 3 C C l7495195 i

4 Property taxes j D 4 f.40 o2.5 D f 9gg f,go 5 Insurance E E

,  ; jggg g I

6 Operating and maintenance expense F 5 49/ ifo I i .

1 '

I 7  ; Annual fixed charges 7/ 77f /.24 32 /7f /d 8 Net continuous plant capab Llity - KW G 8 NI' i 'G 8 i38 M Capacity charge /KW ye ar l' l 9 (line 7 + 8) /2. 4 4/o _ l

/

8;1207 I 1 10 Monthly capacity char ge/KW (Lin 9 + 12) Las/2 . MS'/7 3

l i l

I I

..}__ _ - -

. .- .._.l-._.__._.._ ..._ _.. _ . . . _ _ _ - .

t l  !

Questfor '11-12 1

~

LIMITED TERM POWER SERVICE SCHEDULE III Du hs_ mev Comp [ny

~

ENERGY CHARGE fina FPC I Month of

_ No. _ __

Reference Tau mo *

(1)

Steam

_ 1 . Operation (500-507,exclud Lng fuel) p.417,11ne 12 g',g,j pg 2 Maintenance (510-514) -

p.417,11ne 19 ANf3, Nuclear 3 Operation (517-525,exclud Lng fuel) p.417,11ne 32 -o-'

4 Maintenance (528-532) p.417,line 39 -o-Hydraulic 5 Opers: tion (535-540) p.417,11ne 49 ///a 'U/

6 Maintenance (541-545) p.418,11ne 5 g'fo~o r

l l-Other Power p,7 Operation (546-550, Excluding fuel) p.418,line 14 J. 4 72, i 8 Maintenance (551-554) p.418,line 20 l . __ ,J Qf i Other Power Supply Expense (Excluding Purchased Power) 9 Systen control and load disp. p.418,11ne 24 _ a _.

Other expens.es 10 ,

p.418,11ne 25 .- o_

11 Total (Lines 1 thru 10) / ddT(7fip 12 Add.3 7 lE7. Line 11(See Sch.IIIa) ,- 4NS 7.3.

Fuel -

13 Steam 79?c od,*/

l l"- 14 Nuclear o- 3

,r 15 Other / da44f9 '

h 16 Total (Lines 11 thru 15) M 4f4 /33 l

I. t l 17 h ,

) .4 3 ' . '. ine '9 3 /7[d21 l 31 Net Generation 18 roduction Cost per Net IMH (line 16 + 17 ) *Do3Md/M-19 /.dd 107. (1107. of line 18 ) ggg7g,

• Exclude claims all cost from . is schedule which can reasonably be expected to be rec eived as

~

frominsurancecompaniesanjvendors. l l Question 11-13 '

p.___

.._q 7 . . _ _ . , - - , ., __

.)

LIMITED TERM POWER SERVICE SCIIEDULE IIIa D,3 Mr. ko,a c. e Company Calculation of Allocation Percent for A & C Expense, Payroll Taxes, etc.

Calendar Year 17/,7 u ~----. - - - ~ , .

~~

_Np% _ _ . n o r. r o n,. .

(1) 1 Adm. and Cen. Expense Page 419 Line 53 k Less Insurance

/51F/M Page 419 Line 42

( A/SAr$

3 Add All Fed. & State Payro .1 Taxes Page 352 / g,3 foM

_4___ _ Total A & C and PR Taxej  :

1 /4 72S7Jb 5 Total 0 6 M Expense Page 419 Line 54 jgg ggf Less:

Fuels Excludedy I

6 Steam - Acc.t. 501 Page 41 r, Line 5

..if6 0/o M 7 Nuclear - Acc t. 318 Page 41 r, Line 24 8 Other - Act t. 547

(-o-)

Page 413, Line 10 (4/A.d5M) 9 A & C Expense (Line 1 above)

(/fggfff9) 10 Purchased Power Page 418 Line 23 (ffj2 g g) 11 Balance O & M (Line 5 less 6 - 10)

Wpay

12. Allocation Percent (Line 4; Line 11) y/.1.ff, Questio i 11-14

- ^

.* A LIMITED TERM POWER SERVICE SC11EDULE D ol< r o ut

• y- COMPANY Return on Investment as of J Z- Sl. /,9 1 -Pfbddbtion .

- Transmiss i on - -- - - --- - -- - ' - - -

go- Reference I Amount i

v. 4- . - .m . .,

. _ . . - .. . . .. _ . ... .s-,_--_--

Reference Amount m- . . . , m_ . _ _ _ _ _ . --

Sch. Line Col. (1) Sch. Line Col. (2)

Cross Plant in Service:

1 Electric A-1 6 5 STr/JLf9476 A-3 7 2 JoJ 4 22/u f 2 Electric-Nuc. fuel-net A-7 4 5 - o -- _a_ ,

3 Less: Accum. depr. A-1 17 5 (229/Ma27l A-3 15 2 (R,ri/ 3oo )

4 Net plant in service dOdsfd47

/ /4'75.50 % 7 a.

Materials and Supplies: -

5 Non - Fuel A-4 21 4 AI 597 A-4 1 23 2 f4274a5' 6 Fuel A-5 30 2 /4 /[ou/ Working Capital:

~

7 Minimum bank balance A-6 3 2 //974 /9/ A-6 5 3 /727f,F'T 8 1/8 Oper. expense A-6 15 2 /J 91/ io.i A-6 17 3 6 41# @

9 Fed. Inc. tax offset A-6 20 2 ( / <TI//.2O A-6 22 3 ( 47/odf6 )

LO Total Investment 394 74[o7/ ffagflfo -

il Composite cost of cap. A-8 4 5 ,MM . A-8 4 5 __.

7 55,I

~

12 Return on Investment (11 times 1 0) 3 44d % //49Eg

~ Question 11-15 a

__q

)

q j T.IMITED TERM POWER SERVICE SCHFJULE '

1 .

Dot <e powa v - A-1 Company Cost of Plent trid Accumuisted Depreciation As of l A 6 9 i.

Balancn @ppral-Rlartt_

Line .

FPC 1 as of dubsequent  ;

D. . Revised Allocation l'es c r_ip tiop Total 7. of Total Pag @,[2/3 d7"T.aPS ActiWJ 41aRCC -'SAh.-A-1).- (1) (111/43 s= Cola =

Cost of Plant (Acets. 101-106) (1) (2) (3) (4) (5) (6) 1 Production: Steam 401 t#/frJ6ove/ ## VJ/o /

2 Nuclear 401 3 Hydro '

401 fo/ yygkrj /s/ 745'gkr7 4 Internal Comt

, . 402 41 %t9 2}f' .11229 935 5

6 Total Produetion ,, 402 f7/gf4i.13 f//fy422 3 /y #2/073, 7 Transmission fp/,Jfitf. f gf'.f77.

402 2 /,gf4' (,M' #6f744fi5r J ffr4 7vg 8 Distribution ~ A47754Df j g. gy 403 ftpr/jg /g f fl,ry49/J/ /t 2d42/ f374727J1 Jglp7

/9 Ceneral, Com., Intang. (Sch. A-24 J7_574I'27 37J7d Df /1?O'4 73E _g_ 10 TOTAL (6 - 9) / 42.14Pkdu? / 44J/frN*e7 /4.2 Y 4f//ou 7 100 00 t i

j i ACCUMULATED DEPRECIATION (Acets. 108, 109, 110) 11 Production: Steam 408 /f37 Ey /717h.iTy 12 Nuclear 408 13 Hydro-Convent tonal 408 4 (A'1 1 T7$

//oJ52 F74 14 Hydro-Pomp. S 408 tor. '

15 Internal Comb 408 /ypi[6L7 /#hW,7 16 17 Total Production 408 2Afd43d77 MSN#77 J37kW F' JZJL1/fI(427 -

18 Transmission 408 */3./hJ27 19 Distribution 7.1169C/ 946"/73 74 /3 o/o -

408 fqJJ1f'og/ //fg/goff '

97799gg fqggyoof7 .

20 General, Conanon, etc. (Sch.A-2) 9yyjapf 9f9).v77 (7h 677) -

3 21 TorAT. (17 50) 494fgM 1./C/49ad __ 40/14/ofu Question 11-16

A-2 LIMITED TERM POWER SERVICE SCHEDU12 Oake hnus e 2 Company General, comon, Intangible Ilant Allocation f-

• • Of

_ '_2 - 2 l'_b 9 .

l

_ _ _ _ _ _All l Page. Description Reference Total ?roduction Transmissiori Other (1) (2) (3) (4)

I Plant FPC 1 J. General Plant P.403 2#S//.f_t2 Comon plant (elec. portion? P.351B -- d -

3 Intangible plant (elec. portion) P.401 Total (Ins. 1-3) 375/4 Pat 5 Allocate on basis of

~'

Line 19 belou 37 S/4 f32 /$$2/471 2 ff4 *Md /9. tofts I Depreciation Reserve FPC 1 General P.408 9 322cf7 '

7 ' Comon P.351B -O-l Total (Ins. 6-7) 9 324 tJ7

'4 Allocate on basis of j . Line 19 below T32.4Q?? 258l$48 944 /23 4 ?7d964

Non-Depreciable or Clearing f Account Depreciable Plant FPC 1 0 Auto and trucks P.403 g.jg p9j Other Gen.Non-Depr. P.403 2 g,2 y(,g 2 Comon Non-Depr. P351B -o-Other, if any /Lcpp7f 4 Total (las. 10-13) 7498237 Allocate on basis of

(, l Line 19 below 7 NS 237 199232% 7742/7* 3 R29o' 99 _

l u

l.

L  !

f Allocation Basis-Electric O&M FPC 1 Salaries Other Than A&c P355 Ln.25 Ln. 19 Ln. 20 25-(19&20) i6 . Total O b M Salaries 3 jog _gy_o) jo32ayd 279zdjy zg_ffo M Less A 6 G (FPC 1, P355, Ln.24) 7232#E4 @ --O- 7 232 MO I

1 h- ' '

Balance 24 2 5~/2/ 7 Jo.32c 2%l 21/2 J/? /3 7d2504 i

l 7. o f Tot a l - Ln 18 100.00*/. 3 f . 4,l/ 7. /o.32 7 5/.20 7.

I

!*UseonScheduleB, Col.:!, Lines 7 And 10.

l C.ueetion 11- 17

i r- _.....-._.l 1

A-3 LIMITED TERM POWER SERVICE SCHEDULE i

Ot> ld < ho w e_V Company

_ Transmission Plant

___ _As_J2f_ =

17 M.-._--

Lino Description (1) (2)

Plant Investment .

e

~1 Balance (Sch. A1, Ln. , Col.5) .94975 09 2 Less Non-bulk Transmission Plant (84 7.) 4.t h[o ff44

, 3 Bulk Transmission (Ln. 1._- Ln. 2) _

JdIIp1[73I 4 l Plant currently beir,.g shared by former CAIl.VA_,

t Pool members under termir ation agre ment i

t (attach listing as A-3-a)

• 4,4 74 4t49 5 Former members' applicable percent Il 7.

