ML20010F223
| ML20010F223 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 09/03/1981 |
| From: | Jackie Jones CAROLINA POWER & LIGHT CO. |
| To: | Harold Denton Office of Nuclear Reactor Regulation |
| References | |
| NO-81-1413, NUDOCS 8109090514 | |
| Download: ML20010F223 (50) | |
Text
f V
t CP&L
[8013 j
c Carolina Power & Light Company C
O h
Ig Q
Q September 3, 1981
=
FILE: UG-3514(B)
SERIAL No.: NO-81-1413 Mr. Harold R. Denton, Director Office of Nuclear Reactor Regulation United States Nuclear Regulatory Commission Washington, D.C.
20555 BRUNSWICK STEAM ELECTRIC PLANT, UNIT NOS. 1 AND 2 DOCKET NOS. 50-325 AND 50-324 LICENSE NOS. DPR-71 AND DPR-62 REQUEST FOR LICENSE AMENDMENTS ADDITION OF CO-0WNER
Dear Mr. Denton:
In accordance with the Code of Federal Regulations, Title 10,
.Section 50.90 and Section 2.101, Carolina Power & Light Company (CP&L) hereby requests revisions to the Operating Licenses for its Brunswick Steam Electric Plant, Unit Nos. 1 and 2.
These changes reflect the
-addition of North Carolina Municipal Power Agency Number 3 (Power Agency) as a co-owner of the Brunswick facilities. The " Application for Amendment of Operating License Nos. DPR-71 and DPR-62 Adding Co-Owner" is attached; in accordance with 10CFR50.33 and 50.33a, it contains the applicable information necessary to determine financial qualification and to conduct tFe appropriate antitrust reviews. A suggested revision to Paragraph 2.A of each Operating License is also attached.
Power Agency is purchasing undivided ownership interests from CP&L in three fossil units (Roxboro 4, Mayo 1, and Mayo 2), Brunswick 1 & 2, and the four units of the Shearon Harris Nuclear Power Plant (SHNPP).
Applications-to amend the SHNPP Construction Permits and the SHNFP Application for Operating Licenses are being filed concurrently with this submittal.
In addition, due to their volume, Exhibits A, B.1, B.2, C, D, E, F, C, and H are being submitted under separata cover (Serial No. : NO-81-1414).
These exhibits are referenced in the attached application.
G}hg 0109090514 810903 PDR ADOCK 05000324 p
PDR ag6 fl \\
~
411 Fayettevilte Street e P. O. Box 1551 e Raleigh, N. C. 27602
y.Y f.i 4
We have determined that the requested changes constitute one Class II amendment and one Class I amendment in accordance with 10CFR170.22.
Accordingly,'our check for $1,600.00 is enclosed.
The agreements which CP&L and Power Agency have executed relating to the sale of generating capacity are conditioned upon necessary regulatory reviews and approvals. It is requested, -therefore, that review of this application be expedited.
Please contact our' staff should you have any questions regarding this matter, j
Yours very truly, J. A. J,nbs Vice Cha rman i
JAM /1r (0581)'
Attachments cc:
Mr. D.
G.' Eisenhut (letter only) i Mr. T. A. Ippolito (letter only)
Mr. J. Van Vliet (letter only) l Sworn to and subscribed before me this 3rd day of September, 1981.
l WW.4't Notary Public
..'."...N My Commission Expires:Oct. 4, 1981 E
3 l
3 ygOTARyi E
( ( #(181. t C j' 3=
......../ t>
00in f / g'?
s.
'soossnnoo t '
l I.
4 OPERATING LICENSE AMENDMENTS The following is a prososed revision to Paragraph 2.A of Brunswick Unit No. 1 Operating License No. DPR-71 to reflect North Carolina Municipal Power Agency Number 3 as a co-owner of the facility:
2.A This license applies to the Brunswick Steam Electric Plant, Unit 1, a boiling water reactor and associated e uipment (the facility), owned by the s
Carolina Power 5 Light Company and North Carolina Municipal Power Agency Number 3.
The facility is located on the Cape Fear River, near Southport in Brunswick County, North Carolina, and is described in the " Final Safety Analysis Report" as supple-mented and amended (Amendments 1 through 31) and the " Environmental Report" as supplemented and amended.
t, The following is a proposed revision to Paragraph 2.A of Brunswick Unit No. 2 Operating License No. DPR-62 to reflect North Carolina Municipal Power Agency Number 3 as a co-owner of the facility:
2.A This license applies to the Brunswick Steam Electric Plant, Unit 2, a boiling water reactor and associated equipment (the facility), owned by the Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3.
Tte facility is located on the Cape Fear River, nr.ar Southport in Brunswick County, North Carolina, end is described in the " Final Safety Analysis Report" as supplemented and amended (Amendments 1 through 29) and the "Enviror. mental Report" as supplemented and ameuded (Supplements 1 through 7).
I
4 i
UNITED STATES OF AMERICA I
NUCLEAR REGULATORY COMMISSION In the Matter of
)
)
Docket Nos. 50-325 CAROLINA POWER & LIGHT COMPANY
)
50-324
)
(Brunswick Steam Electric Plant,
)
Units 1 and 2)
)
APPLICATION FOR AMENDMENT OF OPERATING LICENSE NOS. DPR-71 AND DPR-62 ADDING CO-OWNER Carolina Power & Light Company ("CP&L") is presently the holder of Nucle r Regulatory Commission ("NRC" or "the Commission")
Operating License Nos. DPk-71 and DPR-62 for Units 1 and 2 c' the Brunswick Steam Electric Plant.
By this application, CP&L and the North Carolina Municipal Power Agency Number 3
(" Power Agency") respectfully request that the Commission amend these i
Operating Licenses to include Power Agency as a co-owner of Brunswick Units Nos. 1 and 2, consistent with the agreements between CP&L and Power Agency as hereinafter described.
CP&L will retain exclusive responsibility for the operation and maintenance and the construction of capital additions to Brunswick UnibsNos. 1 and 2.
E
l.-
General Information a.
Name and Address of Proposed Co-Owner North Carolina Municipal Power Agency Number 3 Post Office Box 95162 Raleigh, North Carolina 27625 b.
Description of Business of Proposed Co-Owner Power Agency is a public body corporate and politic and an instrumentality of the State of North Carolina, incorporated i
{
under North Carolina statutes in December, 1976.
Power Agency I
was created to plan, develop, Nonstruct, and opr: ate generation l
and transmission facilities.
Power Agency has been granted all of the powers necessary or convenient to carry out such purposes.
Power Agency has proposed to enter into contreets with thirty-six political subdivisions, listed in Appendix A, under which Power Agency is to be the sole and exclusive bulk powe* supplier for each such political subditrision in excess of any allotment of i
i federal power from Southeastern Power Administration or of the j
i output of any resource such political subdivision may develop 4
and install pursuant to provisions of the Supplementi.1 Power Sales Agreement in effect between Power Agency and such political subdivision.
Each such political subdivision is oblicated to l
take or pay for its entitlement share of power from any owned project, such as the Brunswick and Harris Units.
The terms of said contracts are for the life of the project or so long as any of Power Agency's bonds issued to finance the project are outstanding, i
but not exceeding 50 years.
i c,
Corporate Date Relating to Proposed Co-Owner j
Power Agency is a body corporate and politic and an I
i dwt4_ '
3l090f0/55
_3_
instrumentality of the State of North Carolina created pursuant to the Joint Municipal Electric Power and Energy Act, Chapter 159B of the General Statutes of North Carolina.
Power Agency is not ovmed, controlled or dominated by an alien, a foreign corporation or foreign government.
Power Agency's officepis n,
located at Cypress Building, Highwoods Office Center, Post' Office Box 95162, Raleigh, North Carolina 27625.
The names-,>
and business addresses of Power Agency's Board of Commissioners all of whom are citizens of the United States, are as follows:
The Honorable Simon C. Sitterson, Jr.*, Chairman Kinston Mr. Peter Vandenberg,* Vice Chairman Laurinburg Mr. David R. Taylor,* Secretary-Treasurer Tarboro Mr. Ralph W. Shaw, General Manager Mr. Lamar Hales Mr. Mark A. Suggs Town of Apex Town of Ayden Hon. Ralph M. Wallace Mr. Robie G. Dunn Town of Belhaven Town of Benson Mr. Charles Stewart Mr. James P. Ricks, Jr.
Town of Clayton Town of Edenton Mr. Tommy M. Combs Hon. B. D. Kimball City of Elizabeth City Town of Enfield Mr. J. A. Wooten, Jr.*
Mr. Devone Jones 1
Town of Farmville Town of Fremont Mr. Cn rles O'H. Horne, Jr.*
Mr. W. P. Riley City of Greenville Town of Hamilton Hon. W. D. Cox Hon. R. G. Anthony j
Town of Hertford Town of Hobgood l
Hon. Harry S. Taylor, Jr.
Hon. Simon C. Sitterson, Jr.*
{
Town of Hookerton City of Kinston Mr. Edward B. Walters Mr. Peter Vandenberg*
Town of LaGrange City of Laurinburg l
~
Ms. Lois Brown Wheless Hon. Furman K. Biggs, Jr.
Town of Louisburg City of Lumberton Mr. Russ Conner Mr. Raymond Glover City of New Bern Town of Pikevillo Mr. John McNeill Mr. Ralph Mobley Town of Red Springs Town of Robersonville Hon. Frederick E. Turnage*
Mr. W. Everette Prince City of Rocky Mount Town of Selma Hon. Ferd L. Harrison Mr. Earl Langley Town of Scotland Neck Town of Smithfield Mr. Jonathan Hankins Mr. David R. Taylor
- City of Southport Town of Tarboro t
Mr. Guy C. Hill Mr. D. R. Jones Town of Wake Forest City of Washington Mr. William L. Ross Mr. T. Bruce Boyette Town of Waynesville City of Wilson Mr. T. R. Shaw, Jr.
Mr. E. C. Eines City of Windsor Town of Winterville
- Executive Committee Member f
't O
f 9
.-4
s.
2.
RESPONSES TO INFORMATION REQUESTS OF NUCLEAR REGULATORY COMMISSION STAFF CONCERNING FINANCIAL QUALIFICATIONS OF MUNICIPAL APPLICANT
' NORTH CAROLINA MUNICIPAL POWER AGENCY NUMBER 3 Question 1 Provide a detailed statement of the projected source of funds for ea:h municipal applicant's capital contribution to the subject project reflecting assumptions and detailed explanation.
Response to Question 1 Power Agency's ownership interest in the project will he financed through issuance of tax-exempt revenue bonds.
4 The estimated capital costs, principal amount of bonds required, and assumptions used in developing such estimates are included in Exhibit A.
Question 2 If the applicant is to finance its ownership share with bonds, indicate the source of funds for payms:st of interest charges and principal.
Response to Question 2 PLwer Agency will execute Project Power Sales Agreements with its Participants for the Initial Project which in the aggregate provide for the payment of principal and interest (to the extent not capitalized and paid from bond proceeds).
Each Participant will pay its Participant's Share of the Monthly Project Power Costs which, as defined, include provisions for such principal and interest charges.
. s The obligations of the Participant to make payments to Power Agency under the Project Power Sales Agreement will be an expense of its Electric System, and the Participant will not be required to maka payments to Power Agency except from revenues of its Electric System.
Each Participant will covenant in the Project Power Sales Agreement that it will fix and charge rates for electric service supplied from its
^
Electric System sufficient to meet all of its obligations under the Project Power Sales Agreement and to pay any and all other amounts payable from such revenues including cost of operation and of any general obligation bonds issued by the Participant to finance its electric system.
Exhibit B.1 is a copy of the North Carolina Municipal Power Agency Number 3, Project Power Sales Agreement, Initial Project, dated July 30, 1981.
Section 1(t) therein defines Monthly Project Power Costs.
Additionally, Sections 4 and 6 therein respectively provide for sale and source of and obligation of payments.
Exhibit B.2 is a copy of the Supple-mental Power Sales Agreement dated July 30, 1981 to be executed i
by Power Agency and each Participant.
Question 3 Describe the nature, amount, rating and success of the applicant's most recent revenue and-general obligation bond sales.
Indicate the current total outstanding indebtedness in each category for each entity.
4 Respo,se to Question 3 Power Agency has not heretofore issued any such bonds.
Question 4 l
Provide copies of the official statements for the most recent bond issue.
Response to Question 4 See response to question 3.
Question 5 Provide copies of the most recent annual financial report (June, 1980).
Response to Question 5 Submitted herewith as Exhibit C is the report entitled l
" Audited Financial Statements and Other Financial Information" for North Carolina Municipal Power Agency Number 3, dated June 30, 1980.
Applicants will submit the 1981 financial statement for Power Agency as soon as it becomes available.
In addition, applicants can make available to the Commission copies of the nest recent annual financial statements of the nanicipalities which may become Participants in the project.
Question 6 Is each Participant's percentage ownership share in the facility equal to its percentage entitlement in the electrical capacity and output of the plant.
Response to Question 6-Yes, they are equal.
Question 7 Describe the rate-setting authority of each municipal applicant and how that authority may be used to ensure the satisfaction of financial obligations related to both capital and operating costs of the facility.
Response to Question 7 The authority of Power Agency is set forth in Chapter 159B (Joint Municipal Electric Power and Energy Act) of the General Statutes of North Carolina and in Article V, Section 10 of the Constitution of North Carolina.
In particular, N.C.G. S. 15 9B-ll (14 ) authorizes joint agencies "To fix, charge and collect rents, rates, fees and charges for electric power or energy and other services, facilities and commodities i
sold, furnished or supplied through any project. "
Under the Power Coordination Agreement and the Operating and Fuel Agreement between Power Agency and Carolina Power & Light Company (Exhibits D and L), Power Agency covenants to set i
rates adequate to cover all its costs [ Power Coordination Agreement, Section 26.l(A); Operating Agreement, Section 19.l(B) ].
These obligations are embodied in the agreements between Power Agency and its Participants (Project Power Sales Agreement, Section 6; Supplemental Power Sales Agree-ment, Section 5).
No regulatory approvals are required by Power Agency in setting rates to its Participants.
The Participants, as municipalities of the State of North Carolina, have authority to establish their own retail rates for service to their customers.
In N.C.G.S.
159B-22, the State of North Carolina covenants and agrees that so long as any bonds of Power Agency are outstanding and unpaid, the State will not limit or alter the rights of any participant or of Power Agency to establish, maintain, revise, charge and collect electric rates to fulfill the terms of any agreement for the project.
. 4 Question 8 What is the estimated dollar amount that will be payable i
by the applicant at the date of closing of the sale, and after closing through the completion of the units.
Response to Question 8 Table 5 of Exhibit A
reflects the estimated dollar amounts payable by the applicant for the closings and after closing through the completion of the units (see line 12--
columns (b) + (c) + (d) = closing costs; column (p) minus the sum of. (b) + (c) + (d) = amounts to be paid after closing until the units are complete.
Question 9 Provide copies of the joint ownership agreements.
Response to Question 9
.i copies of the joint ownership agreemer.s are being filed as.a part of this Application.
Question 10 2
If a membership organization is participating in the joint ownership, explain the contractual arrangement among the members that assures that funds will be available to meet the entity's obligations to the project.
Response to Question 10 The member participants will enter into various agreements with the applicant whereby the participant covenants to charge rates sufficient to cover all costs for facilities acquired and services rendered under the agreements.
Please reference to " Response to Question 2",
Lo Exhibit B.1, Section 5(e),
s.
. =
Section 6 (b), and Sections 12 (c) and (d); and to Exhibit
)
B.2, Section 7 (c).
4 Question 11 Explain the procedure to be used by the lead applicant for billing the municipalities for construction progress payments subsequent to closing the sale.
Response to Question 11 Pursuant to Section 6,2 of the Purchase, Construction and Ownership Agreement
(" Sales Agreement" Exhibit F ), CP&L will fur-nish to Power Agency on an annual basis estimates of construc-tion costs for the project and Power Agency's share thereof.
Pursuant to Section 6.3 of the Sales Agreement, on the first day of each month after the first closing CP&L will submit to Power Agency a statement showing the amount due from Power Agency for construction expenditures expected to be incurred in the month next following.
Power Agency's payment will be due on the first of the month following the month of each i
such statement.
When the costs actually incurred in that month become known, CP&L will make an adjustment on the next monthly statement submitted to Power Agency to correct any differences between Power Agency's progress payment and its i
share of the costs actually incurred.
The procedures relating to monthly construction progress payments are fully set forth in Sections 6.2 and 6.3 of the
]
Sales Agreement.
i Question 12 Describe the applicant's plan for financing its share
of the. cost of eventual shut-down of the facility and main-tenance in'a safe shut-down condition.
Response to Question 12 Provisions fer the creation of a Decommissioning Fund have been provided in the draf t Bond Resolution (Exhibit e
G) which is to be adopted by the applicant's Board of Com-
,' e Y
missioners.
In addition, costs of decomniasioning the Bruns-f F
wick and Harris dnits have been included in the Preliminary EnJineering Report of R. W. Beck and Associates as a portion of the project's overall feasibility.
i i
}
i I
4
? * )
l 3.
Information Requested by the Attol/ney General for Antitrust Review
)
, Carolina Power & Light Company ("CP&L") and North Carolina Municipal Power Agency Number 3 (" Power Agency") are applicants for an amendment to the Operating Licenses for Brunswick Steam Electric Plant Unit Nos. 1 and 2 (" Brunswick Units"), DPR-71 (Brunswick Unit No.1, issued September 8, 1976) and DPR-62 (Brunswick Unit No. 2, issued Dece.nber 27, 1974) and the Construction Permits for Shearon Hanris Nuclear Power Plant Unit Nos. 1, 2, 3 and 4 (" Harris Units").
CPPR-158, CPPR-159, CPPR-160 and CPPR-161, esp *
'y (issued January 27, 1978).
Applicants seek to 1ase the Operating Licenses for the Brunswick Units, the Construction Permits for the Harris Units and the application for Operating Licenses for the Harris Units amended to incluce Power Agency as co-owner of the Brunswick Units and the i
Harris Units.
This request is submitted by CP&L on behalf of Power Agency in support of their applications for amendments to the Nuclear Regulatory Commission and in response to the i
information requested by the A orney General for antitrust review pursuant to Title 10, Code of Federal Regulations, Part 50, Appendix L.
1/, 2/
1/
Because Power Agency does not presently own or operate any generating capacity a Td because the capacity which will be available to Power Ageacy through the subject project is less than 1400 MW(e), Power Age;'.cy is not required to submit (Footnote continued on page following.)
g>
+. INTRODUCTION A.
General Background
]
There are 72 municipalities in North Carolina which own and operate their own electric distribution systems.
Thirty-one of these systems are in Carolina Power &
1 l
Light Company's service area; sixteen are in Virginia Electric and Power Company's service area in northeastern North Carolina; and twenty-three of there systems are in Duke Power Company's service area.
The Town of Murphy is served by the Tennessee Valley Authority and the Town of Highlands is served by Nantahala Power & Light Company.
In May, 1975, the General Assembly of North Carolina enacted the Joint Municipal Electric Power and Energy Act, a new Chapter 159B of the General Statutes of 1
This Act provides that municipal electric i
i systems in the State of North Caroline may jointly plan, 4
d3velop, construct, and operate generation and transmission i
j facilities.
The new law provided that municipalities owning i
l (Footnote continued from previous page.)
1 the information requested by the Attorney General descriced i
in 10 C.F.R. Part 50, Appendix L other than the information i
described in Section II, paragraph 9 of Appendix L.
- See, 18 C.F.R.
{50.33(a)(1), (2).
CP&L and Power Agency are, however, hereby furnishing information concerning Power Agency in response to each of the requests set forth in 1
Appendix L for the use of the Attorney General in reviewing this Application.
2/
Certain terms which are used in the narrative text are J
capitalized to signify that such terms are defined terms having specified meanings in the project agreements between Power Agency and CP&L, in the agreements between Power Agency 1
and Virginia Electric and Power Company, or in the proposed cond resolution to be adopted by Power Agency's Board of Commissioners.
i
- i electric distribution systems may create joint power agencies with the authority to issue electric revenue bonds for any projects that they may undertake.
Such agencies are bodies corporate and politic and instrumentalities of the State of North Carolina.
Each municipality joining such an agency appoints a commissioner to serve on a governing Board of Commissioners of Power Agency.
Further, a 1977 amendment to the Constitution of North Carolina permits joint power agencies to participate as joint owners in generating or transmission projects with private utilities and rural electric cooperatives.
Since passage of Chapter 159B, municipal electric systems in North Carolina have formed three joint agencies in order to pursue potential power supply projects.
These three agencies, North Carolina Municipal Power Agencies' Numbers 1, 2, and 3, are organized and have memberships of the majority of the municipally owned distribution systems in the state.
Power Agency Number 1 is composed of twenty municipalities which now purchase their wholesale power supply from Duke Power Company.
In March, 1978, Power Agency Number 1 contracted with Duke Power Company for the purchase of a 75%
ownership interest in Duke's Catawba Nuclear Unit No. 2 and a l
37.5% ownership interest in the support facilities at the Catawba Nuclear Station.
Power Agency Number 1 closed on th ese ownership interests in November, 1978.
Power Agency Number 2 is com; ased of 15 municipalities that purchase their wholesale power supply directly or indirectly from virginia
e Electric and Power Company ("VEPCO").
In the spring of 1980, members o'f Power Agency Number 2 began applying for 4
membership in Power Agency Number 3 in anticipation of i
j successful completion of the negotiations with CP&L for purchase by Power Agency Number 3 of the project and related power supply services.
Late in 1980, Power Agency Number 3 1
acted to include the 14 members of Power Age'ncy Number 2 which sought such inclusion. 1/ At this time, Power Agency Number 2 remains a corporate entity, but its members presently have no plans to pursue projects other than joint ownership of the Joint Units.
Today, Power Agency Number 3 is composed of 22 municipalities that purchase their l
wholesale power supply from CP&L and the 14 members that i
j purchase power either directly or indirectly from VEPCO.
Under North Carolins law, Power Agency may be com-posed only of North Carolina municipalities.
Power Agency i
)
Number 3 was incorporated in December, 1976 after its f
formation by twentv-six North Carolina municipal systems in the CP&L service area.
Since that time, eight municipal i'
systems that are served at Wholesale through other Power J
Agency Number 3 members have withdrawn from Power Agency Number 3 and are expected to continue as wholesale customers 2
of the Power Agency Number 3 members that now serve their 1/
One member of Power Agency Number 2, which is served at I
wholesale by an electric membership corporation, did not apply for membership in Power Agency Number 3.
.. power supply requirements.
Also, four other municipal systems served directly by CP&L have joined Power Agency Number 3.
Power Agency Number 3 currently has as members twenty-two of the twenty-three municipal electric systems that are direct wholesale customers of CP&L in North Carolina, all thirteen direct wholesale customers of VEPCO in North Carolina, and one wholesale customer of a member of Power Agency served by VEPCO.
The thirty-six members of Power Agency Number 3, including the members which receive service either directly or indirectly from VEPCO, will be referred to collectively as " Power Agency".
1/
The municipal electric system served directly by CP&L that is not a member of Power Agency, the Fayetteville Public Works Commission, was invited to join Power Agency in 1976 but elected not to join.
Under North Carolina law, the Fayetteville Public Works Commission, which is the largest municipal electric system in North Carolina, could finance an ownership interest in CP&L generating facilities apart from Power Agency.
B.
The Project and Related Power Supply Program The project, in conjunction with coordinated power supply arrangements, will provide for a long term, all requirements bulk power supply program to meet the power and energy needs of those members of Power Agency which become participants in the project (" Participants").
This long range power supply arrangement includes:
(i) acquisition of 1/
See Appendix A for list of members of Power Agency.
-. =.
e J.
undivided ownership interests in three coal-fired generating units'and six nuclear generating units currently owned and-in operation or under construction by CP&L (the " Joint Units")
for the purpose of providing base load generating resources pursuant to a Purchase, Construction and Ownership Agreement and an Operating and Fuel Agreement; and (ii) the provision 1
of all necessary backstand services for such resources plus
~
supplemental power supply and transmission services pursuant to a Power Coordination Agreement with CP&L and agreements with VEPCO.
Also, through the operation of the Purchased i
Capacity arrangement described infra at pp. 21-22 Power Agency will sell to CP&L capacity from Power Agency's ownership interests in specific generating units in declining i
i amounts over a 15 year period; Power Agency thereby retains increasing amounts of base load generation in each year during the term of the Purchased Capacity arrangement.
The overall result of these arrangements is that Power Agency I
will have available assured power supply and transmission i
resources to provide the total all requirements bulk power 4
j supply needs of all Power Agency members through the year i
2032 or until the last Joint Unit is retired or i
i decommissioned, whichever is later.
The Joint Units include the 650 MW coal-fired Roxboro Unit No. 4, which is part of CP&L's Roxboro Steam Electric Plant, in operation near Roxboro, North Carolina; i
the two 790 MW nuclear-fueled units at.the Brunswick Steam Electric Plant, in operation near Southport, North Carolina; I
l
.. the two 720 MW coal-fired units,at the Mayo Electric Generating Plant, under construction in Person County, North Carolina; and the four 900 MW nuclear-fueled units at the Shearon Harris Nuclear Power Plant, under construction near New Hill, North Carolina.
Power Agency's acquisition of undivided ownership interests in the Joint Units is discussed infra, at pp. 20-21.
~
C.
The Project Agreements The acquisition and use of the project and other power resources, together with delivery of these resources over CP&L's transmission system for Power Agency and its Participants, would be provided for under three agreements between Power Agency and CP&L, copies of which are submitted with this Application as Exhibits E, F,
and G.
In addition, agreements have been entered into between VEPCO and Power Agency (Exhibit H hereto) providing for partial requirements l
l service during a Transition Period (extending from December, 1981 through December 30, 1983), and for transmission and emergency services on a long-term basis.
The various agreements are:
1.
The Purchase, Construction and Ownership Agreement (the " Sales Agreement").
This Agreement provides for: (a) the purchase by Power Agency and conveyance by CP&L of undivided ownership interasts in the Joint Units; (b) employment of CP&L as Power Agency's project nanager for the Construction, Initial Fueling, and placing into Commercial Operation of those of the Joint Units currently under construction; and (c ) monthly payment to CP&L by Power Agency of its share of the Costs of Construction and Initial Fueling of the Joint Units including fees to CP&L as project manager.
2.
The Operating and Fuel Agreement (the
" Operating Agreement"). This Agreement provides for (a) operation, maintenance, and fueling of the Joint Units by CP&L; (b) CP&L's making of renewals, replacements and capital additions to the Joint Units; and (c) the ultimate retirement or decommissioning, by CP&L or a qualified contractor, of each of the Joint Units included in the project at the end of its useful life.
3.
The Power Coordination Agreement. This Agreement provides for: (a) interconnection between the CP&L system _ and the project; (b) backstand provisions, including Reserve Capacity and Deficiency Energy; (c) Retained Capacity from the proposed project; 3
i (d) Purchased Capacity and Energy sales to j
CP&L from Power Agency's entitlement to the output of the Mayo and Harris Units; (e) surplus energy sales to CP&L or others from Power Agency's entitlements to the output of i
the Joint Units; (f) the purchase of Supplemental Capacity and Energy; (g) the purchase of Interim capacity under certain conditions if the completion of a Joint Unit is postponed beyond certain Trigger Dates; l
(h) transmission service; and (i) purchase, i
lease or construction of delivery facilities.
This Agreement includes provisions relating to j
accounting, verification, costing, use of the 3
project by Power Agency, and additional power supply resources that may be constructed or l
acquital for the benefit of the Participants l
of Power Agency.
[
4.
Agreements with VEPCO.
Power Agency and VEPCO have reached an agreement (the " Settlement Agreement") relating to the transfer of all-requirements service from VEPCO to Power i
Agency for those members of Power Agency which i
are currently served by VEPCO and which decide to become Participants in the project.
The Settlement Agreement provides that Power Agency will supply the full requirements of 2
such Participants during a Transition Period through a combiav. tion of capacity from the project, partial requirements purchases from VEPCO at VEPCO's Schedule RS-A rates, and transmission service over the VEPCO system.
t The Transition Period will extend from i
1 1
i
j
.. December, 1981 through December, 1983. 1/
After the Transition Period, Power Agency will
)
provide all requirements bulk power supply to such Participants through a combination of Retained Capacity from the project and purchases of Supplemental Capacity and Energy from CP&L pursuant to the Power Coordination Agreement in the same manner as it would supply Participants presently served by CP&L plus additional transmission services over the VEPCO system.
Such additional transmission services pursuant to the transmission use agreement included in the Settlement Agreement will be provided for delivery of power over the VEPCO system during and after the Transition Period.
Pursuant to Article 2 of the Sales Agreement, Power Agency will purchase and CP&L will convey undivided ownership interests in the Joint Units in increments through separate closings.
The aggregate of the undivided ownership interests in each of the Joint Units Which Power Agency will purchase and CP&L will convey (" Ultimate Ownership Interest") is to be determined by multiplying (i) the ownership interest in each Joint Unit which CP&L has offered for purchase by Power Agency (" Ownership offering") times (ii) the ratio of the projected 1982 Annual Peak Resource Demand contribution of the members of Pcwer Agency Which become Participants in the 1/
In order for Power Agency to begin service in December T981 to those Participants now served by VEPCO in the event there is no first closing with CP&L by the end of that monthj Power Aguncy has agreed with VEPCO and with CP&L with respect to an Interim Period from December, 1981 through the date of the first closing with CP&L.
Under those agreements, the Transition Period arrangement with VEPCO would begin as scheduled and CP&L would sell Power Agency capacity and energy from the CP&L System in amounts essentially equal to those which Power Agency would have received from the project had Power Agency closed on 69% of its Ultimate Ownership Interests in the Brunswick Units and Roxboro Unit No. 4 in December, 1981.
' project to the projected 1982 Annual Peak Resource Demand contribution of all of the members of Power Agency (the
" Commitment Ratio").
The Ownership Offerings in the Joint Units are (i) 19.7% for the Brunswick Units, (ii) 16.5% for the Harris Units and the Mayo Units, and (iii) 13.2% for Roxboro Unit No. 4.
Members of Power Agency may become Participants in the project through the execution of Project Power Sales Agreements and Supplemental Power Sales Agreements with Power Agency, which agreements will be substantially in the form of the draft agreements submitted herewith as Exhibits B.1 and B.2.
To the extent that any members of Power Agency elect not to become Participants in the pro j ec t, application of the Commitment Ratio will result in a proportionate reduction of Power Agency's Ultimate ownership Interest in each of the Joint Units.
Also, in the event that any Mayo Unit or Harris Unit is cancelled or decommissioned by CP&L prior to its date of commercial opera tion, Power Agency's Ultimate Ownership Interest in the cancelled or decommissioned unit and all payment obligations related solely thereto will be reduced by 20%.
Because the aggregate of Power Agency's ownership inter rts in the Joint Units is in excess of its base load requirements in the initial years of operation of the Mayo and Harris Units, the Power Coordination Agreement provides for the sale to CP&L of capacity and energy from Power Agency's ownership interest in each Mayo Unit and Harris Unit
.. (" Purchased Capacity" and " Purchased Energy").
The sale to I
CP&L of Purchased Capacity will be on a "take or pay" basis and will be in declining quantities over a fifteen year schedule which will commence on the date of commercial operation of each of the Mayo and Harris Units. The capacity 1
associated with Power Agency's ownership interests in the
]
Joint Units which is not sold to CP&L as Purchased Capacity, and wh4ch may therefore be used to meet the Participants' load requirements, is Power Agency's Retained Capacity.
Power Agency's Scheduled Retained Capacity Percentage applicable to each Mayo Unit and Harris Unit, and CP&L's Scheduled i
j Purchased Capacity Percentage applicable to each such unit, I
are set forth in Section 5.3 of the Power Coordination Agreement.
The Mayo and Harris Units, including Power Agency's ownership interests in such units, will be dispatched by CP&L as resources available to assist in meeting the combined.CP&L-Power Agency territorial load requirements; therefore, the distinction between Retained Capacity and Purchased Capacity will not affect the operation of those units.