.. 6 Less former members ' portic n (Ln.4 x Ln.5) / MdN/,

'7 Gross bulk Transmission Ple nt (Ln .3-Lrt.6) ,203dh2AJ9 F

L . 8*

Bulk Transmission 7. (Ln.7 + Ln.1)(XX.>7.) 7dg y, t

i Depreciation Reserve 9 Balaace from Sch. Apl, Ln. 18, Col.5 7u /3L'o/o

.0 Less Non-bulk Transmission Reserve ( 2d. 7.) ,

/7 79.1 hn 11 Bulk Transmiss ion (Ln.9 - I n.10) G Su3 kl.ff' 2 Accumulated Reserve applicc ble to Investment on Ln.4 above (Sch. A-3-a) /#/uu 1,

3 Former members ' applicable percent 4/ 7.

'14 ,Less-Former members' portic a (Ln.12 x Ln.13) 7A osf t5 T Bulk Depreciation Reserve (Ln. 11 - Lrt. 14) _f7,4 7 dC 6

._ L_ _ . _ . _ _ _ _

Question :.1-18 l

A-3-n 1

Limited Term Service Schedule

[~ Duke Power Company l Transmission Plant r-

-l Plant Currently Being Shared by Former

_;ool Members Under Termination Agreement

. r-k Autocransformer bank breaker - Wateree $ 25,449 r-Autotransformer - Dan River 288,646 Autotransformer - Davidson River 145,131 Autotransformer - Newberry 252,288 Eno to Roxboro 568,110

, Skyland to Hendersonville 1,000,025

,j

'l $2,279,649 I~

)

Accumulated Reserve Applicable to Above Plant Investment il

- Autotransformer bank breaker - Wateree $ 2,038 Autotransformer - Dan River 22,341 Autotransformer - Davidson River 10,145 Autotransformer - Newberry 15.137 Eno to Roxboro 26,880 Skyland to Hendersonville 41,603

$ 118,144 t.

.I

'l 6

t l

t t-Question 11-19

LIMITED TERM POWER SERVICE SCIIEDULE , A-4 Duke Pa m , # Comp ny Materints cnd Supplies (Excluding Fuel)

Date 12. 4'7 Line Warehouse Location or kelerence cc ' I ~ ~ ~ ~ ~ ~ ~ ~ ~ " "~

No. (11ocation Productioni

~ T Class of Mat _erial Transmissic a Other

% .-- -.--- - . - . - -. . . _ - - Total - . . _m .

(1) (2) (3) (4)

I '

$ 1 / B es L e~ ff  ; otyTrI[iwo 2,56[,'f*>

2 Li a , L,u s, s 93., + m l  ; 353 61N Id3.M 3 }yons.cagr<kov,e e, e l sQl g l 4 __ Cey[s ] M Se..[f a %.[a>] . _,____.;_ _ _ _.,_3 . __,, , _,[fjf,_Y)). _ _ _ _ _ _ _ _ _ _ _ j_79)fjf,,___ __ 'f_sL7tisk . - . . .

5 6 Mig f)/,q,f7j- f*/J3 N/- /! 5 735217 6  ;//yhp fpph gg l S.9$tc7 7 I6' If #U 8

1 l 44 17 /3 $ /3 ! f 47Ek(' l

.f o ( ,:t $~b y .

l l li.jh75 - /u(l16 PA.'<j*1l l 9- 4 *A?r". d-.IH12'11 . _$Ahba

• l _ 222]L4 10

• Pu\s 4 Cyv N j '7 /4 6 j 35y h3  !

,r4 ff.2_

I, l 36bhf/

in i  !

g . .

12  !  !

I j

13 i

• l u

1 I I 14

.r_.__._.- .

,_ _ j_ _

15 , j ,

16 Tota 1 Account 154 fFPCP207 ' [*.15" f70 7 #/[f'7/ $ 7// N f /7 /44 4 #

I 17 Merchandise - Acct. 155 FPC P207

/3.z o pf( f py.7f I3 Total (16 + 17) ' b#3bE7# 70/ Y// 783I N3

@.) 382.'t1y 3 's of Total - Line 18 l g, 3 4, 7. ._

J 2.q L 7.I 3 y.h 7 7. 100.007, 2 '. Stores Expense (163) ,( Line 19) l /9q 7of ,1;rf, he ' ~

.J6f fil ! d$4 Ro l '. ~otal (18 + 20) l 4.]$0'C] Q t I /Gul bb] fq-1-j $4q l .))94(({t) ii hlk Transmission  !

7(.[7. I t(A-3) i i a 1

1; blk Transmission i fB4)i g i s

l

. 1.

4 , .

j  ! . + l

' . l Question I L-20

-p - -. - - , _ _ _ . - , _

I LIMuc.d TEnn P0h.2ERhu SClu.uutE 3 __l '

' A-d.. . __ I Duk< Pau,. < Comp:ny .

Materials and Supplies (Excluding Fuel)

Date 12_ - $ l - (,9 Warehouse Location or

-- ~

~

Inc Reference cs:

- ~~

[

10.- . . . . C. lass of Materiala (11ocation ProductionI Transmi:: sic n Other Total

-a y~__ _.-_.,.- __ , . . - - - - -

(1) (2) (3) (4) e 1 %L/ AsG fj .

dtSTri9." 9o 2,5Bl.?*

2 Lia.,t,,us,s 93., + m : l  :

A53 6t1l 2&I 3

3as.s w a.n bu .< s e j dicthi ,

qs't eq/!

4 _ Ces[ni fuhse.f4o 'd?iau - _. . . 2 - ... . t .- - ES14 Y'L - - - - - - 21919 5 - 9A9tiML- -

5 Shty p/an7s f735b7l l 5 735N7 6 * //y/ro / VMfi hj)s7 l \ l M0 '*7 7 lV kS c /93 '

i 451 Af }3 ll3 l 472bW l 8 fo( 4 yb L.,_ j l hl 75~~ /" bb .

9 .. .

SMr .1-_7MfB.5/ ____ -

.h . _- _ _ _ . - -. N 'O' -- E 10 5 94 ads 4 bru M l , 7M6l 354iD .I4 f5M l N fl I

ll l2 I L3 i l -

I l

14 . - . . _ . - _ . _ _ _ _ _ . . _ . -

._.- g 15 j l

'6 Total Account 154 FPC P207 lI /* 1.[87c7 7#' I'7/ di//W I /i 7/ddI7 l

.7 Merchandise - Acct. 155 FPC P207 /32[J7[ /132[J7f'

• t8 To t ,.1 (16 + 17) ti 6d) @ d , ,

70/ 67/ .

4L3J D 3 p.) .182 T1y

.9 7. of Tota 1 - Line 18 l ,,2 T. 3 L 7.  !

32 9(,7. 100.007,

~ J Ts. W 7.

!O Stores Expense (163) (Line 19) i /90 7of ,121, N9o J ClI dft flo Tota 1 (18 + 20) l S.330 ff 9 784/Ifd/ ft/97 Ny JIJ949NLJ

!2 7. Bulk Transmission (A-3) , i 7(-[1 8

'3 Bulk Transmission I '

[/Jd41.I' f l

_.1 l _ _ .

{ i .

7._ . _ . _ . . - . - - - - . - _ . 4 l l 9  ; l l Question 11-21 l

LIMITED TERM POWER SERVICE SCHEDULE A-5 D o ke Pou) e A Company '

Fuel S tock As of / Z- 3/-49

.- Fuel 60-Day '

Line l Description Supply Amount  !

l~

Steam Plan *3 - Name: (1) (2)  !

I 1* Mhes hn// (s7t czo m2 A //ed 54,9 f,4o 3

N ee /SD 24 C / l

.., :. dad Auvee //f 420

C/o ffside 74, zoo R,veebead 24I 390 8 ve k /77 48o

' ~

No c r=

S u z- 2 np2 Roas h

_  ? 800

,0 il Total - Tons Coal 2,o/7 ddD 42 ,

Average System Price ($ on)* M 7. d f Amount - Coal (Ln.11 x Ln. 12) jf Jg3 dfg

. Normal Oil Supply (Bbls) 4 t

Total Bbls. Oil - Steam Plants is AverageSystemPrice($[Bb1) *

)

Amount - Oil - Steam Plants (17 x L8) -o-Other Production: (Use Storage Capac .ty)

' Lee /f ff/

dad 0 Je9 24 /?o

2 h.Vethead / 00 oCC Ur*G u h at h ,2/ 429 m.

I Total - Bbis. Oil - Other Prod. j g gg Average System Price ($!Bb1)* 8 4, g /

Amount - Oil - Oth. Production (27x 28) 7/4 (,yf 1 Total Fuel Stock (Ln:;. 13 + 19 + 29) /4/foad

>lse year-end average for calendar year studies or previous month'saveragewhenl revised for addition of m w generat ng unit.

l l Question 1 -22

'A-6 f.iMITED TERM POWER SERVICE SCHEDULE __,_

buke swe V Company Working Capita 1 12 - 3 1- 69, Year n I ina Descriptior Total Production Transmissicn Other (1) (2) (3) (4) 1 ' Minimum Bank Balances:

I2idEl* 400 , . ,

f

~

Allocation 7. (A1, Col.6) 100.00% /,4p . / y' % / ?.1,5"~ 7. 37.(7 1 Allocated amounts (Ln.2 x Total) f7 goi go A 974 /1/ MW1/7 4 977M /

'7$ N 4 Bulk Trans .7. (A3, Ln. 8) '

' l g Bulk Trans. Amount (Ln.3 x Ln.4) -

/72fkff l

'l /8 Annual Operating Expens 3 .

> Production-FPC 1, page 41 3, Ln.27) 2/ 7 /fb/2.1 // 7 Ed 'tJ'1/ r Transmission.FPC 1.P. 418, Ln.47) G2d 757 C9N37 k Distribution,FPC 1, P.419 , Ln.18 /a/M*f// /e#/301//

Cuctomer Accounts, FPC 1,  ?. 419,Ln.2 5) 470[747 47N 747 u- Sales FPC 1 P.419, Ln.35 379Mo7a 37f7u7a

A&G FPC 1, ?'.419, Ln.5 1 ,

Allocated on basis of A2 , Ln.18 /CP'/ fM l'7N3#/ 7 / fT$11t4 7Pauh7B Total O&M,FPC 1, P. 41), Ln.54 //,2 ady70 /23 cro s/P 4 RB/ 9r/ 31 #6/ 626 Less purchased power, P.4'18, Ln.23 ( // /.2f/9)J ( // /J7'/9,:L). I j Totals (Ln.12 - Ln.1 3) N/ J7) /d3 //)#N62d 4 ??lTs / l 32.4M E2./,

1/8 of Line 14 totals /3 97'/ 733 E'6odav d c67/4/

l Bulk Trans.7. (A3, Ln.8) N#7 6

ga9'/Jg2A l Bulk Trans. Amount Federal Income Tax Of fset:

i i Provision for Current Fed Electric Income Tax (FPC 1, p. 114, Ln. 12) 4571'K KJ-. -

Percent Of fset * #%

j Offset Amount (Ln.16 x Ln .17) f77[3# .