The balance of Power Agency's requirements not met I
by Retained Capacity from the project (or other generating projects which Power Agency may acquire or construct) together with the backstand thereof, will be purchased by Power Agency from CP&L as Supplemental Capacity 1/ and will 1/
Also, during the Transition Period, there would be certain purchases of partial requirements power from VEPCO.
i
. be equal to the Annual Peak Resource Demand (100% peuk load) of the Participants less Retained Capacity.
When Retained Capacity is operating at less than total capability, Reserva Capacity and associated energy purchased from CP&L would be used to meet the shortage.
If shortage still exists, energy associated with Unused Supplemental Capacity purchased from CP&L would be utilized.
If the Resource Demand at any time still exceeds that capability being supplied from the available output from Retained Capacity, Reserve Capacity, and Unused Supplemental Capacity, then Deficiency Energy would be additionally purchased from CP&L and, in some circumstances, emergency power would be purchased by Power Agency from VEPCO.
D.
Power Agency - Municipal Participants 3
Agreements.
Currently, Power Agency's members individually contract with CP&L or VEPCO for the provision by such utility of wholesale power services.
Upon the commencement of the i
provision of services under the Power Coordination Agreement, i
this relationship between the Participants and CP&L or VEPCO will terminate, and a new contractual arrangement will be effectuated between each Participant and Power Agency for the supply by Power Agency of essentially all of the Participant's power needs.
This arrangement will be structured through two power sales contracts: the Project Power Sales Agreement and the Supplemental Power Sales Agreement (collectively, the
.. " Power Sales Agreements").
Under the Power Sales Agreements, Power Agency will be obligated to provide all of the bulk power supply requirements of the Participants.
This all requirements bulk power power supply will be in excess of any allotment of power which a Participant may receive from the Southeastern Power Administration ("SEPA") or certain resources which a Participant may install pursuant to the Supplemental Power Sales Agreement.
The Power Sales Agreements obligate Power Agency to provide two basic types of bulk power supply to the
Participants:
project power and supplemental power.
Pursuant to the Project Power Sales Agreement, project power is furnished to the Participants on l
a "take or pay" basis.
Each Participant convenants in the Power Sales Agreements that it will fix and charge rates for electric service supplied from its electric system sufficient to meet all of its cbligations under both Power Salea Agreements and to pay any and all other amounts payable from such revenues, including it s costs of operation and its obligation to pay principal and interest on any bonds, notes or evidences of indebtedness heretofore or hereafter issued by the Participant to finance its electric system.
.. RESPONSES TO SPECIFIC INFORMATION REQUESTS Question 1 State separately for hydroelectric and thermal generating resources applicant's 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 10 years for Which information is available.
Identify each new unit or resource.
For hydroelectric generating capacity, indicate the number of kilowatt hours of use associated with each kilowatt of capacity during the " adverse water year" upon Which dependable capa-city is based.
Indicate average annual kilowatt-hour loads per kilowatt, associated with each system peak shown (exclusive of interchange arrangements).
RESPONSE
At this time Power 7.gency does not own any generation (either hviroelectric or thermal) resources.
Member municipalities of Power Agency currently purchase all l
of their power supply at wholesale (directly or indirectly) from CP&L or VEPCO except for a small allocation of hydroelectric power received by one member municipality (the i
Town of Louisburg) from SEPA.
Power Agency does not have any present plans for adding generating capacity other than its Ultimate Ownership Interests in the Joint Units.
I.stimated system peak loads, energy requirements, arnual load factor and tota 1' Retained Capacity for the period 1982-2000 are shown in the table on the psge next following.
Also included as a part of this response is a table presented in the Preliminary Engineering Report for the
- project which shows Power Agency's Retained Capacity in each of the Joint Units for the period 1982-2009 (i.e.,
through the end of the period in whict. Power Agency will be selling Purchased Capacity to CP&L based on presently scheduled dates of commercial operation icr the Mayo Units and the Harris Units).
TOTAL POWER AGENCY POWER AND ENERGY REQUIREMENTS (AT GENERATION LEVEL) (1,/)
t Total Annual Peak Energy Annual net.ained Demand Requirements Load Factor Capacity Year (KW)
(MWH)
(%)
(MW) 2/
1982 1,010,528 4,754,648 53.71 381-3 1983 1,054,557 4,961,812 53.71 440.7 1984 1,098,585 5,168,976 53.71 444.7 1985 1,142,613 5,376,140 53.71 522.9 l
1986 1,186,641 5,583,304 53.71 526.9 1987 1,230,669 5,790,468 53.71 53f.7 l
1988 1,274,697 5,997,632 53.71 619.0 1989 1,318,726 6,204,796 53.71 632.8 1990 1,362,754 6,411,960 53.71 706.1 1991 1,406,782 6,619,124 53.71 723.9 1992 1,450,810 6,826,288 53.71 816.0 1993 1,494,838 7,033,452 53.71 838.7 1994 1,538,867 7,240,616 53.71 935.9 1995 1,582,895 7,447,780 53.71 963.4 1996 1,626,923 7,654,944 53.71 991.4 1997 1,670,951 7,862,107 53.71 1,018.8 1998 1,714,979 8,069,271 53.71 1,046.8 1999 1,759,007 8,276,435 53.71 1,070.3 2000 1,803,036 8,483,599 53.71 1,095.2 1/
Values presented in this table are based on the assumption that all members of Power Agency become Participants in the project.
2/
Retained Capacity values reflect the following considerations and assumptions:
(a) Currently scheduled dates of commercial operation of the Mayo and Harris Units are reflected; (b) Reflects current maximum net dependable capability (MNDC) of Roxboro Unit No. 4 of 650 MW; (c) Reflects Scheduled Retained Capacity Percentages applicable to the Mayo and Harris Units pursuant to Section 5.3 of the Power Coordination Agreement; and (d) Resultant MW of Retained Capacity in the Mayo and Harris Units = Ownership Interest x Scheduled Retained Capacity Percentage Y. MNDC.
.t.-..- c... ~. e..... ~....................~-.
-~..2
. ~. ~..
....~8
..gg g~.,g g~-
--....~.
g.o
.R q,
,--g,
,2.
..........~~...
~~........
.3...
E
... --~~--..
8
. ~.. ~.. ~... ~.
R*S.3.~~~Sn 8.
8.
2'2..t
......~...-....
- ~ 3 : 3 3 8.. ~. ~... e. e. s.
--...R.....
E 4
I :L
....... ~.......
" L-R:23:32 *S:3R:2888 r
4 g
3}'..
......~...-....~.
7 Ja t
1.
)~.
. ~. ~~. t ~ ~..-.. 3.......
3
~.
I
~
2
.. ~.. ~... ~.. ~... ~......
2 22 3
R RS 32 *S233:288888 2
~.
4 g
t,
~
2 3
......~...-....~. 2 3
- I
-r t*
g 4
A
.....~~..
..ee.
E a}
e.....-
~~3:2 IF
. E E._._.. R........
f 3
4 1
8 t
....~..~..~..~....c...
5 g c
R:23:32:*S:33:38888888 t
3 A
A 2
2
- x*
1 2 23
..........-.....~.
2--
1. K} "
Ja m....
~
e............~.~.....e.e..e...
a.
~~~3 K 38..--..R-.........
X R.-
.3 E2.
~.
A
..-u
.. ~.. ~.. ~.. ~.. ~..........
1 E. - ~.,g
-5 r
4 RR223:32
- S 3R:3888888888 s h.
i,..
z I
l" 3"'2.q"3 t
2.] j "
i
....~..R J
g..
2
" 8 tt. ;
. ~ ~..t E
..~.~~~.~...................
2...
.3..............
E 3
.I A
1 L
. ~.. ~.. ~...~...............
J2.
" 3 R RS232:*S 3R 3888888888888 3-2
}g sl*y g
g]~E4 * *..~
. t. '
.A3"3;
-..............~. 2.-.....
3 L.
4.Ry 4
t 4
-.~ o r.5 I-.3
~x I
1
.....................o.......
3 2.
.1
..u 3
2-,I.
~
- .}:: :5 E
5-
- 4
..CL**
a I
I.
17 5.I 1
1 I T. 41 S 2222222222222222222222222222 1 C
. 2...E g
.t
....I~.E......E~s.E 8$2 s E.8 8 : I :~
- :: :=
......j.
Ex:
- n :::
t
=
3r.
rw
~
- -- ~~
- Question 2 State applicant's estimated annus1 load growth for each of the next 20 years or for the period appli-cant utilizes in system planning.
Indicate growth both in kilowatt requirements and kilowatt hour requirements.
Response
Power Agency's estimated peak load growth end energy requirements st the generation level are set forth in the response to Question 1.
Power Agency's estimated annual peak load growth and energy regnirements at the delivery point level 1/ for 1981 through 2000 are as follows:
Kilowatts x 103 Kilowatthours x 106 1981 922 4,338 1982 964 4,535 1983 1,006 4,733 1984 1,048 4,930 1985 1,090 5,128 1986 1,132 5,325 1987 1,174 5,523 1988 1,216 5,721 1989 1,258 5,918 1990 1,300 6,116 1991 1,342 6,313 1992 1,384 6,511 1993 1,426 6,708 1994 1,468 6,906 1995 1,510 7,104 1996 1,552 7,301 1997 1,594 7,499 1998 1,636 7,696 1999 1,678 7,894 2000 1,720 8,091 Average Annual Growth Rate (%):
081-2000 3.33%
3.34%
1/ Total delivery point requirements of Power Agency members currently aerved by CP&L and Power Agency members currently served directly or indirectly by VEPCO.
C 4 Ouestion 3 State estimated annual load growth in kilowatts and kl.lowatt hours of companies or pools upon which the economic justification of the subject unit is based for each of the next 20 years or for the period applicant utilized in system planning.
Identify each company or pool member.
~
Response
Economic justification for the subject project is based solely on the growth in native loads on the Participants' systems and Purchased Capacity and Purchased Energy sales to CPkL in the initial years of operation of each of the Mayo and Harris Units
+
1 4
a
. -.- Question 4 For the year the subject unit vnuld first come on line, state estimated annual load growth in i
kilowatts and kilowatt hours of any coordinating group or pool of which the applicant is a member (other than the coordinating group or pool referred to in the applicant's response to Item 3) which has generating and/or transmission planaing functions.
Identify each company or pool member whose loads are indicated in the response thereto.
Response
On July 30, 1981, Power Agency and CPiL executed a Power Coordination Agreement to establish the terms and conditions for provision by CP&L to Power Agency of certain power services and for other matters.
This agreement will be submitted to the FederL1 Energy Regulatory Commission for its approval or acceptance for filing without suspension.
CP&L's projected annual peak demands (in MW, including the demands of the members of Power Agency which are served directly by CP&L and including the demands of Power Agency members now served directly or indirectly by VEPCO) for the period 1981 through 1994 are shown in the table on the page following:
4 d
.. CP&L Peak Demand
'Ibtal CP&L Peak (including demands VEPCO Demand (including of P::wer Agency Sc ' red Memoers' demands of Power members rxx served e ak Demards Agency members ncw directly or irdirectly at the CP&L served directly ce Yecr by CP&L)
Generation Invel (Q indirectly by VEPCD) (1/)
~
1932 6,457 95 (8/)
6.552 1983 (2/)
6,713 138 (8/)
6;851 1984 -
6,982 387 -
7,369 1985 (3/)
7,273 403 7,676 1986 -
7,530 419 7,949 1937 7,8 13 434 8,247 1988 (4/)
8,147 450 8,597 1989 8,469 466 8,935 1090 (5/)
8,727 481 9,200 1991 8,988 497 9,485 1992 (6/)
9,240 513 9,753 1993 -
9,497 528 10,025 1994 (7/)
9,752 544 10,296 1/ Values are based on the asstrnption that all members of Power Agency currently served directly or indirectly by VEPCO become Participants in the project.
2/ Estimated year of commercial operation of Mayo Unit No. 1.
3/ Estimated year of commert-5 al operation of Harris Unit No.
1.
4/ Estimated year of commercial operation of Harris Unit No.
2.
}/ Estimated year of commercial operation of Harris Unit No. 4.
/ Estimated year of commercial operation of Mayo Unit No.
2.
6 7/ Estimated year of commercial operation of Harris Unit No. 3 8_/ Transitior period 4
l 1
l "Dae Agreement for Interim Electric Service betweea Power Agency and VEPCO -- which covers a Transition Period extending from December, 1981 through December 30, 1983 --
provides for the purchase from VEPCO by Power Agency of certain portions of the power requirements of the Participants I
which are now served directly or indirectly by VEPCO and for the furnishing by VEPCO to Power Agency of emergency and 4
econcoy energy services.
The Agreement for Transmission Use and Other' Electric Service between Power Agency and VEPCO l
provides for transmission service over the VEPCO transmission l
system and also for emergency energy services to be rendered i
~
after the Transition Period.
These agreements will be submitted to the Federal Energy Regulatory Commission for its i
approval or acceptance for filing without suspension.
VEPCO's projected annual peak icad (expressed in MW, and shown i
including and excluding the loads of Power Agency's members currently receiving service directly or indirectly from VEPCO) 3 i
I for the years 1981 through 1994 is presented in the table on j
the page following.
i I
i 4
l
.. VEPCO Peak Deands VEPCO Peak Deands (including demands Peak Denands of (excluding demands of Pwer Agency M Agency of Power Agency menbers rm Manbers Nw marbers rm served directly Served Directly served directly or indirectly or Indirectly or indirectly Year by VEPCD) by VEPCD by VEPCO)
Q/)
~
1982 8323 92 (2/)
8231 1983 8330 134 (2/)
8196 i
1984 6634 374 8260 1985 8876 390 8486 1986 9133 405 8728 1987 9405 420 8985 i
1988 9584 435 9149 1989 9715 450 9265 1990 10,020 465 9555 1991 10,315 481 9834 1992 10,621 4%
10,125
~
1993 10,933 511 10,422 1994 11,251 526 10,725 1/
Values are based on the assumption that all Power Agency members currently served directly or indirectly by VEPCO become Participants in the project.
2/
Transition period
O
-e 1
Question 5 l
State applicant's minimum installed-reserve cri-j terion (as a percentage of load) for the period when the subject unit will first come on line.
If the applicant shares reserves with other systems, idet-tify the other systems and provide minimam installed reserve criterion (as a percentage of load) by I
contracting parties or pool for the period when the
-proposed unit will first come on line.
Response
Pursuant.tx) Section 7.4 of the Power Coordination Agreement, CP&L will sell and Power Agency will purchase in 1
i each year Reserve Capacity equal to a percentage of Power j
Agency's Retained Capacity in that year.
The percentage will be based on the percentage reserves maintained by CP&L for l
the Combined System (CP&L's System plus Power Agency's I
project) in the previous year.
Power Agency will receive energy associated with its Reserve Capacity only as it is needed to backstand Retained Capacity.
Power Agency will pay i
CP&L a monthly Reserve Capacity charge for each kilowatt of i
}
Reserve Capacity based upon CP&L's overall average annual production costs and production capability.
f A part of the reserves purchased by Power Agency l
are Spinning Reserves.
Spinning Reserves are reserve capability maintained on the CP&L System as capacity 1
immediately available for rapid increases in load and when 1
cther resources are unavailable due to forced outages.
t 1
4
~.-,
,-s
e 1
i Question 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.u.,
(a) single largest unit down, (b) probability methods such as loss of load one day in 20 years, loss of capacity once in 5 years, (c) other methods and/or (d) judgment.
List contingencies other than risk of forced outage that enter into the determination).
' Response:
As noted in response to Quisstion 5, the level of Reserve Capacity which Power Agency will purchase pursuant to the Power Coordination Agreement is to be based upon the percentage reserves maintained by CP&L in the immediately i
preceding year for the Combined System.
1 l
l l
l t
- Question 7 Indieute whether applicant's system intercennections are credited explicitly or implicitly in establishing applicant's installed reserves.
Response ts :
Power Agency's system interconnections are creditud l
implicitly in establishing installed reserves.
i s
c.
.... Question 8 List rights to receive emergency power and obliga-I tions to deliver emergency power, rights or obliga-tions to receive or deliver deficiency power or unit power, or other coordinating arrangements,*,y reference to applicant's Federal Power Commission (FPC) rate schedules (i.e.,
ABC Power and Light Co.,
roc Rate Schedule No. 15 including supplements 1-5),
and also by reference tc applicant's state commisbicn filings.
Where documents are not on file with the FPC, supply copies, or where not reduced to writing, describe arrangements.
Identify for each such arrangement the participating parties other than applicant.
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 facilities constitute a part.
Response
The Power Coordination Agreament between CP&L and Power Agency contains provisions regarding comprehensive coordination and backstand services sufficient to serve all of Power Agency's needs.
The service agreements between VEPCO ar.d Power Agency (the Agreement for Interim Electric Service 1
and the Agreement for Transmission Use and Other Electric service) provide transmission, emergency and certain other services suitable for Power Acency's needs when combined with 5
the arrangements with CP&L.
I The Power Coordination Agreement provides for:
^
(1) wheeling Power Agency's power and energy from the project; (2) backstanding Power Agency's ownership interest in the project through (a) reserves, and (b) deficiency energy; and (3) supplying Power Agency's requireaents for power and energy through Supplemental Capacity and Energy.
The backstand arrangements are firm as opposed to an "as available" basis.
Because the aggregate of Power Agency's ownership interests in the Joint Units is in excess of Power Agency's base load require..;ents in the initial years of commercial operation of each Mayo Unit and Harris Unit, the Power Coordination Agreement provides for the sale to CP&L of capacity and energy from Power Ag0ncy's ownership interest in C
each Mayo and Harris Unit (Purchased Capacity and Purchased Energy).
In the first year of Commerical Operation of each 4
Mayo and Harris Unit, Power Agency will sell 50% of its entitlement to CP&L as Purchased Capacity, and Power Agency will also sell the energy associated with Purchased C?.pacity.
I The amount of capacity sold to CP&L as Purchased Capacity from each Mayo Unit and Harris Unit will decline over a
~
fifteen year period until, in the sixteenth year of operation of each such unit, Power Agency will retain its entire entitlement in the Joint Unit.
Therefore, in any year Power l
Agency's Retained Capacity in any Mayo Unit or Harris Unit is Power Agency's entitlement less the Purchased Capacity paid for by CP&L.
This allows Power Agency to obtain the economic advantages of having available to it increasing amounts of base load capacity from large generating resources for meeting Power Agency's load.
Also, because Power Agency's cost of capital and carrying charges are lower than CP&L's, the sale to CP&L of Purchased Capacity provides a cargin over
(
Power Agency's costs which contributes to the economic desirability of the project.
l
\\
In addition, Surplus Energy from Power Agency's Retained Ca'pacity in any Joint Unit may be sold to CP&L or to others pursuant to Article 11 of the Power Coordination Agreement.
In light of CP&L's commitment to provide Supplemental Capacity and Energy and wheeling, the Power coordination Agreement imposes certain coordinating require-ments (including reasonable advance notice) on Power Agency's purchase or construction of electric generating facilities other than the Joint Units.
The service agreements with VEPCO provide Power Agency with full rights to use VEPCO's transmission system upon making appropriate compensation for such transmission use including compensation for the cost of any necersary modifica-tions to such system.
In addition, VEPCO will provide emergency service to Power Agency as may be necessary and as would be available.
During the Transition Period, VEPCO will provide additional coordination services including, in particular, partial requirements service.
I
... Question 9
" List, and provide the mailing address for non-affiliated electric utility systems with peak loads 4
smaller than applicant's Which serve either at wholesale or at retail adjacent to areas serwad by t:e applicant.
P; ovide a geographic one line diagram of applicant's generating and transmission facilties (including subtransmission) indicating 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.
Response
At the present time, Power Agency does not generate or sell electric power; therefore, there are no non-affiliated electric utility systems with peak loads smaller than applicant's which serve either at Wholesale or at retail adjacent to areas served by applicant.
4 i
Power Agency does not have any generating or transmiusion facilities and therefore the request for a geographic one line diagram of its existing facilities is not f
applicable.
Thare are a number of electric membership corporations served by CP&L and VEPCO which neighbor the i
members of Power Agency.
Those served by CP&L ares
~_
Brunswick Electric Lumbee River Electric Membe:' ship Corport. tion Membership Corporation P.O.
Box 826 P.O.
Box 830 Shallote, NC 28459 Red Springs, NC 28377 Carteret-Craven Electric Pee Dee Electric Membership Corporation Membership Corporation P.O Box 1499 P.O.
Box 859 Morehead City, NC 28557 Wadesboro, NC 28170 Central Electric Piedmont Electric Membership Corporation Memberc2ip Corporation P.O.
Box 1107 P.O. Drawer 1179 Sanford, NC 27330 Hillsborough, NC 27278 Four County Electric Pitt & Greene Electric Membership Corporation Membership Corporation P.O.
Box 667 P.O.
Box 249 Burgaw, NC 28425 Farmville, NC 27828 French Broad Electric Randolph Electric Membership Corporation Membership Corporation P.G.
Box 9 P.O.
Box 40 Marshall, NC 28753 Ashebcro, NC 27203 Halifax Eleutris South River Electric Membership Corporation Membership Corporation P.O.
Box 667 P.O.
Drawer 931 Enfield, NC 27823 Dunn, NC 28334 Haywood Electric Tideland Electric Membership Corporation Membership Corporation P.O.
Drawer 9 P.O.
Box 158 Waynesville, NC 28786 Pantego, NC 27860 Harkers Island Elect ric Tri-County Electric Membership Corpora 3 ion Membership Corporation P.O.
Box 198 P.O.
Box 130 Harkers Island, NC' 28531 Dudley, NC 28333 Jones-Onslow Electric Wakr4 Electric Membership Corporation Membership Corporation 259 Western Boul'"vard P.O. Box 872 e
Jacksonville, NC 28540 Wake Forest, NC 27587
one municipal electric system is a customer of CP&L but is not a member of Power Agency.
This system is:
Fayetteville Public Works Commission 508 Person Street P.O.
Drawer 1089 Fayetteville, NC 28302
~
Also, pine municipal elect ic systems are wholesale customers of members of Power Agency.
They are:
Customers of the City of Wilson Town of Black Creek Black Creek Electric Department P.O.
Box 8 Black Creek, NC 27813 Lucama Electric Department Town of Lucaraa P.O.
Box 122 Lucama, NC 27851 Town of Macclesfield P.O.
Box 185 Macclesfield, NC 27852 Town of Pinetops Drawer C l
Pinetops, NC 27864 Stantonsburg Municipal Light Department Town of Stantonsburg i
P.O.
Box 174 Stantonsburg, NC 27883 Walstonburg Electric Department Town of Walstonburg P.O.
Box 86 Walstonburg, NC 27888 Customer of the City of Rocky Mount Sharpsburg Electric Department Town of Sharpsburg P.O.
Box 305 i
Sharpsburg, NC 27878
... a Customer of the_ Town of Farmville j
Fountain Electric Department Town'of Fountain j
Box 111 Fountain,-NC 27829 l
Customer of the Town of Tarboro j
Town of Princeville P.O.
Box 1527 Tarboro, NC 27886 An additional municipal electric, system is a wholesale customer of Edgecombe-Martin Electric Membership Corporation:
Town of Oak City P.O.
Box 26 Oak City, NC 27857
)
The electric membership corporations located in i
North Carolina which are served by VEPCO are:
Albemarle Electric Membership Corporation P.O.
Box 69 Hertford, NC 27944 Cape Hatteras Electric Membership Corporation P.O.
Box 9 Buxton, NC 27920 Edgecombe-Martin County Electric Membership Corporation P.O. Box 188 Tarboro, NC 27886 4
Halifax Electric Membership Corporation l
P.O. Box 667 Enfield, NC 27823 3
f
Roanoke Electric Membership Corporation P.O.
Box 440 Rich Square, NC 27869 Tideland Electric Membership Corporation P.O.
Box 158 Pantego, NC 27860 1
}
l d
4
(
i *
- = - - -
... A Question 10 List separately those systens in Item 9 which purchase from applicant (a) all 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 from suppliers other than t3pplicant.
Response
At the.present time, Power Agency does not generate or sell electric power; therefore, there are no systems which purchase all or a portion of their bulk power supply requirements from Power Agency.
1 There are several municipal electric systems which purchase all their bulk power requirements from certain members of Power Agency.
These purchasing municipal systems and the relevant municipal suppliers are listed in the response to Question 9.
e a
Question 11
\\
State as to all power generated and sold by appli-cant 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 pri-mary transmission (backbone) system, (c) at delivery points from 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 4
and kilowatt hour costs divided by the kilowatt-3 hours.
If wholesale sales are made at varying voltages, indicate average costs at each voltage.
Response
At the prasent time, Power Agency does not generate or sell power.
4
)
l l
T
Question 12 State (a ) for generating facilities and (b) for transmission sub-divided by voltage classes, the most recent estimated cost of applicant's bulk pcwer supply expansion program of which the subject cnit is a part, in terms of dollars pur kilowatt per year, in mills per kilowatt hour and in both the kilowatt costs and kilowatt hour costs divided by the kilevatt hours.
Also state separately the most recently estimated cost of subject unit (s).
Response
The Preliminary Engineering Report for the project contains tables providing information responsive to this question.
These tables are provided on the pages following.
Direct costs to Power Agency for the acquisition, construction, initial fuelang and placing into commercial operation of the Joint Units are shown in attached Tables X-2, X-3, und X-4 (lines 1-5).
Tr.ble XI-2, Schedule 1, summarizes project costs by plant including the net effect of credits for Purchased Capacity and Purchased Energy paid by CP&L.
Costs are shown in total dollars, S/kW of capacity, mills /kWh of energy costs, and total cost in mills /hWh.
Also shown are the project Retained Capacity, project output, and capacity factors.
The credit shown for capacity costs in some years reflects periods i
where interest 'is being capitalized rather than paid from revenues; there is substantial interest income from reserve funds and there are sales of Purchased Capacity to CP&L, all
of which exceed Power Agency's fixed coste in those years and contribute to the net savings for those years.
Schedule 2, which begins on page 7 of Table XI-2, shows' the estimated costs of services from CP&L under the Power Coordination Agreement.
Charges in $/kW/yr for Supp2.emental Capacity and transmission service are shown based on the maximum annual demands for each service occurring in the year.
Schedule 3, which begins on page 10 of Table XI-2, develops the total cost of the project and related power f
supply services from the costs shown in Schedules 1 and 2 and shows additional Power Agency costs, including special obligations of the Power Agency members now served directly or indirectly by VEPCO.
The power and energy requirements of the Power Agency members at the generation level of the CP&L System are also included in Schedule 3.
\\
TABLE X-2 EST1 MATED CLOSING AND INITIAL FUELINO COSTS FOR POWER AGENCY'S 01.fNERSHIP INTERESTS IN UNITS IN CoffttERCIAL OPERATION THE BRUNSWICK UNITS AND ROIBORO UNIT NO. 4 [1]
(Dollars in Thousands)
Line No.
Brunswick Units Roxboro Unit No. 4 (a)
(b)
(c) i Estimated Closing Costs 1
Costs as of December 31, 1979 [2]
S199,436
$36,115 Plant Additions Subsequent to December 31, 1979:!3]
2 Direct Casts [4]
24,169 2,542 l
3 Indirect Costs [5]
861 111 q
4 AFUDC [6]
1,796 1,435 i
5 Iax Effects [7]
1.221 652 i
6 Total Estimated Closing Costs
$227,483
$40,855 i
]
7 S770/W [8]
$476/W [8]
8 Total Estimated Costs of Initial Fualing S 16,765 [9]
$ 2,027 [10]
9 3 57/W [8]
$ 24/kW [8]
Total Estimated Closing Costs and 10.
Costs of Initial Pueling
$244.248
$42,882 1
11
$827/W [8]
$500/W [8]
12 Maximum Net Dependable Capability ODIDC)[11]
295.5 W 85.8 MW a
i
' [1] Anahes rower Agency closes on 33Z, 36%, and 31% of its Ultimate ownership Interest of 18.7 of the Btunswick Ibits and 13.2% of Roxboro Unit No. 4 at each of three separate closings accurring January 1 July 1, and December 1, 1982, respectively, and 2002 participation in the proposed Project "oy Power Agen.y Membera.
j
[1] Pursuant to Article 4 of the tales Agreement.
j
[3] Power Agency's share of the cost of plant additions currently scheduled at each facility during the period from January 1,1980, through each closing date as estimated by CP&L.
[4] Direct costs inc.lude materials, labor, and other construction costs.
i
[5] Indirect costs include capitalised overheads such as certain taxes and employe, benefits.
i 16] Power Agency's share of CP&L's estimated AFUDC on plant additions after December 31, 1979 1
and AFUDC on the total Roxboro Unit No. 4 from December 31, 1979 to the date of commercial operation of this Unit.
[7] The estinsted not effect on CP&L's federal and state income taxes, including tax on capital gains, associated with payments by Power Agency for CP&L's AFUDC on plant additions'as pro-vided in the Sales Agreement.
[8] Total estimated cost divided by NNDC as shown on line 12.
[9] Based on CP&L estimates of the net nuclear fuel-in-reactor at Brunswick and reload fual-in-process for use at Brunswick at the closings, including AFUDC and the estimated net effect on CP&L's federal and state income taxes including tax on capital gains associated with payments by Power Agency for CP&L's AFUDC.
[10] Represents Power Agency's share of estimated costs at the closings associated with coal and startup fuel.
l11] Based on assumptions outlined in footnote [1] W*ve and an NNDC of 1580 W for the Brunswick Units and the present rating of 650 W for Rcxboro Unit No. 4.
f e
TABLT I-3 ESTIM4TED CthSINC, CONSTRUCTION, AND INITIAL FUEL.IMG COSTS FDR F0WER ACENCT'S OWNERSRtr INTERESTS IN tREITS UNDER UptSTRUCTrost TRE MAYO ANO MARRIS UNITS fil (Dollere in Thousande)
Fage 1 of 2 Line Mayo 'hatte Rarrie Unite No.
Unit I [2] dati 2~
Total Unit i 12] Unit 2 Unit F Unit 4 Total (e)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(1)
Estlasted Closing and Construction Coster closing Coets: [3l l
Direct Coete 14]
$ 62,590
$ 1,745
$ 64,135
$153,214
$ J2,074 3 7,287
$ 11.462 3 204.03?
2 V4!reet Coste 15) 1.078 50 1,128 5,282
'1,067 173 310 6,832 3
% p nent Fees (6) 929 25 954 2.299 485 110 172 3,066 4
AT M 17l 13,619 539 14,158 46,960 13,574 2.954 5,406 6M.924 5
Tas U fecte 181 9.101 336 9.4?7 29.ItJ 7.930 1.774 3 144 42,016 6
Total closing Costo S 87,317
$ 2,695 T 90,012
$236,923
$ 55,130
$ 12,328
_$ ze, eve
$ 324,875 Construction reste Subsequent to Closingesl91 7
Direct Coete (4)
$ 6.010
$ 91.660
$ 97,670
$ 57,427
$100,097
$216,707
$202,379 3 576.610 g
8 Indtreet costo 15]
416 1,492 1,908 7,501 7,657 15,993 13,951 45,102 g
9 Management Fees 16l 89 1.373 1.462 890 1.530 3.317 3.089 8.826 o
Total Constreetion Coete 10 Sobeequent to Closinge
$ 6,515
$ 94,525
$101,040
$ 65,818
$109,284
$236,017
$219,419
$ 630.538 il Total Estimted Closing and Construction Coete
$ 93.832
$ 97.220
$191.052
$302.741
$164.414
$248,345
$239.913
$ 955.413 12 S/ W [10)
$790
$818
$804
$2,039
$1,107
$1,672
$1,616 11,608 Estimated Coets of fattial Feeltagt 13 At Cloetage [lil 9 1,451
$ 1,451 8 -
14 Suboegrent to Closinge lill 1.511 6.157 7.668 10.143 13.125 41.950 36.392 101.610 IS Total Estimated Coets of Inittel Feeling
$ 2.962 9 6 I57 8 9.119 9 10.143
$ 13.125
$ 41.950
$ 36.392
$ 101.6l0 16 S/W l10)
$25
$52
$38
$68
$80
$282 S245
$171 Total Estleated Coets of closing, 17 Conetraction, and Initle; f=='ing 9 96.794
$103.377
$200.171
_03}2.88j
$l77,539
$290.295
$276.305
$1,057.023 18
$/W [10)
$815
$870
$842
$2.lc
$1,196
$1.955
$1.861 91,779 Erpeeted Mastern Met Dependable 19 Capability (P98DC) in W lit!