• Allocation 7. (A1, Col.6) 100.007. Q./p 7. / 9. 9[ 7. 37.9'7 7 Allocated Amounts (Ln.19 c Total) 8 77[ 3'/7 / G ///.'L 7/N1 u. /55Uv 7_ l

~

Bulk Trans.7. (A-3, Ln.8) *7C[7, Bulk Trans. Amount (Ln.20 c Ln.21) , _6JdM/. ,

I i

l Of fset 7. will vary as og ecd upon.

__ .. L l 0uestion 11- 23

7

- ae A gc an ra el 4 2

va AB 1 L

n o

i 9 t e t. s c/ e n1 u a3 l/

Q a2 B1 y

n a

p s n

m o o i C c E )c L 1 u U (a D e E d p H a C t S as m n E l i o C e t i I u s t V F E t R o E

S n r a

o n

e e R l E w c Wo u OP P

N M

R E

e n

T k u u 3 n

D n ED 9 k T

I 1 f M 8-

"/

r e

I 3_ a L

H-

" 2 s

/ e t

a

. g i

f d

n e

r

) a y

4, y 3, n t

n r 2 o e e i

m t 0 t t f 2 a s a 1

(

z e i v e t t n t t r n i m n o e m e m m t i m A t e t s

t s n e s d e e e v e v t n g t n a I a n

. I l r u u t e i s m e v d s u N A A o c r c )

C A 1

(

e.

ro iN I 2 3 4

_ L . .

LIMITED TERM POWER SERVICE SCllEDULE A-8 Du k e P,w e v Company Composite Cost of Capital As of )'t.- % L 9 Lins No. Descript_fon Capitalization Colst of Capit .

PsW l

al Cost as of d 49 7.

Amount 7. Total Reference 1 (2) x (4)

(1) (2) (3) (4) (5) 1 Long-Term Debt df3/jddd 6.d y A-8-1 Line 20, Col. 7 f./g7 2 Preferred Stock 4 .fl 7.

/gfded @ /1.. g4 A-8-2 Line 11, Col. 7 f .*vgy . pg'

~

3 Common Equity 39/, /Pf&42, 32. .'af" A-8-2 Line 16, Col. 7 L*L.4a 1 3.h7 4 TOTAL

/ 44fd 100.00 7. -

7 2d7.

I I Question %1-25

_y

_. q LIMITED TERM P y SERUICE SCHEDULE A-8-1 Du Ite. rne ea9 Company Cost of Debt Capital as of }Z- 3/-4 9 Debt. Dis c . _

Line , principal & Exp. or Net Coupon Series Net Cost Outstandin t Annual

_No . Issued Prem.-Net Proceeds Rate to Company as of Cost M LL} M Q4 tJ} LD) ti}

1 1)x(4)+(3) '(6) x (5)

First and Refiinding Mortgage Bonds:

1 3 7. Jee,es doe j-/.7f go em 39'P2o4o? 3.ooo 3. ooG. Yooooem / *o* 4m 2 L G S**7o 6eenes <l ue 9- /- 77 do ocoooo 39 9stS-@7 2 45b 2.45C 40 ococee / C62 om 3 L h% beeoes &ve 2 - /- 7'? 40owmo 40 /df9ff X*$7S L [4C 'lo &OMo /N4om 4 1 '4Po

/ Se er es e oe l 4-1-f/ 3cooo ow 3s* SloIsy 3. ;cso 'd . W'? RG'ow on / /24 t-sc 5

35787o 6eeres cloc 5-/- Ed 3D ooo om 3D 3+'7ac4 3 42S 3 560 30 coacco I * *'S**

6 ajyz9, g ,g, a gog g.-/- 92 go ooo coo ^l9495cfd d.Soo N.C46 So ooo coo 2.2*/3C" 7 4 Y4 ?o 2eeues doc f /- 92 56on W 49 3Jd7W. sj.;go t},3of SD cccccc Z. / d oco 8 4 h.c7, geeje3 due 2./.7f 40 ooo ao go oy3 oSg s].Svo y,497 ;Jc acoc, j 793 gon 9

5NS % $eeses doe 4-I-97 '/ Coco ete 74 CIS 4/2 S.373 ,g. 3,(g *] gam ao 4 cJ/ ooo 10 f, Ty% 6e es es d ve. 7-/-98 7(ooo sr> y/909ght 4.375 d,.3R3 '/Tanmo 0 7S7 N 11  ? '7o ge g, eg dve 7-/-99 7Sowox 75 7?f9n 7. mc- 7./g ygmoma 5 r7ew 1

E '70 See,es d oc 9-/-99 ? cow 0:o W&n?4 8. coo IT'.oJo 7sewem 4 noem 13 14 15 16 Sinking Fund Debentures:

17 ^l 7/g 7o be g,'e_s d ue. )qfx jf, ySo go 39 pgjfgf N,fyg $ gy7 Qg ygogy / 970 $gg 18 19 Total Long-Term Debt ld.Sysb / 9f,1909 dg] 7flo9) 443 7Sveco 33 903 7t.S 20 Weighted Average Cos : (Line 19, Col. 7/Line 19, Col. 6 - to 3 decimals) ,6~, fof 7.

gQuestion I l-26

' LIMITED TERM POWER SERVICE SCHEDULE *

• A-8-2 O o K e_ Qowe4 Compcny Embedded Cost of Preferred and Three Year Average Comon Equity

/ :2. - 3 /- d7

- ~

Line Embedded Cost of Principal Expense Net Dividend Net Cost Outstandin'h Annual

_F o . Preferred Series Issued of ssue Proceeds Rate to Comnany as of ener _

(1) (2) 3 (4) (5) (6) (7) 1 (1 x 4 + 3) (5 x 6)

Preference Stock: X.XXX7 1 &,73gor cas.See,eson tocw go god gsq 4 9 19f/&l 4.?S d . 340 So m coo 3 430 000 2

3 Pre ferred Stock:

4 Q .50% bceoe,s C 3 7 000 000 20o875 34 797'5 YEO N* 52/- 35mo ooo / 684 /cu 5 C. 72% 4e es es O 3 r o w ooo co/ 423 3} d99.S?? 57z r803 3S~momo z est osa f . 7X.To e$e6cs E agooo two 487 /43 3h S/083) $.72 4 6/f 3[ 000 @  % 3fC2So 7

8 9

10 Total Preferred Series /Sfoco cao /99P A m /It e t e /rf~ay, e Y gjo V 11 Weighted Average cost Line 10,Co . 7/Line 10 , Col. 6,to 17. decimals i

> S . of 4/ 7 Three Year Average Comon 1:quity Cost Daily Average Comon Ech Year Reference Amount Earnings

• 12 194 7 A-8-3 3gogsagg 42f,79cfj 13 194f 3M . / 9/ Nr A-8-3 Md MO49f 14 19ff A-8-3 377 7## 7 I 15 TOTALS c17,924.138 l l$$ 29727f 16 Weighted Average Cost (Line 15.ColM/J ine 15. Col, 2. to 3 _ dt cimals) /2 Mo/ 7.

• After Preferred Dividends and Exclusive of Extra ordinary II ems Question 1 .-27 l

n. ,

LIMITED TEp POWER Q RVICE SCHEDULE A-8-3 unke Yc.se V Company Daily Weighted Average Common Equity '

\2- 31 *)6 r- .

Reference 19f] 19 g 19 I 7

'~ 1 , Cocenon Equity - End of yeat l'orm 1,p.11'.Jf3 /I I4' MJtJ17.tf J/% /f74r13.

2 Common Equity - Beginning c f year l'orm 1,p.11' 33f"8/rHe3 353 N.TJ4

. . 3422i.T323 3 'ncrease (Decrease) /709fQ /geg27f/

4

/d ff4 /df Lese public sale net proce< ds -e- -o- N' 5 Public sale date 6 Normal change (In. 3 - In. 4)

/7/Mf43 /goh p /jr[f,/49 7 One-half of normal change ( 507. in. 6) .

746'h2Q D4} 47) 7"4Ndff 8 Daily pro-rata share of lir e 4 for

~ ~ ~

no. of days outstanding ( e /365 x Ln 4) ~

9 Average Daily Common Equity (Ins. 2 + 7 + 8) JM/4ddff 36/M/ruf 3 n ;)nfor r .

.i e

l i

1

{uestion11-28

, B LIMITED TERM POWER SERVICE SCIEDULE D o ka. Po m e Company Annualized Depreciation Expenses as of /2.- 3)-4 9

. . . ~ . . . ... .- .---.--.=-n~.----.w-.- a v -

. - .a.- ~.-- --.- . ~ x= -- - a . <r.a + m Line Description Plant Less Depre- Weighted Annualized 3riginal Non-Depre- ciable Composite Depreciati >n Cost c?iable Amount Annual Expense l Balance Amounts Rate (Form 1 (A1, col.3) * (1) - (2) P. 429

._ (3) x (4)

Productico Plant: (1) (2) (3) (4) (5)

Steam aQg34o4o1 1

gj c34292 427 31c pog ,o3,, ,, ,,,yz 2 Nuclear 3 liyd ro - % ,,w } , w /

,gy ygggy.7 to 2.93 gig q7 g y , g , g, 4 Ilydro _

5 Other Prod. Wa/ deb 7 f 727735 -o-  %/ 12SPJs .03f7 715757 6 Other Prod. -

1 General, Comon, etc .

Allocated to Prod. (Enter Col.1 froo A2, In.5, col.2) /M 42/V7s m sz // S39 /r/ . c 472 SV/4VF

._8 Total Pr 4 _(S__um_ uCo l_,.5_1 /7 7/7 7V/

Transmission Plant:

9 Plant Cost (A-1, Col.3 , Ln. 7) 245 s44S55 / 7 //.7 Fo7 2V5 497o# . o2Eg 7 /4z V7f 10 General, Comon, etc.

Allocated to Trans. (Enter Col.1 from A2, Ln 5, col.3) , 3 sg7 del 77, p/7 .2 /d?f27 .o472. /4/ 7pf 11 Total Trans,. (Sum. C )1.5) -o- -o- 73o918 12 Bulk Trans.7. (Sch. A-3) 75~ f ".

Bulk Trans. Amount (Ln. 11 x L1 12) 85/f 47al

• For lines 7 and 10, tfr . non-depr. from Sch. 42, Line 14 .

Question .1-29

C i LIMITED TERM POWER SERVICE SCHEDULE

- sk, we V Company Income Taxes Year 10/3-f.ina Productioni Triansmis s ion J;o , _

(1) (2) 1 Return on investment (Sch. A) JoM$ 11611459 .

2 Less: Interest on Long Tern Debt (Sch.A, line 10 times Sch.A-8, line 1, Col.5) // /Nff3 J JuYWP 3 Balance for equity earning o j g ejMfgg, ,

4 Combined Federal & State income tax factor (1) /49E/I 1 /0 9.* g /I' 7.

5 Total income taxes, before Sch. M adjustments (4 times 3) Jt04 25Trif

, fo37 Af i Gross taxable income (line 3 plus lino 5) ,jgg7[ g *

/fg yo/3- -

Add or (Deduct) . s 7 Difference between book and tax depreciation (Sch. C-1)

(3 /// df39) (/44@)

8 Difference between book and tax nue:. ear fuci amortization ' -/-

) Adjusted taxable income fot- Federal & State income tax 34;hp7&

jggpf,g_

3 Composite Federal & State i neome tax rate (b) A .14 7 ' . [c,2 dO- 9 E.

1 Incone taxes (10 tines 9) _/fY/h?26 7 //'98hfE (1) Calculation of tax fac tor:

100.0007. Tax facto r= (b) = M'2# /o9 h_f M 100 - (b) p,g Less: State rate f.o,o

_ __ _ 94 000 (a)

Federal (474* x N (t)) ~

/j f .ku 7 l Add: State rate 4 ood i

1 Composite Federal & Strte riite R. *[4bb)

I l 1* Federal Tax Rate. I-Question ;.1-30

LIMITED TERM POWER SERVICE SCl!EDULE C-1 Duke fb, e COMPANY Calculation of Difference Between Book and Tax Depreciation As oG '2 - S '* (9

.._z___.._..___._.- _ _ _ . _ . . _ _

p -

gg - --- . _ _ _ _ _ . m. __ _ ,m -

Line Desc g tion llepreciation Plant Tax Base liepreciable Tax Tax . Difference isch.B, Col.:i) Col.3) s idjustment Tax Base Rate Depreciation (2)-(3) '

(4) x (5) (1) - (6)

Production Plant (1) (2)- (3) (4) (5) (6) (7) 1 Steam e s, a s s,'.n 42p21., sol t,2,sul,999 49o, i%,cns .osal 8 7,5 *, a= 2,299,9s8 2 Nuclear 3 Ilydro '--w 6 \ I. Y11, " > 9' "*### ~1,28D,5 bl '8.733,333 .o s so I 8J f f,eco los,2os ,

4 Ilydro 5 Ot her ' Prod . - 1 tc,W c..b. 17S,759 z/ '729 98# 8L,673/f26 38/fc3,3bt .oss7 I 371088 595,298 6 Other Prod.

_7 General, Common, etc.

Allocated to Prod. 5 94.k'8 // (39 /57 3,6:5 9, o 63 ly193,2ro .o m 'lo7, iso Ib%C32-8 Total Prod.(Sum. Col.'i) n ,9 97,74 1 21,o59 680 g *039 Transmission Plant:

9 Plant Cost 7. 'd97 s 5 #U # 8 '" . '0"* IO '0*" E' ** '* D e82#

10 General, Common, etc.

Allocated to Trans. 146,789 3 fo1927 q3p,q2o ,1,04o,W0 .o412 190.728 '13,439 11 Total Trans.(Sum. Co L.5) 13C9,WI E,689 pit 1,390,Wf 12 Bulk Transmission % (Sch. A-3) 755 1 ,

13 Bulk Transmission Amount (in.11 x Ln. L2) e,042,2so l Question 11-31

r ,

LIMITED TERM POkTR SERVICE SCdEDULE D Dokg i fn -a et/ Company ,

., PROPERTY TAXES

r YEAR H]f Lina Description Production Transmission _

(1) (2)

~~1 Local Property Taxes (Sch. D-1) 4 fl7 74t / ,007//2 S . C. Franchise Tax (Sch. D-2) 2 //3 M 4 C 18 9

~

3 Other, if any (explain) -

- o- a-

~

4 Total (Ln. 1 + 2) A Sao oM $ Mda7.I/

i 5 Transmission Bulk Percent (A-3, Ln.8) 7dd I'

4 l -

6 hulk Transmission Amount (In 4 x 5) /$h4do

[ ~~

L t'

I t.

f L

1 t

_. _ l -

Question 11-32 .

D-1 LIMITED TERM POWER SERVICE SCHEDULE '

Onko of;> & _ Company Local Property Taxes y,. IO /1 (1)

L Previous Year Taxes Assessed (Form 1, page 352) /0 99h 7W 2 Less Amount Applicable to I roduction t' nits (Sch. D-1-a, Ln. 19) S M E 2.

> . Balance Taxes Applicable tg all other Plant 7NV Idi Cross Plant Beginning of Ptevious Year:

-  ! Electric (FPC 1, P. 403, Ln. 88) -

MI/d7,M7

~

5 Add Common (FPC 1, P. 3! 1) 2 Deduct Production (FPC [, P.402, Lu.42) (g[gG$.L*4 )

7 Balance non-prod. (Lns. 4 + 5 - 6) 152DN4/

r 3 .rffective prev. year non-prod. rate ( Ln . 3 + Ln . 7) .XXXXXX 00 % ;9 j __

o l

, currant Year Taxes:

I m . Production Plant:

I 9 , Previous year taxes (Ln., 2 above) 39731.7._

p _ ,,_

Add (deduct) Estimated Taxes for Production Plant additLons and re .irement last year (D'-1-a, Ln. 27) 5 77/7 i Acid General - Common allocation .

j (Sch. A1, col.4, Ln. 6 x Line 8 ebove) / ff't.92 1

'I ,

Total Production, current year d $1774ll e

! Transmission Plant:

~

1 l Plant in service beginn:.ng of current year (A L , col .1, L1.7) Jt,tTN 917,

t a  ; Add General - Common al Location -

(A1, col.4, Ln.7) 3 5T(1,7a4

'; ,_ ', Total (Ln. 13 + :.4) M7M i

.S TrSumi ssion Taxes Current Year (Ln.15 x L, 8 rate) ADh//.'L,

' l i

t

. I i

.__..r a _._ w.

t ,l I

l Ouestian 11-33 i

l l

l i

l I

LIMITED TERM POWER SERVICE SCHEDULE D.1.a Du ke A w to Company PRODUCTION PLANT LOCAL PROPERTY TAXES ,

YEAR / 94 9 Page 1 o-P 3 )

i Line l Plant Name Type County lValue Rate Tax l l

r- Plant (Mills per S-Steam $1)

N-Nuc Plants Taxes H-Hydro (3) x (4) l Previous Year 0-Other (1) (2) (3) (4) 1 l Al C . g}.e u .

2 Atled S 493 993 3 , R,vecb w d ;S 2M 37'l 4

l 6oc k .- 19 S'it 5

2.1. m.de  : 66 3CC l

6 i Daa P,vea 6 -t 0 2.34 sn 7

l p)g,9 y ll g 432 m

~

6v b Tc+a l lvvv 769 s

! Al c. coap. Esce u 2.5% 44 444 la l Tila/ Al.e. Slean 1 ez2 zis I II O.0 $-} rnM * -

' I1 l- c e 640 Sf7 SS/

g Zged .I /g 99/

14 l Ev2.2. sed Pead S tr i ,

)i  ; 54a/Sc.9:w 621 94.?

I *! C. Avdens l 17 l .?.c ,d n e w e.k2 2 13 2 16 l

19 lTotalpreviouscalendaryeartaxes (Sum.1-18) A z,, d i

i Annualized Tax on Units Added or Reti. red:

20 l, f

21 l l

l

' cy"  ?

23 ,

. I 3 ., e 2' Total annual taxes on plant changes (Sum. 20-2M f g.] l 5 l Question 11-34 i

(

h

. LIMITED TERM POWER SERVICE SCHEDULE D-1-c O o he Po o e a Company PRODUCTION PLANT LOCAL PROPERTY TAXES TEAR /969 ?MjC A CE 3

.ine Plant Name Type County Value Rate Tax Plant (Mills per S-Steam $1)

~

N-Nuc Plants Taxes H-Hydro (3) x (4)

Previous Year 0-Other (1) (2) (3) (4) 1 M c. Nadu (Ces ) ~

2 P koa k.ss H .zl 179 3

o x.foea H 3s- 042 4 . l-oo k od .6 h oa ls H 24 n1 5

l C ow aus Fosd H 272 .tle c '-

L M 4. '1~sfed H 3749f1_

{7 \

ToRHe& H /4 304 6 Tugea a H .s ssy 9 $o/ Ace k]l Hoe la N. C. Hydeo I"n Plan &s H '

II 2M

\;2 .5v 6 T*da I - n'. c . Hyden 482 f.91 n N.c. Cas o. & cass .: . 29 '

12 o9:

, To~+n/ A/.c. H ydec 495 723 ss 3 c. Mydao:

I Wvllc. J./ j9.,i 033 17 fo ,s A,9 Ceeek H jf7 5 1 2.

I g GeentL G Ms M 24 c67 19 Total previous calendar year . taxes (Sum.1-18) /wel l

, Annualized Tax on Units Added or Retired:

.'0 I

22 I)

'.N.

l 5

7 Total annual taxes on plant changes (Sum. 20-26) pyg l Question 11-35

- o LIMITED TERM POWER SERVICE SCHEDULE D-1-a Duke Pa u,e ns Company PRMUCTION PLANT LOCAL PROPERTY TAXES ygAn /$49  ?%d 3 CS 3 Ins Plant Name Type County Value Rete Tax Plant (Mills per S-Steams $1)

N-Nuc Plants Yaxes H-Hydro (3) x (4)

Previous Year 0-Other (1) (2) (3) (4) 1 .:f.c. Hvd.% (Cod, ) ~

2 Dedd beed N W off 3 Roe ky Cecek N 37 2.75 4 Cedas Geeck H //9 8 s

l klaleece }4 2as' O'S 1.,

9 9 T.sle a d s // 10 ar7

? 0, As +od gh onl3 H f l7 c14 s Saluda H 19 34'l 9 &oLLAed Roosh H /L 30l 10 5~o b ed M Mo2 .dC.