118.8 118.8 237.6 148.5 148.5 148.5 148.5 594.0 29 Sche 4: lad Date of Commercial Operetten 4/1/83 4/1/90 10/l/85 4/1/R8 4/1/94 4/1/92 (Footnotae on follmelna paga)
TABLE X-3 Page 2 of 2
' ESTIMATED CLOSING, CONSTRUCTION, AND INITIAL FUELING COSTS FOR POWER AGENCY'S OWNERSHIP INTERESTS IN UNITS UNDER CONSTRUCTION
]
THE MAYO AND HARRIS UNITS a
5 Footnotes
}
[1] Assumes Power Agency closes on 33%, 36%, and 31% of its Ultimate ownership Interest of 16.5% in each of the Mayo and Barris Units at each of three 1
separate closings occurring l January 1 July 1,
and Decuber 1,
- 1982, respectively; 100% participation in the proposed Project by Power Agency j
Members; and the scheduled dates of Commercial Operation as shown on j
line 20.
[2] Amounts for land and common facilities necessary for the operation of each of the Mayo and Eans Units are included in amounts shown for Mayo Unit 1 l
and Harris Unit 1, respectively.
)
i i
[3] Estimated aggregate amounts to be paid to CP&L by Power Agency at the clo-j sings outlined in footnote [1] based on cost estimates provided by CP&L.
1
[4] Direct costs include materials, labor, and other construction cor.ts, j
[5] Indirect costs include capitalized overheads such as certain taxes and employee benefits.
i l
[6] The costs of employing CP&L managers and technicians and utilizing CP&L methods and technical expertise in the construction of the Mayo and Barris l
Units calculated as 1.5% of CP&L's direct and indirect costs of construc-tion less gross investment in land, capitalised property taxes, or CP&L AFUDC.
f
[7] Power Agency's share of AFUDC incurred by CP&L prior to the closing 'daten based on estimates provided by CP&L.
[8] The estimated net effect on CP&L's federal and state income taxes, including tax on capital gains, associated with payments by Power Agency 4
j for CP&L's AFUDC as provided under the Sales Agreement.
1 i
[9] Estimated snounts for Power Agency's share of construction costs subse-j quent to the closings.
i 1
[10] Total estimated cost divided by MNDC as shown on line 19.
)
}
[11] Estimates of costs associated with the Initial Core at each Barris Unit j
based on data supplied by CP&L and costs associated with the Initial Coal Stockpile at each Mayo Unit assuming an average ninety-five-day coal supply based on coal prices and expected usage.
t
[12] Based on assumptions outlined in footnote [1] above and the expected MNDC l
of 720 MW and 900 MW for each Mayo and Harris Unit, respectively.
i l
e I
e TAat2 3-4 TOTAL ESTlat4TED FetNCle% etnetrr OF BONDS ALIACATED TO JOINT FACILitass AND WORKtpC CAPITAL (Dollere to Thousande)
Worhtng Capt*al Total -
Line Grunewtek Reeboro Mayo gette Berrte Dette en6 Pever Agency Proresed 50, Ustto Delt No. 4 Uett I Def* 2 Unit I Ustt 2 Dett 3 Ueft 4 fuyenees
~ Je eet Pr (e)
(b)
(c)
(4)
T)
(f)
(g)
(%)
(i)
(j) tkI Clostag, Cometraction, and Feel Coste I
Clostag and Construction Coote IIT-
$227,4e3
$40,e55
$ 93,s12 9 97,220
$302,748
$:64,414
$24s,345
$239,983
$1i6,277 121 $ 8,531.0%:
2 lettlet Feeling Coste 131 16,765 2,027 2.962 6,157 10,143 13,125 48,950 36,392 129,521 3
Betoed Feel Espense 141 12,597 6,615 15,445 24,992 20,192 79,948 4
Inittet Capital Additione 151 15.378 144 85,526 5
Total Direct Costs
$272,223
$43,030
$ 96,FM
$103,3t7
$319,499
$192,964
$315.287
$296,%e?
SII6.277
$1.756,068 6
Investseet Earninge 16)
(3,333)
(6)
(392)
(10.203)
(6.951)
(12.993)
(30,741) _(23.035)
(92,534) 7
' set Direct Caste
$269,090
$43,024
$ 96,402 9 93,09.
$312,548
$179,998
$284,546
$268,562
$l16,277
$1,663.534 I
8 Cross Interest During Constreetton 171 3 40,326 9 6.447
$ 51,092
$104.193
$343,660
$278,409
$499,426
$456,805
$1.773,358b I
Fleanetna Requiremente Deposite tes 9
Send Fond Reserve Account 141 40,126 6.447 19,223 23,125 81,080 53,952 91.900 85,1 M I4,138 415,306 ID Reeereo end Contingency Fund 191 4,034 645 1,922 2,113 8.102 5.395 9,I90 8,5!
1,485 4I,533 18 Underwriters' Discount and Fineneing Coste (10) 12.831 2.052 6.116 0,07C 27.033 10.525 32,099 29.76f 4,?Of 141,224 12 Total tettested Principal Amoest of Seeds
$366,607
$ 58,615. $174.755
$230,004
$772,361 1529 2 2,
$917,168
$848,769,
$136,688
$4,034,955 lIl free fable I-2, line 6. for Brunestek Unite end forbore Unit No. 4 and free Table t-3, line ll, for Mayo end Hertto Uette.
[2] Frettetnery eetteete of Fever Agency's vorhing espitet ragstrese4te en eeen unit to placed in eeretee me sett se adotalettettee esponees mesociated with unite under eenetraction.
[3] Free Table X-2, line 4, for Brueestek Plant and Rosbere Unit No. 4 and free Table I-3, llee ti, for Mayo and Herrte Unito.
14l Fever Agency's ehere of releed feel payeente through apprestastely twelee unethe following the cleotag dates for the Bruneetch Dette and for twelve Who following the careently schedolet commeretet operetton detes of each Retrie Latt, beoed on eetlestes presided by CFEL, 151 Coets eebeegeent to the electas datee for capital additiesee ender way, mothertred, er planned me of e ete 3stee se eettested by CF6L.
l$1 At lit in 19e2 on unenpended anoonte depostted into the Constreetten Account free Bond proceede and et 182 thereaf ter.
- 17) At ll2 en Sonde leesed te 1992 and 102 en all tende teemed thereafter, Acessee nne year's fended laterest on the portten of each lesse ellocable to the Stonewtek Unite and te Rosbere Unit No. 4 and two years' fended laterest ef ter the currently scheduled commeretet operetten detee of each Meye end Herrte Unit.
l9) Equal to ge:Inve enneet laterest on all Bende loseed and allocated to each Joint Feetitty end to working espitel and Power Agency empenee.
[9] At 102 of the Bond Fond Reeeree 4eenent reqetrement.
Ilil Egwet to 3.52 of the total eettested peinelpel annent of tende.
WORTH CAROLINA MUNICIPAL. POWER AGENCY NUMBER 3 PROTRCTED OPERATING RESULTS UNDRR PROPOSED ARRANCEMENT WITN C P 6 L CASE A SCHEDULE 1 - SUMMAhd OF PROJPCT COSTS DRSCRIPTION 1982 1993 1994 1995 1996 1997 1999 1389 RRUNSWICK NRT CAPACIT1 COSTS e000 (Il e (l.539) e 28.819 e 45,667 e
46,295 e 46,969 e 47.714 8 49,536 e #?,431 W RT EN RRO Y COSTS 8000 (2) 3,579 7,939 9,757 11.242 12,342 13,150 15.336 18,070 TOTAL NET COSTS 8000 (3) e 2,039 e 28,956 e 55,424 e
57,527 e 59.311 e 60.964 e $3,671 o 67,508 NET PROJECT CAP ACITI MW
[4]
159.3 2 95.5 2 95.5 295.5 295.5 295.5 295.5 295.5 NET PROJECT GENERATION CWH (5) 739.1 1.490.9 1,746.1 1,746.1 1,746.1 1,746.1 1,744.1 1.746.1 CAPACITY FACTOR (6) 53.22 57.59 67.46 67.46 67.46 67.46 67.46 67.46 HRT PROJECT FIERD COSTS e/RW (1)
( 9.72 )
11 49 154.56 156.65 159.97 161.49 164.21 167.30 i
NET PROJBCT ENEROT COSTS MILLS
[9]
4.95 5.26 5.59 4.44 7.07 1.53 e.61 10.35 g
TOf AL NEf PROJECT COSTS MILLS
[91 2.16 19.43 31.74 32.95 33.97 34.96 36.46 39.6 6 to 8
HARRIS
- w-NET CAPACITT COSTS 8000 (II) e (6,942) e(17,408) e(21,907) e (42,161) e(62.630) 9(45.545) 9 10,307 e 11.688 NRT ENEROT COSTS e000 (12) 546 t,900
.2.261 4.917 7.090 TOTAL NET COSTS 9000 (13l 8 (6.942) 4(17,406) e(21,907) e (41,615) e(60,930) e(43.285) 9 1$,224 e 18,101 IR.6 74.3 19.2 339.9 168.3 NET PROJECT CAPACITT RW (14]
NET PROJ RCT ORURRATION CNN (15 )
132.8 396.9 468.1 905.9 94P.9 CAPACITY FACTOR (16l 91.67 61.00 67.46 65.91 64.42 NET PROJ BCT r!IED COSTS e/RW (17)
(2,271.29)
(943.50)
(515.07) 73.73 69.99 4.11 4.54 4.83 6.10 7.47 N ET PROJ ECT EN R R0 f COSTS MILLS (IR)
TOTAL NET PROJRCT COSTS MILLS (19)
(313.38)
(153.32)
(92.48) 19s99 19.69 ROI RORO
=-
NRT CAPACITF COSTS SUOO (21) e (432) e 3,320 e 3,791 e
6.971 e 6.964 e
7.086 e
7.164 e 7.262 NET EMERGY CORTS o000 (22) 4.735 7.194 11.148 9,234 12,998 13,330 86.306 12.464
___ - =
m4
$. ~fr
)
TOTAL NET COSTS o000 (23l e
4,303 e 11.084 e 17,922 e 16,105 e 19. 955 e 18,176 e 23,4 73 e 19,726 MRT PROJECT CAPACITF MW (24]
46.0 MS.s n3.9 R5.n 85.8 R5.9 85.8 RS.9 j
p, NET PROJECT CEMRRATION OWH
( ~25 )
235.2 327.2 437.4 327.2 437.4 327.2 437.4 327.2 H
CAPACITT FACTOR (24]
58.41 41.53 59.20 43.53 58.20 43.53 59.20 43.53 Oqg*
to NET PROJ ECT PIERO COSTS e/RW (27)
(9.39) 10.69 79.15 no.O s el.11 n2.12 s3.50 94.64
[*,
NET PROJECT RHMRaf COSTS MI LLS (19l 20.13 23.73 25.47 29.22 29.70 34.02 31.2R 19.10 TOTAI. NRT PROJECT COSTS MILI.S (29)
In.29 33.nn 40.99 49.22 45.62 55.55 53 65 60.J9 m
4 9
e e
NORTM CAROLIMA MUNICIPAL PCleER ACENCY WlGBER ?
PROfECTED OPERATING RESULTS UNDER PROPOSED ARRANCPJtPlf? WITH C PSL CASE A SCNEDULE 1 - MUM 8 TART Of" PROJ ECT COSTA DESCRIPTION 1982 1983 1984 1995 1996 I **
- 1989
' 1999 MATO NET CAP ACITY COSTS 8000
[ 31 )
e (2.254) *(11.010) e (9.926) e 6.270 e 11.7 96 e 11. 36 2 e 10.799 9
6.522 Nf"T ENFRGT COSTS 9000
[ 32 l 4.905 6.139 9.073 8.365 12.319 90.723 17.403 TOTAL NET COSTS 8000 (33l 8 (2,254) 8 (6.105) e (3.781).e 15.342 e 20,16 3 e 23.681 e 21.521 e 23.925 NET PROJPCT CAPACITT MW
( 343 44.6 63.4 67.3 78.3 15.2 19.2 83.2 NP!T PROJECT CENERATION CWM
[ 35 )
22R.2 242.5 343.2 272.8 393.6 30 3.1 424.0.
CAPACITT FACTOR
[363 58.41 43.69 59.20 43.69 52.20 43.69 58.20 NET PROJECT FIXED COSTS e/EW
[37)
(247.15)
(156.65) 93.13 165.51 151.01 136.34 10 43 I
NET PROJECT ENER07 COSTS MILIE
[ 39 )
21.50 25.31 26.43 30.66 32.11 35.39 41.05 tf.
TOTAL NET PROJECT COSTS MILLS (39)
(26.76)
(15.62) 44.70 13.91 61.13 71.00 56.43 4
I TOTAL PROJFX:7 COSTS NETCAPACITYCOfhS 8000 (101) e(11.067) e ( 3. 978 ) e 20.725 8 17.255 a 3.101 e 20.577 e 76.004 e 74.d26 NET ENERCf COSTS 9000 (102l 9.333 20,507 27.037 30.095 35.499 39.959 47.092 55.027 TOTAL NET COSTS 9000 1103) 8 (2.754) e 16.529 e 47.762 e 47.359 e 38.400 e 59.436 el23.Per 9129.853 NET PROJECT CAPACITT MW (104) 204.3 425.8 444.6 467.1 526.8 5 35.7 600 2 632.7 NET PROJECT CPPf ERATION CWM (105l 973.3 2.045.8 2.426.0 2.549.3 2.mS3.1 2.924.9 3.292.6 3.447.0 CAPACITT FACTOR (106) 54.39 54.95 62.29
. 62.30 61.93 62.33 62.62 62.19 NET PROJECT FIRED COSTS e/RW llo7]
(54.17)
(9.34) 46.61 39.96 5.99 39.41 1..' 7. ? 5 lle.26 NET PROJECT ENEROY COSTS MILIE
{109) 8.54 10.02 11.14 11.81 12.44 13.29 a'.30 15.96 TOTAL NET PROJECT COSTS MILLM (109)
(2.83) s.08 19.69 18.59 13.53 20.32 31.6.5 37.67
- ts.4
>W og tr u
OMM C
m e
?