Hydao PInah

~

n H -

11 141

2 du b To +Al S. c. Hydeo 943 348 3 i '

N 14 5

6 17 8

19 Total previous calendar year taxes (Sum.1-18) 3 F#3 332.

l Annualized Tax on Units Added or Reti. red:

0 #14 e3 4 4 // #3 4 Cdawb4 1.2 3/s roo /4.p 37V 37 i .,1 R, ve e bead 4 Qas+aJ S 343ow /6 4 87 42s

,2 D n ~I R. Vc 4 0 kkoy h" I SI"3 " 'd*7 20 034 3 U29*bA*Y 0 ft a kcd $gl $bo 90.o 28 1st fidad./e .. R.rc_e dh4 eed ') # /#er+eo/d (fo 73o) 1 d. ird ( / /ST)

Gu Pew dce N e,

8*2 (Rei.w) d 4/d we //

(7J Sri) /2.o ( F83) 26 N /! O ## *

"N #

-C- -d' Total annual taxes on plant changes (Sum. 20-26) 7 foy yf 7 Question 11-3 6

LIMITED TERM POWER SERVICE SCHEDULE Doke Pause e South Carolina Franchise Tax (True Value)

Year _ /969 l

1 Total Franchise-Electric liepartment-per Company Records E " F6 6~47 Assessment - Production P:. ants in S .C.

Assessmen  :

l Steam $

I Lee g 11413o T 8CO I38f.40 6 o 2 2 a8d 9cas E 2t9 180 1 livdro l

V4 6

• o us ?lAb g 749 400 iaternal Combustion Turbines l- C C 946 joo i

I i . Tota 1 Assessment $/f199 45D + 42x100=$ 3 6 42 7 738 Tax @ S.003-Applicable to Year End Production E I#iO

/. Annualized Tax on Units added or ret Lred:

i l

{  ; Total Assessment 9/S ; 7?Aso+ 42x100xS. 303-$ R ! Taxes Applicable to Total Production in South C arolina (3+i) ) /09113 I

6; Taxes Applicable to All 0 :her Utility Plant in 1.C.(Line 1 - 3) 'S / 7 7 2 f 6 7 Summary - Allocation fraxesApplicableto: Amount oh^ Gen. Plt.

(A-1, Col.o)

Total Production (Line 5)  ; / c 9 2.573 , 2 999 3/12 Zfh j Transmission (1) SC J 3 / fcf 54 /39 j Distribution (1) // d /f Jb //8 /

3 General (1) 7 fc/ ( 7 IO / ) -O-c j 256 n o s+ -c- s xt& rs? .

1

. , ' Allocation based on Plant Investment (A-1, Col. 1): [

l l'lant Inves .

All acation  !

A-1, Col.1) ; of Total of Taxes (Line 6) j i Transmission f g gfy jj gj i l <g y3f I  !

Distribution f 4 M #3I d W ' '#

jGeneralPlant 37.s(,83E d JC l 7 fo/ i l Total f Ss'/ e47 nJ 100.00'l h / 7'f 74 Ouestion 11-37 j t

1 1

E LIMITED TERM POWER SERVICE SCIIEDULE D o k e_ Q ,,, e v- company ANNUAL INSURANCE YEAR \9'10

, h escription b (1) (2) (3) (4) _

_l' Total Insurance Previous Y ar (Acet.9 4,FPC 1, P.419) 4 ff~JfR 2 Add (deduct) amount necess try to annu alize Acct. 924 -

for addition or retirem :nt of generating unit df/d37 3 Total Insurance Curr ant Year J 77No J

Allocation of Ln.3 total (3xplain

! Allocation Basis Below if' to t I Directly Assignable):

Production Transmission Other Total I -

4 l,

F1re and extended covera ge (97// ,jy477

([pf9_ gho O Boiler and machinery 5

6 Nuclear liability g _ _ gf, g

Other: -

Tooca Tood

? b t' / V 12AJ '

s._. I M .,s? mmh -

3,k- I tir- Iros

/

'J 10 11 12

.l. 3_

-14 15 Total - Per Ln.3 8Cl5Hfd-  ?'7u'77 / N 3 7l 477[0 0 16 Bulk Transmission Percent g(7, 1: -

Sulk Transmission Amount hfh[

1  !

u.__ Explanation of Allocation 3ases:

' Explanation

,f;ine No.

~

~] SCN A.l (of $ , d!>f BS/S

[ ///Z,1y/ I t

1 . . . _ _ . . _ . _ _ . _ . . _ . _ . . _ _ _ _ . _ . . . _ _ . _ _ _ _ _ _.___ . ____. _ _ _ _ _ _.

6 i

i t-e t

i

. -- . . _ . _ _ _ _ . _ _ . _ _ . . .. - . . . _ . . . . . _ _ _ . _ _ _ _ . ._ Ouestion 1}.33_ . . _ . ..

p.

e I

LIMITED TERM POWER SERVICE SCliEDULE F h A' t Pow ar Company p Transmissi'on Operating and Maintenance Expense I

Year 19 70 l Line No,__ Amount

'F i 19/g Expense (Form 1, . p. 418, line 47) fol[f2r/

i 2 Add 37. A V 7. for A & G, payroll taxes , etc. ,

(Schedule __UI a) / 9'7M4.9 3 Total 7;,7q /ot, 4 7. applicable to b 21k power

, _ _ (A-3, col. 7 7.) 7f.f t il

.i 5 i Transmission expense appli :able to bulk power fa9/ 9ils '

F 0 k

t i

L.-

.1 l

+- - . . . - _ __ -. . __.

x 1

I l

i

, .. _ [ _ _ . . _ , _ _ _ _ . . _ _ . . __. . ._ _

l l Question 11-39

LIMITED TERM POWER SERVICE SCHEDULE g 1

h a he Pmne2 Company Net Continuous Plant Capability

[ As of /2 3/-69 Page / of /

.1

~

Line Reference ilu8ie'a I Steam O E Prod P Hydro Total

.p.~ Plant Name ......_,___ .. '

. _(1)__ __ __ . , 12 ) _ . .

_ _ Q1 .

(4) ._ ._L, . ., (6) _.

i, Reference FPC Form 1 P432 -L10 P432 -L10 7432 - L 5 , P433 - L10 A R. vee bend tse 81r izo ac 0 vc. h , A3 5' l.k r

4 D44 RoVCG Xf8 9.50 SS 000 b

._ . ' _.. . _ ._ . . . . . . . l27 980., _. . . _ .

n , 7~3ee ,

21 c.w f '

Lee .

St.I sfo 90 **

'9 A//es/ / 1 0 S40 hipaksbA// l W yoo

)

Me7 "Id . _ . _ _ _ _ . _ .

. _ . _ . . _ _Vatecc._ . . .

6a.1 e<G %d. slea~r z.rz. sM. I4 too B2 *d o e Welce ,

jf 6Cc A3 Shcdh 43 I 21 300 C VEc nid 39 doc

• i l-oo kou$ $ hon $ 2./ Too

-{ . . . . .

, Mf Is/wxd , n, coo

7 00 &ds fodd ,

37% cec Wy/s e STeoc

y W

, ,5 l

. s'} OsteeA' U *) .Sc0

.m ,

Seea ' fr. */s t I

,?d goo f/e4e'ber%' a

,3s ;op

? '

Soc ky Cceek l 29 000 d ed4e Cadec h 3? Cx; g Wa/cece 2, roo C3 Ih/4~'d$~ ,

9 9sv l ., 0.'2.zAed h s4&c'co /3 2o0

$r4 // hl4N!.tr s'O 26'l i

f I

Total Production Capability, d 5'7/ 95i 3tr coo 862 2/d 5 7F '44# '

Long-term firm purchase: From g g pfp f c g_.#g i 3' KW / 'IS* hn 2 f "V/5' ? /M 272 Total Trans. KW(L31 + L33) f 9 3f 4N Ouestion 11-40

. r- -

I

<a I

Question No. 12:

State (a) for generating facilities and (b) for transmission subdivided by voltage classes, the most recent estimated cost of applicant's bulk power supply expansion program of which the subject unit is a part, in terms of dollars per kilowatt /per year, in mills per kilowatt hour and in both the

~

kilowatt costs and kilowatt hour costs divided by the kilowatt hours.

Answer:

The latest estimates of cost for the Oconee Nuclear generating units and assa-ciated transmission are:

Investment:

Generating Units, not including nuclear fuel $130.00 per kw 500 Kv transmission 26.62 230 & 100 kv transmission 6.18

.; Total $162.80 per kw Annual Cost: ,

Generation $ 20.80 per kw per year Transmission 5.25 Insurance .70 Total Fixed Charges S 26.75 per kw per year Fuel (7000 hrs / year) $ 12.60 per kw per year 0&M 1.05 Total Production $ 13.65 per kw per year Total Annual Cost:

Fixed Charges $ 26.75 per kw per year Production Expense 13.65 per kw per year Total S 40.40 per kw per year 5.77 mills /kw hour 3.82 (fixed charges) 1.95 (production)

Costs shown do not include components for other system fixed and operating expenses.

In addition, power delivered in South Carolina is subject to a .5 mill per kwh generation tax and in North Carolina is subject to a 6% gross receipts tax.

12-1

- s

.n Question No. 13:

List and describe all requests for interconnection and/or coordination and for purchases or sales of coordinating power and energy from adjacent utilities listed in Item 9 since 1960 and state applicant's response thereto.

List and describe all requests for supply of full or partial requirements of bulk power for the same period and state applicant's response thereto.

Answer:

CP&L requested the right tc transfer power from its western to its eastern division through the Duke system. CP&L also asked that Duke supply up to 36,000 kw of capacity for the seven month period June, 1965 through January, 1966. The capacity request was later increased to 71,000 kw and the time extended one month. The right to schedule power transfers was included in the interconnection contract which became effective in June, 1961. After having determined that its reserves would be adequate, a term service agree-ment providing for the sale of capacity as requested by CP&L was consummated.

CP&L requested Duke Power to purchase part of the output of a steam electric generating unit scheduled for service in 1971 at CP&L's Asheville generating J- plant. CP&L also requested Duke Power to build part of a new 230 kv inter-

' [' connection to transmit a portion of the output of the Asheville unit. Duke Power responded positively to this request because of the economic and reli-

__ ability advantages.

+

Yadkin, Inc., on two occasions requested supply by Duke of power to supple-

~

ment their own generating resources to permit enlargement of the Alcoa facility at Badin, North Carolina. These requests resulted in an agreement whereby Duke supplies off-peak energy to Yadkin. The agreement also provides for sale of maintenance power and energy to Yadkin at pre-arranged times.

Supply to Yadkin during peak load hours, if requested by Yadkin, is contingent on availability from Duke. Duke has accordingly at times refused to supply or has interrupted supply of on-peak power.

l SEPA requested Duke to wheel power and energy from the Hartwell project to L. its preference customers; to purchase the excess capacity without accompanying firm energy; to purchase any excess energy occurring because of greater than average stream flows; and to supply deficiency energy when energy transmitted from the Hartwell project was less than SEPA's contractural obligation to its preference customers. These requests were accommodated by a contract dated December 16, 1963.

Under the former CARVA Pool Agreement, Duke was responsible for maintaining a pro rata share of the total pool reserve. This included an obligation to purchase or sell reserve capacity at various times. Although such sales and

. . purchases were not in response to specific requests, the resulting transactions with adjacent utilities are listed following for completeness:

l 13-1 1

1

W.

l 4

I RESERVE EQUILIZATION TRANSACTIONS  :

MW Purchased i Date Duke MW From MW Sold To Begin End Purchase Sale SCE&G CP&L SCE&G CP&L

. 5-1-67 12-31-67 22 22 i 1-1-68 1-31-68 18 18 I m 2-1-68 2-29-68 20 20  !

3-1-68 3-31-68 19 19 4-1-68 4-30-68 22 22 5-1-68 5-3-68 42 42 5-4-68 5-10-68 47 47  ;

5-11-68 5-12-68 224 88 134 5-13-68 l 5-31-68 268 81 187 '

6-1-68 6-30-68 236 81 155 7-1-68 7-14-68 234 81 153 7-15-68 3-31-69 376 51 325 4-1-69 4-30-69 383 51 332 5-1-69 5-19-69 286 286 5-20-69 2-29-69 18 18 5-30-69 5-31-69 158 158 6-1-69 6-30-69 66 66 7-1-69 7-15-69 110 110 7-16-69 7-31-69 91 91 8-1-69 9-30-69 59 59

, 10-1-69 12-31-69 62 62 1-1-70 4-30-70 60 60 7 5-1-70 5-31-70 242 165 77 6-1-70 6-28-70 192 173 19 6-29-70 7-31-70 215 180 35 8-1-70 8-31-70 224 162 62 i 9-1-70 9-9-70 229 164 65 9-10-70 12-31-71 76 76 I l-1-71 1-31-71 81 81 2-1-71 3-10-71 74 74 i 3-11-71 44 8 36

\

l l

=

13-2

. p-SCPSA applied for admission to the Carva Pool. Negotiations in this matter were not completed at the time the pool agreement was terminated. SCPSA has

~

been offered the reliability and limited and short term service scheduled

~

which have replaced the former pooling agreement.

The City of High Point requested delivery at two points with either delivery point to be capable of supply of the entire bulk power requirements. This would have required parallel operation of the city's distribution system with the Duke Power transmission system between the two delivery points and would have subjected the city system to unmanageable and extremely heavy power flows in the event of outages on the paralleling Duke system. The request was, therefore, turned down in recognition of the technical difficulties. A subsequent request for similar service has been received from the Blue Ridge EMC. Based on studies which are still underway, it appears that the greater geographic separation of the two projeu;ed Blue Ridge EMC delivery points and the capability of the transmission through the Blue Ridge system between those points will allow satisfactory parallel operation.

~~

The University of North Carolina, Abbeville Water and Electricity, and Lock-hart Power and Light Company systems operate generation in parallel with Duke and have many times requested changes in the amount of supply by Duke Power Company. All such requests have been honored. The same was true with respect to the Belton Power and Light Company before acquisition by Duke.

Many other requests for new delivery points, abandonment of existing delivery points, or changes in the amount of supply have been received and complied with. New deliveries which have been established and existing delivery points which have been abandoned in response to such requests since 1960 are:

I i

t t

h i

13-3

y NEW DELIVERY POINTS TO RESALE CUSTOMERS .

I JANUARY 1.1960 TH10 UGH PRESENT DELIVERY

. SIZE RATE D/TE OF EFFECTIVE

- . CUSTOMER-DELIVERY-LOCATION KW SCHE AGREEMENT DATE Greenwood County Electric Power Commission 5,000 Opr 7-27-59 3-1-60 Laurens, S. C.

'! Broad River Electric Membership Corporation 750 ll-A 10-29-59 6-1-60 Carlisle Delivery, Whitmire, SC

~

Piedmont Electric Membership Corp 1,500 ll-A 3-21-60 10-1-60 Eno Delivery, Durham, NC Pee Dee Electric Membership Corp 800 ll-A 7-18-60 9-1-60 Norsood Delivery, Norwood, NC

I Laurens Electric Cooperative, Inc 750 11-A 8-16-60 10-1-60

'. Fountain Inn Del, Fountain Inn, SC Blue Ridge Electric Cooperative, Inc 1,000 11-A 10-3-60 1-1-61 Anderson Delivery, Anderson, SC

-. Little River Electric Cooperative, Inc 750 11-A 10-7-60 11-1-61 Latimer, SC Davidson Electric Membership Corp 1,000 11-A 6-16-61 10-15-61 Walnut Cove, NC Delivery No. 7 Rutherford Electric Membership Corp 1,500 11-A 7-24-61 11-1-61 Hardins, NC Pee Dee Electric tkmbership Corp 300 ll-A 6-23-61 7-17-61 Marshville, NC City of Lexington 7,500 10 5-9-61 2-1-62 Delivery No. 2, Lexington, NC Cornelius Electric Membership Corp 1,200 ll-A 8-3-61 11-1-61 Cowans Ford Delivery, Lowesville, NC j City of Shelby 2,000 10 3-5-63 9-1-63 4-Delivery No. 4, Shelby, NC Laurens Electric Cooperative, Inc 300 ll-A 2-21-63 4-15-63 s Trinceton, S. C.

Laurens Electric Cooperative, Inc 300 ll-A 9-3-63 9-1-63

. Near Duncan,' SC Laurens Electric Cooperative, Inc 800 11-A 10-23-63 10-23-63 Lanford, SC Pee Dee Electric Membership Corp 600 ll-A 7-2 A 7-1-64 Sturdivants Crossroads Del., Marshville, NC 13-4

r-l DELIVERY I SIZE RATE DATE OF EFFECTIVE CUSTOMER-DELIVERY-LOCATION KW SCHE AGREEMENT DATE Lockhart Power Company 20,000 10 12-6-63 9-15-64 Union, SC

,_. , City of Gastonia 4,200 10 1-6-64 6-1-64 Delivery No. 5, Gastonia, NC

~

Commissioners of Public Works of the 3,000 10 6-19-64 11-1-64 City of Greer and the City of Greer, SC City of Castonia 4,500 10 2-24-65 4-15-65 East Gastonia Del., Gastonia, NC City of Newberry 1,000 10 3-29-65 8-15-65 Newberry, SC City of Morganton 3,000 10 12-29-65 1-20-66 Delivery No. 2, Morganton, NC Cornelius Electric Membership Corp Sherrills Ford, NC - Delivery No. 5 1,600 11-A 6-7-65 1-15-66 Hambrights Crossroads, Huntersville, NC 800 11-A 6-14-65 11-15-66 Davidson Electric Membership Corp Gold Hill Delivery, Madison, NC 600 ll-A 6-22-64 10-1-64 I'

Surry-Yadkin Electric Membership Corp Pilot bbuntain, NC - Delivery No. 5 900 ll-A 10-8-64 1-17-65 r

Blue Ridge Electric Cooperative, Inc Central, SC . 800 ll-A 4-2-60 9-15-60 Cateechee, SC 1,000 11-A 2-26-65 4-18-65 Broad River Electric Cooperative, Inc Cowpens, SC 1,400 11-A 1-1-66 11-15-66

, York Electric Cooperative, Inc Tirzah, S. C. Delivery No. 6 1,800 ll-A 3-22-65 9-15-65 Ogden, S. C. Delivery No. 7 500 ll-A 6-1-65 11-1-65 Piedmont Electric Membership Corp 1,800 ll-A 6-30-65 3-15-66 Delivery No. 4, Buckhorn, NC l

L- Davie Electric Membership Corp 900 11-A 12-22-65 4-7-66 Bethlehem School Del., Del. No. 6, Hickory,NC f

Cornelius Electric Membership Corp 1,600 11-A 1-3-66 10-1-66 Davidson Del., Del. No. 7, Davidson, NC Broad River Electric Cooperative, Inc 750 ll-A 6-9-65 10-1-66

- N. Blacksburg Del. , Del. No. 7, Blacksburg, SC Davie Electric Membership Corp 1,800 11-A 3-8-66 10-1-66

. Charles Delivery, Charles, NC 13-5

i6

, *- DELIVERY SIZE RATE DATE OF EFFECTIVE CUSTOMER-DELIVERY-IDCATION KW SCHE AGREEMENT DATE City of Gastonia 5,500 10 4-25-66 8-8-66 Delivery No. 6, Gastonia, NC

~'

Laurens Electric Cooperative Delivery No. 10, Laurens, SC 1,800 11-A 12-16-66 11-20-66 Delivery No. 11, Hooker St., Laurens, SC 200 ll-A 12-16-66 11-20-66 Delivery No. 12, Clinton, SC 1,600 11-A 12-16-66 11-20-66 Delivery No. 13, Cold Point, SC 1,200 ll-A 12-16-66 11-20-66 Delivery No. 14, Waterloo, SC 500 ll-A 12-16-66 11-20-66 Delivery No. 15, Joanna, SC 1,200 ll-A 12-16-66 11-20-66 Delivery No. 16, Belfast Del., Joanna, SC 800 11-A 12-16-66 11-20-66 Little River Electric Cooperative, Inc Del. No.4, Rocky River Del., Abbeville, SC 1,500 ll-A 12-12-66 11-20-66 Del. No.5, Secession Ave Del.Abbeville, SC 1,200 ll-A 12-12-66 11-20-66 Commissioners of Public Works of the 2,500 GCEPC Rate 5-1-63 5-1-63 Town of Ninety Sir., SC 1'

Abbeville, City of 3,000 10 Class 2 1-3-67 7-1-66 Abbeville, SC

'l Commissions of Public Works of the City of Laurens, SC Hampton St Delivery 5,000 10 12-15-66 11-20-66 Royal St Delivery 3,000 10 12-15-66 11-20-66 c Hooker Ave Delivery 2,500 10 12-15-66 11-20-66

.l A

Commissioners of Public Works of the City of Greenwood, SC 1 6,500 City Substation Delivery 10 1-12-67 11-20-66 J Water Works Delivery 3,500 10 1-12-67 11-20-66 Mr'. hews Substation 1,000 10 1-12-67 11-20-66 a Cokesbury Street Delivery 3,000 10 1-12-67 11-20-66

q. Clark Hill Delivery 2,500 10 1-12-67 11-20-66 South Carolina Electric and Gas Co Chapells, SC Delivery 150 10 1-3-67 11-20-66 Blue Ridge Electric Cooperative, Inc 2,000 11-A 2-23-67 4-15-67 Delivery No. 11, Easley, SC w.

Broad River Electric Cooperative, Inc. 750 11-A 2-27-67 4-15-67

. Delivery No. 9, Jonesville, SC Laurens Electric Cooperative, Inc 1,500 11-A 1-25-67 4-15-67 Del No.17, Marion St' Del., Joanna, SC Laurens Electric Cooperative, Inc 800 11-A 3-1-67 5-15-67 Del No. 18, Ware Place Del. , Pelzer, SC 13-6

DELIVERY

,I SIZE

• RATE DATE OF EFFECTIVE 8

CUSTOMER-DELIVE RY-LOCATION KW SCHE AGREENENT DATE F

Rutherford Electric Membership Corporation 2,500 ll-A 7-25-69 10-22-69 Delivery No. 11, Sevier, NC

- City of Statesville 25,000 10 10-21-68 12-22-69 Delivery No. 2, Statesville, NC Davie Electric Membership Corporation 750 ll-A 6-3-68 11-21-69 Delivery No. 10, Boomer, NC, Commissioners of Public Works of the 2,500 10 12-18-69 2-20-70 City of Easley and the City of Easley, SC Delivery No. 2, Easley, SC Commissioners of Public Works of the 6,000 10 12-1-69 5-21-70 City of Greenwood, SC Edgefield Street Substation Commission of Public Works of the 14,000 10 4-21-69 6-22-70 City of Laurens, SC Caroline Street Delivery Piedmont Electric Membership Corporation 3,000 ll-A 10-24-69 7-22-70 Delivery No. 6, Camp Springs, NC Town of Maiden 2,000 10 3-3-69 7-22-70 Delivery No. 2, Maiden, NC Davidson Electric Membership Corporation

- Delivery No. 8, Walkertown, NC 400 ll-A 4-28-70 7-22-70 Delivery No. 9, Belews Creek, NC 400 ll-A 4-28-70 6-22-70

] Delivery No.10, South of Walnut Cove, NC 500 ll-A 4-28-70 6-22-70 Little River Electric Cooperative, Inc 1,000 ll-A 3-14-70 11-20-70 Delivery No. 6, Watson Substation,Starr, SC City of Gastonia 3,500 10 4-7-70 1-20-71 Delivery No. 9, Gastonia, NC Town of Prosperity 600 10 12-4-70 2-19-71 Delivery No. 2, Prosperity, SC 1.