e e
NORTH CAROLIN A MUNICIPAL POWER ACENCY NUMMER 3 PROJECTED OPERATING RESULTS UNDRR PROPOSED ARRANCRMENT WITH C P S L CASE A SCHEDUI.E i - SUMMApr nr PROJRCT COSTS DESCRIPTION 1990 1995 1992 1993 1994 1995 1996
, 1997 BRUNSWICE NET' CAPACITY COST 0000 (1)
- 50.419 e 51.508 e 52.695 e 53.998 e 55.435 e 57.000 e 58.729 e 50.625 NRT ENERCf COSTS 3000 (2) 21.731 27.029 3 3.e 30 36.24T 39.e95 43.466 47.539 51.9R3 TOTAL NET COSTS e000 (3) e 72.150 e 78.537 e es.576 8 90.245 e 95. 330. e100. 4 6 7 e106.269
- 112.60R 9
HET PROJBCT CAPACITT MW f4]
295.5 295.5 295.5 295.5 295.5 2 95.5 295.5 2 95. 5 NET PROJBCT ORNRRATION CWM (5) 1.146.1 1.746.1 1.746.1 9.746.1 1.746.1 1.746.1 3.746.1 1.746.1 CAPACITY FACTOR
[6) 67.46 67.46 67.46 67.46 67.46 67.46 61.46 67.46 NET PROJBCT PI2ED COSTS e/RW (7) 170.65 174.33 178.35 182.76 187.62 192.92 198.17 205.19 I
WRT PROJECT RNRRCT COSTS MILES (el 12.45 15.4s 19.40 20.76 22.95 24.99 27.23 29.77 Ln TOTAL NRT PROJECT COSTS MII.LS (9) 41.32 44.98 49.58 St.sh 54.60 57.54 60.96 64.49 Ln I
MARRIS NET CAPACITY COSTS e000 (11) e 55.930 e 56.333 e 40.039 e 30.293 0 89.239 e123.856 e215.994 9250.605 NRT RNERaf COSTS 8000 (12]
9,696 13,728 23.3R0 29.350 39.416 47.924 57.299 67.045 TOTAL NRT COSTS 9000 (13]
e 65.616 e 70.041 e 63.419 e 59.432 #129.655 8171.779 8273.1n3 e317.651 WRT PROJ RCT CAPACITT NN
[14]
178.1 l#R.I 253.6 297.1 357.6 396.0 415.7 435.6 NET PROJECT GENERATION CMM (15]
- 1. 052.8 1.111.6 1.418.7 1.651.9 2,093.0 2.295.4 2.457.0 2.574.3 CAPACITY FACTOR (16) 67.46 47.46 66.55 65.69 66.92 66.17 47.46 67.46 NRT PROJRCT P!KRD COSTS e/RW (17) 313.95 299.39 151.86 105.45 249.56 312:T7 519.26 575.31 NET PROJECT ENEROf COSTS MILLD (IS) 9.20 12.3%
15.91 17.16 18.93 J0.09 23.32 26.04 TOTAL WRT PROJECT COSTS MILLS (19]
62.32 63.01 42.99 35.49 61.47 14.e4 111.39 123.39 POKPORO NRT CAPACIff COSTS e000 (21) e 7.396 8 7.515 e 7.683 e 7.925 e 8.018 e 8.191 e e.424 e 0,626 WRT ENERGf COSTS e00*
[22l 18.013 14.650 22.570 18.235 24.905 23.404 31.134 25.440
- p;f TUTAL NET COSTS 9000 (23l e 25.409 e 22.165 8 30.253 e 26.060 8 32.923 e 29.5 95 0 39.623 e 34 C66 so ar nH NRT PROJRCT C APACITT MW (24) 95.R 95.8 85.R e5.9 e5.9 R5.3 85.9 85.9 La WRT PROJRCT CE9RRATION CWM
[25 )
437.4 327.2 4 37.4 327.2 437.4 327.2 437.4 327.2
>4 1
CAPACITT FACTOR (26l SM.20 43.53 58.20 43.53 59.20 43.53 59.20 43.53 kg E N
NET PROJECT FIRED COSTS e/FW (27)
R6.20 R7.5n 99.55 91.20 93.45 95.47 99.10 100.53 N
NRT PROJRCT ENRRGT COSTS M ll.l.S (2R) 45.le 44.7R 51.60
'35.74 56.93 65.42 11.32 77.76 TOTAL NMT PROJECT COSTS M*LLS (293 S R.0 9 67.75 69.16 79.65 75.26 90.46 90.54 104.12
.c e
e e
e WonTM CAROLINA MUNICIPAL POWER ACRNCY WUMBER 3 PROJECTED OPEAATING RESULTS UNDER PROPOSRn AnnAMORMENT WITM C P & L CASE A DCMEDULR 1 -
SUMMARY
OF PROJRCT COSTS DESC RI PTI ON 1990 1991 1992 1993 1994 1995 1996
- 1997 MATO NET CAPACITY COSTS e000 1 31]
e 1,519 8 3,344 0 24,062 e 32,843 8 34,495 e 36,211 e 38.030 e 39.990 NET ENERaf COSTS e000 l32) 25.215 34.236 35,757 42,192
,47,143 56,157 41,370 72,684 TOTAL NRT COSTS 8000
[33) e 26,134 e 27,589 e 59,919 8 75,025 e R1,639 8 92,??M e 99,400 0112,674 NET PROJRCT CAPActTY MW
[34) 138.7 154.4 162.4 170.3 11R.2 186.1 194.0 202.3 WRT PROJRCT ORNER ATIDW GWN
( 35 )
561.6 706.0 707.0 714.5 777.7 947.1 549.3 919.4 CAPACITT FACTOR
[ 36 )
48.69 52.19 49.71 52.08 49.92 51.94 49.91 51.99 NET PROJBCT FIRED COSTS e/EW (37) 11.54 21.65 149.20 192.ee 193.58 194.56 195.99 197.69 4
NET PROJBCT ENRROF COSTS MILLS
' 3# l 44.90 48.49 50.59 54.32 60.62 66Jf1 72.34 19.05 Ln TOTAL WRT PROJRCT COSTS MILIA (39) 47.40 53.23 e4.61 96.61 104.99 109.04 117.17 122.55 c) 1 TOTAT, PROJECT COSTS NET CAPACITY COSTS e000 (1981 0115,265 0118,480 8124.480 8124,949 8187,197 e225,258 8321.068 8359,846 NET ENERCf COSTS 8000
{102) 74,645 89,642 115,5e7 125.013 151,360 165,951 197.406 217,153 TOTAL NET COSTS 9000
[103) 8199,910, 8209,322 e240,067 8249,963 e3 38,5 47 e394.209' 8519,474 e576,999 NET PROJBCT CAPACITF MW (104]
691.1 723.0
- '7. 3 939.6 917.0 963.4 991.1 1.019.2 NET PROJECT ORWERATIDW OWN
[105) 3,799.0 3.8 90. 9 d
69.2 4,503.7 5,054.2 5.215.9 5.499.9 5.567.0 CAPACITY FACTOR 1
.(106) 62.74 61.37 62.56 61.28 62.92 61.90 43.22 62.36 prr PROJBCT FINED COSTS e/tw
[107) 166.79 163.97 156.13 149.99. 204.12 233.92 323.97 353,09 NRT PROJ ECT RNRROf COSTS MILLS
[106l 19.65 23.04 26.45 27.77 29.95 32.99 35.96 39.01 TOTAL NRT PROJRCT COSTS MILLS (109l 50.00 53.54 54.94 55.53 66.98 75.58 94.46 103.65 4 el D D s.o U"
g.
> H O F4 t;
NORTH CAROLIN A MUNICIPAL POWER ACENCY HUP 4.4 3 PROTECTED OPERATINC ARSUI.TS UNDRP PROPOSED ARRANCRMRNT WITH C P S 1.
CARR A SCHEDtJLR I -
SUMMARY
OF PRCJMCT COSTS DESCRIPTION 1999 1999 2000 2001 2002 2003 BRUNRWICR NET CAPACITE COSTS 8000 (1) e 62.104 9 64.990 e 67,495 e 70,230 e 73,242 e 76.555 NRT RWERGT COSf3 e000 (2) 56,609 61,924 67.602 73,912 80.801 BR 309 TOTA!.,NRT COSTS 8000 (3) 8539.312 el26. 90 3 4835,087 sh44,142 el54.043 9164,965 NET PROJECT CAPACITT MW (4l 2 95.5 4f5.5 2 95.5 295.5 2 95.5 295.5 N RY PROJECT CENERATION CWM
[5]
3.746.1 8.746.1
- 1. '.'4 6. 5 1,746.1 1,746.I 1.746 1 CAPACITT PA CTOR
[6]
67.46 67.44 47.46 67.46 67.46
$7.46 WRT PROJECT FIRED COSTS e/RW (7) 212.22 219.93 229.41 237.79 247.89 259.11 g
NET PROJ ECT ENRRGT COSTS MILLS
[8) 32.42 35.41 79.72 42.33 46.28 50.58 TOTAL NRT PROJRCT COSTS MILLS
[9]
48.J3 72.62 77.37 82.55 89.22 94.42 L]
I MARRIS NET CAPACITY COSTS 8000
[Ill e267.769 0280.271 8293.574 8307,220 8339,428 e332.084 NET EREROT COSTS 8000
.[12) 77,622 90,005 104.791 120,165 136,699 154,923 TtffAL NET POSTS e000 (13l 8345.391 e370,276 8397.865 0427.385 e456.125 e486.907 NRT PROJECT CAPACITI MW
[14) 455.3 475.2 4/5.4 514.8 5J0.3 544.5 NRT PROJRCT G ENERAT?ON OWN (15]
2,691.0 2.909.3 2.929.0 3,042.3 3,133.1 3.217.9 CAPACITT PACTON (16l 67.46 67.46 67.4R 67.46 67.47 67.46 NET PROJECT FIXED COST 9 e/RW
[17]
588.05 589.90 592.64 596.79 602.62 609.89 NRT PROJ ECT RNRROF COSTS MILLS
[19) 29.84 32.05 35.62 39.50 43.63 en.lt TOTAL N ET PROJECT COSTS MILLS (19) 129.35 131.95 135.98 140.49 145.58 151.31 ROXbORO NRT CAPACITY COSTS 8000
[21]
e 8,911 8
9.151 e 9,494 e 9,7e5 e 10,131 e 10.532 NET ENERGT COSTS 8000 (22l 37.0P2 30,239 44,076 35,940 52,398 42.739
=
- ts e4 TOTAL NET COSTS 8000 (23) e 45.993 8 39,3R9 e 5 3,5 69 e 45,725 e 62,575 8 53.250
$h i
e
>d NRT PROJECT CAPActTT MW (24) es.n 85.9 e5.9 85.8
- 5.8 95.8 (n
NRT PROJECT ORNRRATION CNN
[ 25 )
437.4 327.2 437.4 327.2 437.4 327.2 CAPActTF PACTOR (24) 59.20 43.53 59.20 43.53 58.20 43.53 gl*
O N
NET PROJ ECT PIERD COSTS e/FW
[27' 103.R6 106.65 110.65 114.04 119.73 322.75
((
NET PROJ ECT ENERGY COSTS MILLS
[293 94.77 92.42 100.76 109.R5 119.76 130.57 TOTAI. N RT l'ROJECT COSTS MILLS
[291 105.34 120.39 122.44 139.75 143.05 162.16
m e
e NORTH CAROLI 2A MUNICIPAL POWER AGRMCF MUMBER 3 PROJECTED OPERATINC RMSULTS UNPER PROFOSED ARRANORMRUT WITN C P & L CASE A SCHEDULE 1 - SUMMART OF PROJECT COSTS DESCRIPTION 1994 1999 2000 2001 2002 2003
=
MATO NET CAPACITF COSTS 9000 (31]
8 41,933 e 43,406 9 44,999 e 46,676 e 48,462 8 50,405 NET ENRROY COSTS 8000 (32l 79,277 93,151 99,546 111,957 322,25e 137,333
=
TOTAL NET COSTS 8000 (33]
9121,210 8134,558 si43,545 8158,534 e170,720 ele? 539 NET PROJECT CAPACITT MW
( 34 )
209.9 213.8 217.8 221.9 225.7 229.7 NRT PROJECT ORNERATION OWN
( 35 )
939.0 964.5 959.4 994.3 999.8 1,029.5 CAPACITY FACTOR
{ 36 l 49.99 51.69 50.29 51.39 50.56 51.12 I
NET PROJ ECT PIRED COSTS 9/RW
[ 37) 199.79 202.94 206.63 210.48 214.70 219.46 NET PROJ ECT ENERGY COSTN MILLS
{ 36 ]
- 6.26 94.16 102.72 112.05 122.28 133.33
[y TOTAL WRT FROJECT COSTS MILLS (39l 131.89 138.99 149.62 159.90 170.76 132.34 1
==
TOTAL PROJMCT COSTS NET CAPACITY COSTS 9000
[201l 8301,317 8397,907 8415.552 9433,911 e451,318 8489.576 NET ENEROF COSTS 9000 (102l 25n,5 90 273,219 384,534 341,974 392.146 422,984 TOTAL NRT COSTS 8000
{103) e631,907 0671,027 9730,047 8775,795 se43,464 9992,560 NET PROJBCT CAPACITI MW
{104) 3.046.5 1,070.3 3.094.4 1,317.8 1,137.0 1,155.4 N RT PROJECT CR4RRATION CNN
[105]
5,793.6 5,849.7 6.071.0 6,113.9 6,316.4 6.319.6 CAPACITF PACTOR
{l06) 93.20 62.39 63.32 62.44 63.41 62.44 NET PROJBCT PIRED COSTS e/RW
{l07l 364.39 378.68 379.70 399.18 396.92 406.40 N RT PROJBCT ENRROY COSTS MILLS
{100l 43.25 44.71 51.91 55.92 62.00 86.93 TOTAL NEF PROJRCT COST 1 MILLS (109) 109.07 114.71 120.25 126.83 133.54 141.24
- s. Y 5 a R
NkY u
-~
- -.-.~-_-- -...
i
'T r
e a
e MORTM CAROLIWA MUNICIPAL PONRR ACPJtCI WUMBRR 3 PROJ2CTED OPERATING RRSULTS UNDRR PROPOSPD ARRANORRENT WITH C P & L CASE A SCMEDULE 2 - PARTI AL REQUIREMRNTS PURCNASES PROM CPSL 4
DESCRtertoW 39e2 19s3 19e4 1945 19e6 19ev 19ee n989 1990
- 1. SUPPLEMENTAL POWER SUPPL EMENTAl, ~.ef!M AND FWI (111l 806.2 628.7 654.0 675.5 659.9 6 95.0 674.4 696.0 611.7 COST e/KW/TR [332) 55.97 59.56 68.00
- 69. e ?
1d2.3R 99.23 133.96 115.64 119.14
%PACITT COSTS e000
{113l 845,042 837.450 839.991 e47.12e & 47.426 8 6e.959 e 76.859 e 19,326 e 90.053 SUPPLEMENTAL ENERO!
UWM
{184l 3.359.2 2,In4.6 le779.4 2,034.9 1.997.6 3.909.9 1.776.3 1,445.3 1.434.0 COST MILLS (115) 15.01 16.65 19.36. 20.20 21.05 22.32 22.77 26.03 29.17 t
ENEROf COSTS 8000 (1863 e50,431 83r,3m3 e34.457 e40.70s e 42,051 # 40.391 e 39.307 e 37,623 e 4 3.9 30 TOTAL SUPPLEMENTAL COSTS 8006 (1173 895.452 873. e 35 874.34s es1,936 e109,477 e109.350 0116.166 e116.949 e121.pe3 I
- 2. PROJECT RESERVE SRRVICE w
RESERVE CAPACITT MW (lle) 47.e 90.6 109.1 92.2 7e.7 119.6 107.4 149.7 130.6 W
CCST e/KW/fR {3193 54.17
. 62.30 66.62 19.91 113.17 113.31. 128.53 137.46 141.34 g
CAPACITT COSTS 8000 1820) e 2.592 9 's,025 e 7.269 8 7,365 e.e,907 e 13.549 e 13.802 e 20.500 e 18.461 RESERVE ENEROf OWN
{l21) 420.7 106.8 955.e 907.6 689.4 1e047.4 948.1 1, 30 6.4 1.144.5 COST MILLS (122l 15.01 16.65 19.36 20.20 21.05 22.32 22.77 26.03 29.17 RESERVE RfLEROY COSTS 8000 (123l 8 6.314 011.772 ele,500 e16.319 e 14.513 e 23.375 0 21,425 8 34.000 e 33,396 DEPICIENCf EN ERef OWN (1243 2.5 24.5 7.7 4.4 43.2 4.2 37.7 6.1 35.5 COST MILLS (125 )
20.93 22.95 26.53 27.87 31.79 33.57 36.00 41.92 45.97 DEPICIENCf ENRROf COSTS 8000 (126l 4 51 8 562 e 205 e 128 e 1,373 e 276 9 1.3e6 8 257 e 1.6 31 SPINNINO RESERVES MW l127) 9.7 20.2 23.1 22.2 25.0 25.4 29.5 30.1 32.e "OST MILLS (1283 14.12 15.29 15.14 16.93 18.74 15.50 20.se 28t07 24.13 SPINN!No RESERVES COSTS 8000 (129l 9 120 e 271 8 291 e 329 e 411 0 414 6"
522 8 555 e 694 TOTAL RESRRVR COSTS e000 (130) e 9.078 017.630.926,263 824.137 e 25.204 e 37,614 e 3f 137 e 55.320 0 54.171
- 2. TRANSMISSION MERVICE CAPACITY hk REMRIt?S not (1 31 I.010.5 1,054.6 1,098.6 1.142.6 1.186.6 1.2 30.7 1,274.1 1.318.7 3,362.s e/RW/TR (132{1 12.46 13.69 15.60 te.?O 21.92 22.87 22.se 23.00 23.24 CDST C APACI?! COSf8 8000 (133) el2.595 014,434 e;7.134 e 21.5 95 8 26.016 8 29.150 0 29.167 8 30.334 e 31,675
- _= __-
n TOTAL TRAWOMISSIOW SEftVICE 8000
( 137 3. m12.595 814.438 817.134 821.595 8 26,036 e 2a,150 e 29,167 e 30,334 e 31,8 75 es tr e >*
TOTAI. PARTI AL RROUIREMPJi?S
-4 n FINED COMTS e000 l139) 060,2Je 956.909 064,294 e 16, f'e 9 e102.34n el10.658 el19.029 e130,160 8130.189 k7 i
VARIABLE COSTS e000 l139) 56.896 44.990 53.459 57.4#0 54.344 64.457 62.642 72.442 77.540 N
'i t:
TOTAL 8000 (140l 117.125 105,R99 117,144 131.5sn 160.697 175.115 192,470 202.603 207.730
~. _ _. -
- - ~
-..~... ----.. -.
' ~1 l}
)
1 l
NORTM CAROLINA MUNICIPAL POWER ACENCf MUMMER 3 PROJPs*TES OPERATINO RMSULTS UNDER PROPOSES ARRAPOEMPWT WITN C P S L CARE A MCNRDULE 2 - PARTI AL REOclREMENTS PURCHASES PROM CPSL DESCRIPTION 3991 1992 1993 1994 1995 1996 1997 1994
- l. SUPPLEMENTAL POWER SUPPLEMENTAL DEMApp MW
[Ill) 693.0 653.6 456.2 621.4 619.5 635.9 458.s 66#.5 COST e/RW/TR {1123 119.47 139.30 140.72 156.34 155.03 151.26 170.61 198.11 CAPACITY CONF 5 0000 Ill3) e 90.9th e 9 8.0 37 8 97.340 e 97.214 9 96.041 e 96.194 8111.201 8132.035 SUPPLEMENTAL ENER07 OwM
[314) 1.235.7 1.019.3 116.5 513.2 299.7 443.6 642.4 559.7 COST MILLS
[115l 32.99 34.03 36.42 37.01 40.57 44.94 49.91 55.39 RNER'IP COSTS 9000 (116) e 40.640 e 34.695 e 26.097 e 19.994 e 12.16I e 19.n90 e 32.063 e 31.005 TOTAL SUPPLEMRWTAL COSTS 8000 (117) 0121.551,8125.722 #119.437 ell 6.207 8109.202 0116.014 e143.263 8163.936
- 2. PROJECT, RESERVE SERVICE RESERVR CAPACITT NW (118) 167.5 156.2 214.1 202.9 266.4 229.2 197.9 217.4 Q
COST e/RW/TR (1893 146.66 173.29 194.45 20s.96 222.90 224.93 251.16 2e5.05 8
C APACITY COSTS 0000 (120) e 24.606 e 27.066 e 39.491-8 42.347 e 59.375 8 51.330 e 49.710 e 62.131 RESERVR RNER0f 04M
{123) 1.469.7 1.369.4 1.161.6 1.629.2 1.918.7 3.698.2 1.564.2 I.643.8 COST MILLM (122) 32.FA 34.03 36.42 37.01 40.57 44.94 49.91 55.39 RESERVE ENBR0f COSTS e000
{l23) e 40.J36 e 46.563 e 44.161 0 60.294 e 17.942 e 75.701 e 18.067 e 91.014 DRFICIRNCI RWRROf CNN l124l 22.9 49.3 53.7 44.0 13.5 nl.3 98.6 12.9 COST Ml f.LS (125 )
49.59 52.04 56.26 60.97 67.44 73.90 90.53 87.62 DEFICIENCf EWRR0f COSTS 8000 (126) e 1.1 32 e 3.607 9 3.020 e 2.619 8 913 8
- 2. 5 31 e 7.132 0 6.399
!! PINNING RRSRRTRS MW (127) 34.4 37.9 39.9 43.6 45.9 47.1 49.4 49.7 COST MILLS (12WI 25.62 29.63 31.42 35.55 39.90 45.41 50.27 55.52 SPIWWING RRSMRTRS COSTS 9000 (129) 8 772 8 950 e telle 8 1.357 e 1.599 e 1.991 e 2.132 e 2.41e TOTAL RESRRVR COSTS 8000 (130 ) e 74.e46 e 79 195 e307.192 8806.496 el39.730 e131.458 8137.040 8861.991
- 3. TRANSMISSIOW SWRTICR
\\
CAPActTF RROUIRINIRWTS MW
.(1313 1.406.e 1.450.9 1.494.9 1.53n.9 1,Se2.9 3.626.9 1.671.0 1.715.0 d
COST e/RW/TR (132l 23.53 23.79 24.03 24.37 24.68 24.94 25.05 25.26 CAPACITT COSTS e000 (133l 0 33.079 e 14.513 8 35.922 e 37.500 e 3#.957 0 40.406 9 41.e42 e 43.385
'W *1 TOTAL TRANSMISSION SRRVICE 8000 (127) e 33.078 e 34.513 0 35.922 e 37.500 e, 39. 95 7 9 40.406 e 41.942 e 43.385 Mh av*
TOTAL PARTIAL RROWERNRNTS m
>4 FIREO COSTS 8000
[13el e139.5 95 0152.413 e167. 75 3 et17.Ont e194.313 e197.929 0202.113 e 2 39. 29 8 k7 VA pt AMLE COSTS 9000
{139l 90.990 95.905 94,199 W3.122 92.586 100.003 139.393 130.920 M
TOTAL 4000 l140l 229.414 234.41#
2F2.141 240.403 204.pn9 297.931 322.166 369.301 4
i Table XI-2 e
P g2 9 cf 15 61 -
R l
l I
m
," w M
. O sa m
. w an MOO wmW m y, M w
.O..
e3 i O
eee o en en w
ewm
- yi M e9m o en m M
e O en en r= w 0 es em O
m
- 8%
f*
- F*
P M =m M
- as w em e e se m
p ew gy Mm f=
A M
p* M e pg M e e
as W e MM e mea yt yt e e
me e e
o e o
y P= 0 to m 36 w m
MMM P m se se m B 9w w
mMO O
OO O
f'l MM e
M wm e
e se se f*
e et en EP en M.
- m. M es l'W i m as g
[
M.
s.e E
he Me'O E
M OMN MPS m
== P O OPG wwe O m yt i O ee w e llO Mt DEJ E
O e O==
we e
- w==
- av m oOM e en
- 8M e S se ll es
'M EE W
c w ew 0 eO gg E eS S ee m oa w e P= { ft me ee m
we E
wy e PW e w en e et et e s e ae e a
e e e
O es E
N en O e ww e
=
D* E aC P f* m eST f=
fg us S S.O M f*
Pm 84 SME E
a= w m
U D to C
l MO yt yt mm e
et ao e
= w g
en N P*
l s.et M i' 5" E
D M
M.
se r.g s.e se
. s.
I ECD E
Ob D
aC *J E 6.
O>
=
MP*
f* w w Gi 9 yt 9*
Oww me w P es S O e
me M m I m
en q,
==
L SC *e 80 O
- m e== S se
- M e me 96 evw
- 9e en
- P es L es p*==
m 9 eM M em to e se m em f*
f*
e et yg e em - r W ed E to o
e o em P e we m.
== 0 e meo Owe yg M e
=
w en o e
e e e
yE E
N MM e mee O
b M
P tD M f* f* W S
M9m P= F* **
es se M pm P O
9 ft P f*
MM tlP Sm O & aC E
Nm yt w
mE o
m en se M
e w w
MC f4 I
EW E
M.
- m. M se i yt M
as s.o e.m t
e3== E E E
aC > M R w
k at O aC me E E U O
w F* St 96 OP ys O M se M O yn yn m O OMP fM O f* e w
wS T
U E *C O
e en en o en en se e w es e yi e e en es e se en M
e et m es ee m
- b E E
C E
- M P *w 8
- M w
- en O ew M
- O O
M *c 0
if* m O
E PS
- ww e yt P*
O yt e e
o e o
EOE s1 OP =
St G e e
me g m D
aC e3 f* M se f= w w yt f.g g gg W e
em g
wwO se O w wm EO at M 19 yn as Mw e
e se se e
w er p* gm tw K f.
ee se M es tw
.M s.e en
==
at M
De 4
8 E
LC E
== 0 at eJ *) k 8.
m p6m yt m W O
MMm o gg a M gi et am3l3 O M wi vi
.e gg m
O es i O e e se
==
eg es OOO m
eem
- r= c si eMP e f= O e et O
- em O e r*
m e se O e t=
f*
- e f=
7" wm.
en e
EEe i
en E
- yl m ea M.
a yt pd e a se e yn yt a yg se e e
p pg.
e e
o, e
aC 8e 8.
an eM e e se e U
M tr O m w w 96 96 fe O P ewe og yt e go em
- p. pg g my so w y-MM M
w P1 f*
O e
w w
te ys se
[
5, a.
a.-.'-
O O
t E
g
==.e
.e e.
ame a.
=
ese een a.
,e
.es
.o es. e==
1 E
se M M w yt w P*
S&O em M M w in w f* E St O
es M m f*
y en e t.*
ao se se se se es se as M M MMM M M f4 MMM e
m et m m
.e m w
E se as se en se es se se se se se we em se en as se em se se se se se me o es se 3
a=== e.
ese wme e-meme==
e-== en ese e..e me een en e.
wee e.
. e, e.
E E
E a
en ne me j
M C
E E
EO e3 O O
EO 3O ma O JO O
EO O
OO e
i es O E.3 O O
MC E m3 O E eJ O e3 O O
es O O
OO O
W%
B *e O O.
E%.8 EenO E em O
.O E%8
.O 2.O
.O B== 0 E.E E.
DE.
E.
E.
E E
U P
E M.
E E
E
~
E E,
=.
E E-E E. El U
U E
E E
O E
O E
E R
Ui E
ar at E
m3 a:
O se
>m E
b es E
E at.
m h
U O O
E E
E D
. E O
E E
E 9
k E
E D
O E
E ee 3
E E
O O
E E
E E
- e
'N E
E k
H U
E An k
W U
k O
F E
E E
E
, se O
eJ R
+3 4 g E
at C
E E
E E
m E
C t
E l
==
e2 4 De
.3 at O
aC P
m W
O E
E E D E
O E
aC c
aC k
U Se m
eJ to at U
E E
E E
E O
E U 8) y: 0 to E
E O
E E
U E
E U
U W
w a
k
>U R
W to N
U 61 Eg en E
3 O
O g g
>=
to et E
g i
E N
E to D
I RR H E E
E as E
E E
E k
pm a
at OE E
= m b ee en ee me
==
E
=
= - e a.
U ma i
o e
E ee
==
W eJ H U eJ U
EkV E L* E U D= U RHE E 4Ubu E
- a. b O mE m3 e
W W aC E r. E os m M r to a e3 C 3 aC en aC m2
.2 e aC.
- a. O at.
to
.2
=
&Oe kOM st of e o a.
EOm
- 4. O b ee 0 es at y a te, O an at aC W.
at i
se a.
[
h D D at DUE k
O E D aC EUE E U aa
& D a.
to at 4 aC U aC to e
ME pm i
ee E s D
R U
M N
O E
E U
E E
D A E M
O E tU U O
Oil ** as O 80 H
A. i
> > 4 b
b II he > b j
g
=
e A
es te m
i
.m
- p..
m
,s O
WORTM CAROLIWA MUNICIPAL POUTER AGENCf N'
- RR 3 FRtifRCTED OPERATINO PR90LTS UND h PROPOSED AnitANCEMENT WITP C P S L CASR A SCMRDULR 3 - TOTAL AGENCY COSTS RESCRIPTION 1982 1983 19e4 1995 19es 1997 1998 1999
~
ADSiTIONAL AOPMCI COSTS A0thCI A 8 0 EXPRWSES 8000
{151)
- 2,072 8 2,259 e 2.462 e 2.an3 e
- 2. 925 8 3.190 8
3.475
- 3,1ee DERT SERITCE -
WORRINO CAPITAL 0000
( 152 I
. 1.337 2.880 3,091 3,289 4.015 4,980 S.177 4.244 SUBTOTA L 8000 (193l 9 3.409 e Sel19 e 9,543 e
5,972 e
8,940 e
7.768 e
0.652 e 80.032 COSTS ASSOCIATED WITH ARRANDEMENTS WITN VEPCO 9000
{154) 6,e34 7, 31 5 7.921 e,119 e,559 9.924 9.280 9,658 TOTAL ADDITIONAL COSTS 8000
( 155 ) e 10,243 e 12.434 e 13,36 4 e 14,091 e 15.499 e 18,892 e 17,912 e 19,see TOTAL COSTS UNDER AceWCT ARRANGEMBWT cs Pf2RD COSTS 9000
[Ist) e 59,405 e 65.364 e 9e,393 e307.444 e120.949 el47.928 9234,544 e224.674 VARIABLE CDSTS 9000 (182)
SS.209 89.497 30,4e7 e7.575 93.e47 103,316 309.724 127.470 8
TOTAL COSTS 8000 lis3) 8124,614 0134,962 #17s,n70 e195.039 sple.79s e251,243 8324.280 e392.144 DEMAND AND ENER0f RRQUIREMSWTS S OENERATION LRTEL CP8L CITIESS PEAR DEMANDS MW (111) 654.7 693.0 111.4 739.7 769.0 796.4 924.7 e53.3 ENERCI REQOIREMENTS OWN gl12) 3.052.2 3,1N4.S 3.116.7 3,449.0 3.591.3 3.111.8 3,945.e 3.97s.1 VEPCO CITIRSI PEAR DEMANDS MW
{l73) 195.9 371.5 3e7.2.
402.9 419.6 434.3 450.0 tss.4 RWRROY RE00fRERRNTS OWN 1874) 1.702.5 1.177.4 1.e52.2 1.927.1 2.002.0 2.07s.9 2.158.9 2.228.7 TOTAL ASEMCIt PEAR DPA AWDS MW (175l 1.010 9 1.054.8 1.098.6 1.142.6 1.106.8 1.2 30.7 1.214.7 1,319.7 MWE90t NEGOIREMRWTS OWN (176) 4.754.4
- 4. 98 1. 9 S.169.0 S.376.1 S.593.3 S.190.5 S.997.6 S.204.0
'O *4
$h a r Og fl. L l
U
__m O%
g; MORTfl CAROL!pA MUNICIPAL POWER AGENCF WUMRRR 3 PROJECTED OPRRATING RESULTS UNDER PROPOSRD ARRANORitRWT WITH C P E L CAnR A SCHEDULE 3 - TOTAL AGENCF COSTS DRSCRIPTION 19R2 1993 1994 1995 1996 1997 1998 1989 ALimC ATRO BULR POWRW SUPPLT COSTS CPEL CITIESS FIRED COSTS eP00 (177l e 34.059 e 37.597 e 58.941 8 64.301 e 12.741 e 89.953 el32.n2O el39.095 VARI ARLE COSTS 9000 1178]
41.960 44.803 51.645
.56,193 60.196 ss.259 70.35#
el.125
= _.
TOTAL COSTS e000 (179l e 15.ple e e2,200 e110.296 e120.443 el32.940 8854.210. e203.17e e220.820 VRPCO CITIESI FIXED COSTS 9000 (1903 e 25.347 e 27.767 e 39.742 e 43.144 e 48.205 e 57.975 e el 724 o 95.579 VANI ABlJt COSTS 8000
[ISI) 23.349 24.995 28.e42 31.392 33.651 37.057 39.388 45.744 TOTAL COSTS e000 (In2l e 48.696 e 52.662 e 59.594 e 14.536 e R8.856 e 95.032 #121.091 e331.324 TOTAL AGENCft g
FIRED COSTS er' 3 gle3) e 59.405 e 65.364 e 99.393 e107.444 el20.949 8147.926 0214.544 e224.674 VARIABLE COSTS es J (194) 85.209 89.497 so.4A1 e7.575 93.547 103.116 109.724 127.470 TOTAL COSTS 9000
{l453 e124.614 el34.462 0179.470 e195.019 0214.196 0251.243 8324.289 e352.144 DEMAND AND ENEROf DELIVERERS CPEL CITIESS DILLINO DEM AN DS MW-MO
[lps) 6.320.9
- 6. 59 3. e 6.ess.e 7.139.7 1.412.4 7.695.8 7.958.5
.e. 2 31. 4 RWRpot DRLIVRRIRS OWM (107l 2.951.5 3.079.4
.3.207.3 3.335.2 3.483.3 3.591.0 3.789.9 3.e48.e VPPCO CITIESt MILLING DRMANDS MW-Me (188) 3.372.1 3.520.2 3.689.3 3.236.4 3.964.5 4.112.6 4.260.7 4.40s.#
ENERot DELIVERtBS OWN
[1#93 1.583.7 3.853.4 1.123.1 1.792.7 1 e42.4 1.932.0 2.001.7 2.011.4 AVERAGR COSTS OF ALL REQUIRP3IRNTS fufLR PowRR SUPPLT CPSL CITIRSt FIRED COSTS e/RW/MO (191) 5.39 5.70 9.54 9.01 9.nl ll.10 16.69 15.90 VARIADLE COSTS MI LIJE (192) 14.18 14.48 18.10 18.85 17.3e is.45 1s.92 21.24 COSTS ASSOCI ATED WITN ARRANORMENTS WITM VRPCot FIRED COSTS e/RW/MO (193) 2.33 2.19 2.29 2.30.