I 13-8

. Ri-9-ten, .,~Ils Cy, asa:,:; , ..: -

2-2 7L CANCELLATION OF DELIVERY POIhTS AT CUSTOMERS REQUEST OR DUE TO PURCHASE DELIVERY RATE DATE OF EFFECTIVE CUSTOMER-DELIVERY-LOCATION KW SCHE AGREEMEhT DATE

. The United States of America 4,000 10 2-7-64 1-24-64 Donaldson Air Force Base Greenville, S. C.

Belton Light and Power Co 8,200 10 Purchased 11-11-63 Belton, S. C.

Pisgah Mountain Electric Co 1,100 10 Furchased 7-20-64 Long Shoals, NC Greenwood County Electric Power Commission 20,000 Oper Purchased 7-/-C6 20 55 Laurens, S. C.

Rutherford Electric Membership Corp Delivery No. 2, Dallas, NC 1,800 11-A 2-21-67 2-21-67 Commissioners of Public Works of the City of Greenwood, SC - Mathews Substation 1,000 10 12-4-67 11-19-67 Commission of Public Works of the City of Laurens,SC - Hooker Ave Delivery 2,500 10 10-30-67 6-16-68 Davie Electric Membership Cocp Delivery No. 1, Mocksville, NC 2,600 11-A 10-15-68 10-9-68 Pee Dee Electric Membership Corp Delivery No. Temp. 1, Marshville, NC 400 11-A 11-9-68 11-4-68 Commission of Public Works of the Town of Ninety Six, SC 2,500 GCEPC Purchased 10-1-69 Commissioners of Public Works of the City of Greenwood, SC - Cokesbury Substation 3,000 10 11-24-69 11-16-69 Comnission of Public Works of the City of Laurens,SC - Royal Substation 5,000 10 5-18-70 6-22-70 Kershaw Oil Mill Kershaw, SC 4,000 10 Purchased 8-17-70 Commissioners of Public Works of the City of Greenwood, SC - Clark Hill Delivery 2,500 10 9-18-70 7-22-70 13-9

r f

CANCELLATION OF DELIVERY POINTS AT CUSTOMERS REQUEST OR DUE TO PURCHASE

. DELIVERY RATE DATE OF EFFECTIVE CUSTOMER-DELIVERY-LOCATION KW SCHE AGREEMENT DATE

. The United States of America 4,000 10 2-7-64 1-24-64 Donaldson Air Force Base Greenville, S. C.

Belton Light and Power Co 8,200 10 Purchased 11-11-63 Belton, S. C.

Pisgah Mountain Electric Co 1,100 10 Purchased 7-20-64 Long Shoals, NC 71 Greenwor>d County Electric Power Commission 20,000 Oper Purchased 64-30-66 Laurena, S. C.

Rutherford Electric Membership Corp Deliveay No. 2, Dallas, NC 1,800 11-A 2-21-67 2-21-67 commissioners of Public Works of the City of Greenwood, SC - Mathews Substation 1,000 10 12-4-67 11-19 67 l

Commission of Public Works of the City of Laurens,SC - Hooker Ave Delivery 2,500 10 10-30-67 6-16-68 Davie Electric Membership Corp Delivery No. 1, Mocksville, NC 2,600 ll-A 10-15-68 10-9-68 Pee Dee Electric Membership Corp Delivery No. Temp. 1, Marshville, NC -400 11-A 11-9-68 11-4-68 Commission of Public Works of the Totrn of Ninety Six, SC 2,500 GCEPC Purchased 10-1-69 Commissioners of Public Works of the City of Greenwood, SC - Cokesbury Substation 3,000 10 11-24-69 11-16-69 Commission of Public Works of the City of Laurens,SC - Royal Substation 5,000 10 5-18-70 6-22-70 Kershaw 011 Mill Kershaw, SC 4,000 10 Purchased 8-17-70 Commissioners of Public Works of the City of Greenwood, SC - Clark Hill Delivery 2,500 10 9-18-70 7-22-70 l 13-9 l

f Question No. 14:

I~ List (a) agreements to which applicant is a party (reproducing relevant

! paragraphs) and (b) state laws (supply citations only), which restrict or preclude coordination by, with, between, or among any electric utilities

[ -

or systems identified in applicant's response to Items 8 and 9. List (a)

{ agreements to which the applicant is a party (reproducing relevant paragraphs) and (b) state li.ws (supply citations only) which restrict or preclude sub-r stitution of se.vice or establishment of service of full or partial bulk power supply re tuirements by an electric utility other than applicant to ,

systems identilted in Items 8 and 9. Where the contract provision appears in contracts or rate schedules on file with a federal agency, identify each

, in the same forn as in previous responses. Where the contract has not been i filed with a fed tral agency, a copy should be supplied unless it has been supplied pursuant to another item hereto. Where it is not in writing, it should be descril ed.

Answer The Applicant knows of no agreements to which it is a party or State laws "which restrict or preclude coordination by, with, between or among any

.[ electric utilities or systems identified in Applicant's response to Items 8

! and 9."

r 'Ihe Applicant knows of no " agreements to which the Applicant is a party . .

which restrict or preclude substitution of service or establishment of service of full or partial bulk power supply requirements by an electric utility other than the Applicant to systems identified in Items 8 and 9." While the Applicant's contracts for wholesale power supply to its municipal and rural electric cooper-ative customers listed in response to Item 10 provide that the Applicant will furnish all of their bulk power requirements (other than that portion of their requirements which Applicant is now wheeling to some of the'n from the U. S. Army Corps of Engineers Hartwell and Clark Hill projects on the Savannah River in South Carolina for Southeastern Power Administration, U. S. Department of In-terior, and other than portions of the requirements of some of the rural electric cooperatives being supplied to them at some of their delivery points by Carolina Power & Light C .npany) such wholesale power contracts af ter their initial term c,f five years, ahich initial term has in mos t instances expired, are contracts f rom year to year, terminable upon sixty days' written notice by either party.

As a practical matter, they do not " restrict or preclude substitution of service." -

a The following State laws migt t, in a given factual situation, be construed to

" restrict or preclude substitution of service or establishment of service of

full or partial bulk power supply requirements by an electric utility other than Applicant to the system identified in Items 8 and 9."

{

N. C. G. S.62-110. Certificate of Convenience and Necessitv.

State ex rel. Utilities Commission v. Carolina Tel. & Tel. Co.,

267 N. C. 257, 148 S.E. 2d 100 (1966j 14-1

i 4

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State ex rel. Utilities Commission v. Two-Way Radio Service. Inc.. -

272 N. C. 591,158 S.E. 2d 855 (1968) .

r

.l; N.C.G.S.62-118. Abandonment and Reduction of Service.

7 Code of Laws of South Carolina 1962, Section 24-63. When Certifi-

cation of Convenience and Necessity Required; Section 24-64, Pre-

'l

• requisites to Issue of Certificate; Section 24-67, Action When Utility Proceeds Without Certificate; Section 24-68, Interference

[ with Another Utility; Section 24-69, Abandonment of Service.

The following State statutes restrict competition betweea electric utility companies and rural electric cooperatives.

N.C.G.S.62-110.1 and 110.2.

N.C.G.S. 160-510 thru 519, inclusive.

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Code of Laws of S.C. 1962, Sections 24-13 thru 24-18, inclusive;

. Code of Laws of S.C. 1962, Sections 24-63.1 and 63.2; Code of Laws of S.C. 1962, Sections 24-67 and 68; II!

Code of Laws of S.C. 19o2, Sections 24-76.

e 6

a 14-2

r, Question No. 15:

r State, at point of delivery, average future costs of power purchased from appli-cant to adjacent systems identified in applicant's response to Item 9 in terms o of dollars / month /kw for capacity, mills /kwh for energy and mills /kwh for both

. power and energy at purchaser's present load factor (a) at present load, (b) at 50 percent increase over present load, (c) at 100 percent increase aver present load, and (d) at 200 percent increase over present load. [All costs

. should be determined under present rate schedules.] Where sales are made under r contracts or rate schedules on file with a federal agency and not included in the response to Item 9, identify each in the same form as in previous responses.

Where the contract has not been filed with a federal agency, a copy should be supplied.

l i Answer:

r Duke Power Company has limited and short term rate schedules in effect for sales to SCE&G Company and CP&L Company. The cost of limited term capacity F is based on the investment in production and tran mission facilities adjusted

,' for transmission losses. In February this year, Te rate was $1.50 per kw per month before adjustment for losses. This rate s change as costs of new

, facilities are incurred. Energy under the limits. term schedule is priced at I the calculated average production cost of energy produced at all plants plus i

ten percent plus an adjustment for losses. During February, the rate was 5.9 mills per kwh before loss adjustment. Short term capacity is priced at $1.52 i per kw per month plus losses. Energy is priced at 110 percent of the calcu-lated average production cost of the highest cost generating units being used to produce the energy plus losses. There have been no recent short-term sales.

Loss adjustment on both limited and short-term schedules is accomplished by scheduling coincidental delivery of loss compensation.

Duke's rate for off-peak energy to Yadkin depends on the clock hour of sched-uling. During 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> per week, the rate is 3.98 mills /kwh; during 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />, the rate is 4.3 mills; r.nd, during 29 hours3.356481e-4 days <br />0.00806 hours <br />4.794974e-5 weeks <br />1.10345e-5 months <br />, the rate is 4.5 mills. Energy during peak load hours is priced at 5.58 mills per kwh for the first 400,000 kwh per day and at 6.20 mills per kwh for all additional. Maintenance energy is priced at 7.5 mills per kwh. A fuel adjustment is applicable to all of the above rates to Yadkin when Duke's fuel cost exceeds 26.5 cents per MBTU.

Including the effect .of the fuel adjustment, rates for February of this year were:

7.04 mills /kwh during the 25 lowest cost off peak hours 7.51 mills /kwh during the next 30 lowest cost off peak hours

'- 7.98 mills /kwh during the next 29 lowest cost off peak hours 9.92 mills /kwh for the lowest cost block during peak load hours 10.91 mills /kwh for all additional during peak load hours 13.37 mills /kwh for maintenance energy Duke has contracts with Appalachian Power Company and Southern Services which l provide for short-term power and energy sales. Short-term capacity sold to j the Southern Company is priced at S.30 per kw per week. A second schedule  ;

15-1 e

T, i entitled "Special Short-Term Power" provides for capacity at S.35 per kw per week. The Appalachian contract provides for capacity at $.40 per kw per week.

if Energy accompanying short term capacity sold to either company is priced at

110 percent of the incremental cost to make the delivery.

p Under all of the above rate schedules, increased power sales would be at the

j ,

same rates so that the rate per kw and per kwh would remain constant.

~

Duke has no contracts for power sales to Nantahala Power & Light, SCPSA, or

! SEPA.

i All other systems listed in Question 9 are supplied under Duke Power Company's I~ filed rate schedules 10, 11, or llA. These schedules do not identify specific l rates for capacity and energy. The total rate for capacity and energy expressed as mills per kwh and the total cost per billing period for supply at various loads and load factors are tabulated on the following page. This tabulation shows the downward trend in the rate per kwn for all loads larger than 3,000 kw at 406 or more hours use per billing period. The rates as shown include

. the .5 mill per kwh South Carolina generation tax or the 6 percent North Carolina gross receipts tax, as applicable.

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b 15-2

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'}- SCHEDULES 10, 11, AND 11A POWER COSTS r

Equivalent Equivalent

. Hours Per Hours Per

. Billing MILLS / Billing MILLS /

f. MWD Period $ KWH MWD Period $ KWH

. 1 300 2,250.00 7.5 1 400 3,000.00 7.5 i' 2 4,500.00 7.5 2 6,000.00 7.5 l 3 6,750.00 7.5 3 9,000.00 7.5 4 9,000.00 7.5 4 11,970.50 7.48 p 5 11,250.00 7.5 5 14,770.50 7.38 6 13,500.00 7.5 6 17,570.50 7.32 7 15,750.00 7.5 7 20,370.50 7.27 8 18,000.00 7.5 8 23,170.50 7.24 9 20,250.00 7.5 9 25,958.00 7.21 10 22,500.00 7.5 10 28,745.50 7.18 15 33,750.00 7.5 15 42,683.00 7.11

-r 20 45,000.00 7.5 20 56,620.50 7.07

] 30 67,500.00 7.5 30 84,495.50 7.04 40 90,000.00 7.5 40 112,370.50 7.02 50 112,500.00 7.5 50 140,245.50 7.01 60 135,000.00 7.5 60 168,120.50 7.00 1 500 3,750.00 7.5 1 600 4,500.00 7.5 2 7,370.50 7.37 2 8,370.50 6.97 3 10,670.50 7.11 3 12,170.50 6.76

4 13,970.50 6.98 4 15,970.50 6.65 l

5 17,270.50 6.90 5 19,770.50 6.59 6 20,570.50 6.85 6 23,470.50 6.51

, 7 23,870.50 6.82 7 27,170.50 6.46 l 8 27,170.50 6.79 8 30,870.50 6.43 9 30,458.00 6.76 9 34,558.00 6.39 10 33,745.50 6.74 10 38,245.50 6.37 15 49,933.00 6.65 15 56,683.00 6.29

20 66,120.50 6.61 20 75,120.50 6.26 30 98,495.50 6.56 30 111,995.50 6.22 40 130,870.50 6.54 40 148,870.50 6.20 50 163,245.50 6.52 50 185,745.50 6.19 60 195,620.50 6.52 60 222,620.50 6.18 t_

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15-3 i

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F 1 Ouestion No. 16:

{

r State whether applicant has prepared, caused to be prepared, or received i

engineering studies for generation and transmission expansion programs which

, include loads of each system in Item 9.

~

I

! . Answer:

Duke Power has always included the loads of all of its customers in planning for expansion of generation and transmission. Duke has at various times participated in, or individually made studies which included the loads of r- all systems listed in Question 9 except for those loads of SEPA which are j served by systems other than those listed in Question 9. Duke makes continuing planning studies for generation and transmission expansion which include all

, growth requirements estimated for all of its customers including those which j are served at wholesale rates. (Rate Schedules 10,11, and llA). Duke Power

! Company has at all times been willing to serve all of the present and future requirements of all of its wholesale customers.

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I Question No. 17 List adjacent systems to which applicant has offered to uponsor or to

{

, conduct system surveys in contemplation of an offer by applicant to pur-o chase, merge or consolidate with said adjacent system, subsequent to

'r January 1,1960.

=l.

Answer I Since January 1,1960, Duke Power Company has offered to sponsor or conduct surveys of the following systems in contemplation by Duke to purchase, merge

][ or consolidate such systems:

l The Electric Company r Town of Huntersville i Town of Prosperity

'I Lockhart Power Company

., Pisgah Mountain Electric Company Belton Light and Power Company Town of Ninety-Six Kershaw Power and Light Company

( City of Greenville and County of

j Greenville (Donaldson Air Force Base System)

Greenwood County R.E.A.

Clemson Agricultural College of South Carolina Nantahala Power and Light Company (offer to purchase made 1/31/59) (In connection with this proposed purchase, Duke had accompanying

.{ discussions with the Town of Highlands and Li Western Carolina College covering service to or possible system acquisition if the Nantahala j system was acquired by Duke.)

In each instance listed above, except Pisgah Mountain Electric Company, the

, initial invitation to make an of fer to purchase came 'from the other system to

, Duke Power Company. In the case of Pisgah Mountain Electric Company the initial request to negotiate for the acquisition of tne system came from the titaff of the North Carolina Utilities Commission, which was concerned about st rvice pro-blems being experienced by that distribution system. Since January 1,1960, one or more salesmen in Duke Power Company's Power Sales Department, who make regular calls on Duke's industrial and wholesale customers with respect to re-liability of pervice, increases in customers' demands, etc., may have inquired a of a city electrical superintendent or other city official whether his munici-P~ pality would be interested in selling its distribution system to Duke Power

, Company. However, to the best of the Compary's knowledge and belief, no such inquiry resulted in any surveys or offers L. Duke to purchase, merge or consoli-H . date such systems.

o I 17-1 i

Question No. 18:

.r

)l List applicant's offers or proposals to purchase, merge or consolidate with electric utilities, subsequent to January 1,1960.

Answer:

I Duke Power Company, South Carolina Electric & Gas Company, and Carolina Power J & Light Company each offered to. purchase the rural electric cooperatives in each utility's service area and to lease and operate the State-owned South Carolina Public Service Authority generation, transmission and distribution

{' i system. At various times during the 1960's, there have been proposals con-sidered by the South Carolina General Assembly to make rural electric coopera-tives in South Carolina and South Carolina Public Service Authority, which is the bulk power supplier for certain of those rural electric cooperatives, sub-ject to local property taxation. The companies. mentioned above suggested pur-

._ chase by the three major electric utilities ope. rating in South Carolina as a means of accomplishing this result. The companies' offer was promptly rejected and no further action was taken by the companies mentioned above. Laws taxing rural electric cooperatives were subsequently passed by the South Carolina J General Assembly.

At about the same time, when the issue of subjecting North Carolina electric f nembership corporations to local property. taxatlon was being considered in the j North Carolina General Assembly, Duke Power Cor:pany and Carolina Power & Light Company publicly announced their willingness to purchase all electric member-ship corporations operating in their respective service areas in North Carolina.

The offer was rejected and no further action was taken by the companies. Sub-

+ sequent legislation enacted by the North Carolina General Assembly made all electric membership corporations in North Carolina subject to local property taxation, and provided that the North Carolina Utilities Commission should fix

1. service territories for the electric membership corporations as tcll as the regulated electric utilities. See answer to Question 14 for citation of statutes.

Duke Power Company also made offers to purchase or lease the following systems:

' Nantahala Power & Light Company $4,000,000 (approximately) to be j (of fer - Jan. U , 1959) adjusted for further capital additions i (offer expired after 1960) and retirements and accrued depreciation to the date of acquisition.

1

[_ Pisgah Moun.2in Electric Company 4,000 shares Duke common $252,298 cost of shares l

Belton Light & Power Company 26,000 shares Duke common $1,577,936 cost of shares Town of Nine ty-Six - $751',200 of fer to be adjusted at date of closing .

18-1 i

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l Kershaw Power & Light Company $1,260,161 offer to be adjusted at r- date of closing (payment - 58,639

l shares Duke common)

City of Greenville and $304,280 County of Greenville (Dunaldson Air Force Base)

~

Greenenod County R.E. A. $12,918,176 which includes acquisition of a distribution system, transmission system, 14,000 KW generation plant, and

$2,087,981 in cash and investments.

Duke offered to lease for 40 years at

$250,000 annually the R.E.A. 15 000 KW

,-. hydroelectric plant.

Clemson Agricultural College

$279,068 of South Carolina Each of the systems listed above except Pisgah Mountain Electric Company initially requested Duke Power Company to make an offer to purchase. The offer to purchase Pisgah Mountain Electric Company, a small rural distribution system in Lincoln County, North Carolina, was suggested to Duke by the staff of the North Carolina Utilities Commission, which was concerned with service and maintenance problems

_ on the Pisgah Mountain system.

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o o Question,No. 19: *

• List all acquisitions of or mergers or consolidations with electric utilities by applicant, subsequent to January 1, 1960, including:

a. The name and principal place of business of the system prior to the acquisition, merger, or consolidation;

b. The date the acquisition merger or consolidation was consummated;

c. Cross annual revenue and most recent peak load, dependable capacity and the largest thermal generating unit of the system, prior to the date of consummation.

Answer Electric utilities acquired by Duke Power Company since 1960 and data requested on such u;ilities are:

Revenue of Peak Load Acquisition Adjacent of Adjacent System Location Date System System Genera tion Pisgah Mountain Lincolnton, N.C. 7-17-64 $74,884 (1963) 864 KWD None Electric Co.

• Belton Light & Belton, S.C. 11-13-63 $621,962 (1962) o,810 KWD llydro-electric Power Co. 3-1000 KW 1-500 KW

• Ninety-Six, Ninety-Six, S.C. 10-1-69 $157,479 (year 1,920 KWD None Town of ending 9-30-68)

• Kershaw Power Kershaw, S.C. 8-17-70 $144,507 (6 months 3,960 KWD None

& Light Co. ending 6-30-70)

• City of Grecnville Greenville, S.C. 5-11-64 Not available 3,456 KWD None

& County of Green-ville (formerly Donaldson Air Force Base)

• Greenwood Cou,nty' Greenwood, S.C. 7-1-66 $4,144,375 (year 81,700 KWD 14,000 KW, incl.

R.E.A. ending 6-30-66) one 10,000 KW unit.

• Clemson Agricul- Clemson s S.C. 12-15-64 $62,105 (app.) Not available None tural College of South Carolina

• Indicates that negotiations for acquisition by Duke Power Company were initiated by the system subsequently acquired.

19-1

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