2.35 2.39 2.49 2.51 VARI ABLR COSTS MILLS (194)
.58
.57
.64
.67
.69
.73
.75
.84 VRPCO CITIESS w el j $.
FIRED COSTS e/RW/MO (195) 7.52 7.99 IO.n3 31.30 12.14 14.10 19.19 19.41 VARIAnLR Costs MILLS (1981 14.14 15.08 16.14 17.51 18.07 19.1e la.67 22.04 m t.e AVERAGE ADDITIONAL COMTS UM rop VRPCO CITIRS Mt LtA t1973 5.03 5.la 5.42 5.45 5.57 5.s9 5.ns s.OO
e Tab h 11-2 Pege 12 ef 15 64 -
=
. l P
O m.
.M
.m 3 Om ah w
m O
=
=
Mw W
- +
s
- e e m
e P
M w
P MS S
m4 mm mM m
e e
a e
o e e o
PM GM PW P
O 9
M mulm 4 90 mW WW ao m
se M
m M $ *u 4 e o e
ee e
mM i mg mm M
me G
G
G S
19 s el M
W m
le Mm 1f.4 l pg we me 4
al M
w S
S i w WO 3
e e o e e e a
m P
W ele me t.s.
m4 me De 4 e o e mO em MM m
e e
o e
w O
P M lm SW P
Om mP WW
=
m m 4M em M
e o e
o e t
mM 9
M9 M
HP G
sG G
S
$9 el M
m l M mte 64 m
MS PO
- 9 m i elm M
g me e
o e m
P lm M
w Og m
e el e o
e o e o
OOP M
O OW W f OP mW Sw m e=
a e
me ml ee e
me lG wM[P )
mw n
mp s
S S
u G e S
l e
M em m'
w wM w
em mm me e
m M
S m
e e
MS O
e e o e I
m S
P W
P M
WW M
wm WW EO m
o e
o e
e e o e
em WO Mw 4
m O
W M
m Mw S
SW m#
MM M
=
=
m ( M mm M
e e
e a 9
MM W
W M
MP E
S S
8G S
4 E
E s
E M
M M
e m
O MW lwl pH wM em DEJ m
P m
m M
MO M
e e e e e e EE W
mi M
m m
a e
Mw WP FW WM De k
n o
e e
e o
e o e
wD MM mM ME E
m O
M M.
P Om ml Em mm 90 UDb O
mim W $M MW M S
=
=
e o R
U lG t
MM mi N
M mP E MU S
s 19 9
el i
Ok h
I (JE O
DH E
M m
Emm k
m O
M M
M le se el e o e e e e EE3 c
m m
W M
w P
em M
De Mm 04 WE 4
m o
e e
e o
e o e
MP mm me O
k w
D M
m e
malM mM mw we AOE4 J
m m
M 00 10 m
o e o EE 4
l M M lm w
M me JmEE H
G G
sS S
se (kME D
bdO4 mEEU m
O wtw W
WM lt WP Om em UNe i
m O
M N
O M
OM BM e e o e e e wha e
m W
m E
P Om4m MM PW Om EDE M
m e
o e
o e
e o e
Ow me Om 5
D C
w P
=
0 M
OO O
mn WM 99 I
EO E
m M
M EG e
e e o NO J
i MM [w w
n me d
M f
G G
G G
G 8 E
m I
w O
J E
O m
M i n P im Mw e
ww Mw Re m
M M
5 sw e
e e O
O
.U
.O s E4.E r.
m m
a m
-O
==
M. M M
. m.
W R. M. 9 m
o e
o e e
.m
.e O
O U
w m
M m
m m
4 E
M-9 w
n i.
g O
E M
M w m
- m. M M.
-m M9 m.
m m m m m PP PP PP mm_
_m um_
mm_
a m
m m
E 4
O O
O O
O E
OO O
O O
O O
c W
OO O
O 2
.O
.O 2O C
E E
E E
E
==
EE EE y
g O
=O f
g a
g 4.4 E
u.
8.
E 1
H U
E 8
E E*
E g
I E
E U
O
-,E EE J
"i.
E E
R E
J w
E E
E U th 4
DE E
E l ON N
E E
E lw k
E O
A RJ E
E E
NjElm NW m
E S
m em Em gm i
O s b
Ch k
D k
W ER AD=A me i
C lOM4 mE W
t MO
=EDER hm t
UU UE G
MO w
w F4ME4 Ut E
J m>
JOE a
O O
ON MEEMEEEEE 04
=p 4
mp 4mW 4
U E4j mE DE um Ao E.
WEE bec E
4R sbekwAhDAW k s O
MM 04E J
U Ud J
Mi m OU 04 O
m l M i kmM k
4 E
4 At TOME ME mE E
k U
E SWE b
J
' CE k
EM I CEO4EJdE U
M Eko Dh5 0
4 4WM O
COldEEUNkdWE q
ME3 mw4 b HOME k
E tuhkh&E hk L
D OM O
P 'f N61b E
O d
D d
44 U
G su
,r '
Tcblo XI-2 Pcg2 13 of 15 65 -
- u meie Wm o
mW m
m-WP m.
- m MM M
m h me Q
mW M
MW e
m we O
mm S
MO 9
wO MS e e e
- 1 m
o e e
o e e
e o e
me FM de Mn mW e
em m
DO
.O w e.
- m. W.
.m MW MW
- M M
nm m
MM MM m
Me I M mM 1 m Ow mM 9
9 9
ll 9 9
l 9 en
\\
]
W t
OM ua we
=
M.
IM OM mO We mm We M
1 m
I OM I M
WP w
WO sP e *
- e mm mm PP O
m wm m,me O
melm MM mm o e e e e e e
e e e o
e e l e
- w we MO Mm Wm S
00 O
OW P
Op lM mP em Me MW em M
00
' O wm( M e e e o Mm m
Mm I M MM lO Og mh 9
e e
'l e e e G
- e e
e em W
ww
. m mW i m OM we
=O MM Mw F
m mm M
ew M
mW W
e
- WM 09 WP W
P Og m
ew Mm e
- m Me e
- e. m.
e o e i e
Wm he ew Mm
=P P
m o e e
Meem MM
=
Om m
mW W
e
- e e i
Nmtw w
M wM N
mW mM 9
8e e G
S S
li I
w Om m
mp
=
wM S mW MP WM MM Mw W
m MP 00 m
Me e o e
- wm mM
- E M
i m
NM m
wM P
WW WW mm e *
- e
'j m
o e e
o e e
e o e
me em MM Mm Ew P
4 WD W
We m
Mw e
ew mW MM MM M
wel m we M
mM M
e * *
- i MmtM m
M MM j W m.
MM l
E G
$G G
G S
s G E
1 S
1 E
R me M
em m
Mm e
Mr MO MW Me mM e
DEJ B
PS P
mO W
MO M
e
- MM eM MS O
1 NE C
m Me e Os e
Mw P
Me mO e o e e i
QW W
o m
e o e
o e e
o e Me Om mM Mm TM P
WE 2 9 20 m me Om
.e MM OM MM MM 4
UDL Og me M
Me e
Mm M
e o e o t,
E U l mm M
m
=
HM e
tw mM i
EMU s
e e e G
G e
l CH k
.]
<JE U
4 Om E
M i
em m
em m
-W M ts MW
==
em em Om w
Emm E
m I
AP W
WM e emae o e e o em PM me t
J' EEE O
m PC E
OM M
em M
00 MO e e o e o e e
SE m
e e o
e e o
e o e
mm MS DO Mm Mm W
O k
Mm W
wM W
==
M OM eM MM NM ii kOE4 J
eh
= me e
PC-m em gM O
e o e e EE
==
m =
m i
JMEE k
G G
G G
d G
skEE O
A=Oc wSEU m
Mel m
wM i >
WM e
MP OP MO em mM m
UM4 i
DO O
mm M
OM M
e
- SM We mM m
-i w&E D
OP e me P
Om e
PM 20 e o e e e e e
EDE P
m o *
. e e
e =
MO Om me Mm Mm W
D wm a mv O
90 O
Pm PM mM MM EC W
=
3 OW P
We W
e e e.*
I MO J
mm M
m Mm e
og gn i
E e
e e e e e
E m
I w
O J
Jeb E
O e we m
Mwle WP me Ow
=>
mm O
000 U
we o
mM e Dele e *
- e em
,W e am M
a, kkE E
m em w
PW M
wm P
99 Wm e o e e e e e
1 (Ah a
e e o
e e o
e =
OP ew mg M
Me W
4 U
mW M
Ow m
WM e
mm em mM MM
'i l
wm W
Om m
Wel=
= =
E v
MM sW eM 9M m.
M.
m.
e.
i.
g Oe
= === ===
==
==
==
w.
=
1 em m Om M
M.
e W*
em mM Mw mW
- P e se e se a es se em om m e.
m mm m
mm a
um
=
mm
==
mm em um a
= === ===
==
==
==
wm t,
O O
O E
E E
1 M
O O
E I
%F
%E
%E E
4 4
H 00 O
DO O
DO O
E E
k Rm 3d EJ d
E CO O
00 O
00 O
at et E
ud ud ud 4
Og O. O
.O g3 gg E
%. m
.% w O
O 00 O
I
%m m
- u
,g g
q O
.E E
E E
a e
as a
e 4
ml w
E
=
A E
O E
D U
k E
M R
E J
EE O
B M
J U
N A
E 2
J m
E W
=
RE JE
@w tw
<5 i
l E
M M
Em i
M a
EE EM O&
Es b ON w
m E
W E
k E
wm J
E0 M=WO E=EO W
E Ew=Em 20 m dem
=20 kV
=
U kWNU kmku h E
=MJEkJ het=>UwkkUCeb W
=
E a
m mER WUm m
RAEMAM m
aem UER ME c0 O
E, N OwOE DEON O
D E
Du A
ORIEONOEDEmON DU l
w A
M UJ UNUJ UEUJ U
E MO HC UE awCJcEUJkUJ j
E C
m C
E
=
kahmth 3 1>
emE Sw e
E i
wh<
JUS < J <O &C J
wmOUMO MOlwa4408<Ute M>
m UEm 4
Em
=
Mu 4
UJE Jk O& tUMm EMm Mm O
E O
==
kJan JEOJM
====O
$8=<=
=E Jmyu-E mwlJ-ska-cu-<
<E U
O Jwe Osw<
=
E 4
Wkk PLk>
>>k>
> K eGELDM MJSekk@Ek>LL>
Ek l
W 4
E D
E th W
>Elh 04 E
D 1
e ciU
&l w
<E s w U
-O l
i 1
OI e
O NORTH CAROLINA RUNICIPAL PowRR AOPECr wunBER 3 PROJECTED OPERATINO RESULTS UNDER PROPOSED ARRANORMPET WITM C P S L CARE A SCHEDULE 3 - TOTAL AGRWCT COSTS DESC R IPTIOW 199e 1999 2000 2001 2002 2005 ADDITIONAL AcepCT COSTS a
AORRCY A E O RIPENSES e000 l l5i l e 8 9.227 e
4.947 8
9.774 e
10.654 e 31.883 8 32.sSe DRBT SERITCE -
WOREING CAP 1TAL 0000 (152l 10.754 10.153 10.157 10.741 10.741 10.141 SenTOTAL 0000 (153) e 19.981 e 19.71R e 20.531 e 21.395 e
22.354 e
23.379 COSTS ASSOCI ATED WITM ARRP.pOEMENTS WITN TEPCO 9000
[154l 14.931 15.4n3 16.043 16.627 17.202 17.781 TurAL ADDITIopAL COSTS e000 t155) e 33.992 e 35.203 8
38.574 e
39.022 e 39.55s e 41.lso I
TOTAL COSTS UNDRE ACEWCf ARRApcERRRY PIRED COMTS e000 (1483 e 453.490 e 494.430 e 722.772 e 194.908 e 842.30s e e91.Ils I
TARIABLR COSTS 8000
'IS2) 301.431 427.812 487.902 545.590 815.534 593.323 TOTAL COSTS 9000 (1838 ele 034.900 81.122.043 e1.210.614 81.340.399 08.458.940 e8.504.43e DEMAff D AND ENER0f REQUltentRTS e cRaepATIog LRTRL CPSL CITIRS PEAR DEMANDS RW
{l71) 1.109.3 1.136.5 1.144.9 1.193.2 1.221.6 1.249.9 EN RP0 f D RQUI RPMRRTS OWN
{l72) 5.168.6 5.300.9 5.433.2 5.565.4 5.497.7 5.830.0 VEPCO CITIRSt PEAR DRMANDS MW
[173) 4 04.0 622.5 539.2 653.5 669.5 Ges.2 ENER0f REQUIRIIRBRTS OWN I1743 3.900.T 2.975.8 8.v50.4 3.125.3 3.200.2 1.275.1 TOTAL AGRWCY8 PEAR DRMANDS Int (175l 1.115.0
. 1.759.0 1.'03.0.
1.e47.1 1.991.1 1.935.1 RNEROF REQUIRPAelffS OWN I174) 0.069.3 s.216.4 4.4h'-8 e.s90.5 8.e97.9 9.105.1 1
me to tf Y
O I
- % DJ
%#t
.___m..__m
.__m___
(~ *.
// i es
.T NORTH CAROLINA MUNICIPAL POWER AGRNCf IfUEhER 3 PROJ RCTRD OPRRATINO RR3ULTfl UNDER PROPOSED ARRANORMRWT WITM C P S L CASM A RCNRDULR 3 - TOTAL AORNCf COSTS DESCRIPTION 1999 1999 2000 2001 2002 2003 AttDCATED BULR PONRR SUPPLY COSTS CPSL CITIESS FIRED COSTS 8000 (177) e 432.637 8 439,681 e 456,592 9 502.712. e 532,993 e 564,107 VARIABLE COSTS e000
[178) 244.304 273,876 392,467 349,397 194,792 443.934 TOTAL COSTS 8000
{1793 e 656.941 8 712,557 e 769.059 e 352.100 e 927.775 81,009.041 VRPCO CITIEst FINED COSTS e000 (130) e 240.853 e 255.748 e 266,190 8 292.095 4 309.323 8 327.008 VARIABLR COSTS 8000 (191l 137,108 153,736 175.435 194.2n3 221.142 249.399 TOTAL COSTS e000 (192) e 377.959 e 409.404 8 441.615 8 489,2?S e 531 66 e 576,397 8
1DTAL AORNCf 8 r!ISD COSTS 8000 (193) e 653,490 8 694.430 e 722.772 4 794,909 e.942,306 8 991.115 Os 4
VARI ABLE COSTS e000 (184) 191.411 427,612 487.902 545,590 616,534 693,323 g
TOTAL COSTS 8000 In95) 91,034,900 $1.122,041 e1.210,674 e1,340,399 81,458.840 81.584.439 DEMAND AND EMEROf DELIVBWIES CPSL CITIRS BILLING DRMANDS MW-MO (196l 10,687.9 10,96C.e 11.233.7 11.506.6 11,779.6 12,052.5 ENEROf DELIVERIES OWM (197l 4,998.0 5.125.9 5,253.9 5.381.9 5.509.7 5.637.6 VRPCO CITIBSI BILLINO DEMANDS MW-MO (199l 5,741.1 SesR9.9 6,037.9 6,196.0 5,334.1 6,482.2 RWEROT DRLIVRRIRS OttM (109) 2.690.4 2,168.0 2.937.7 2,907.3 2.977.0 3.046.7 AVERROR COSTS OF ALL RROUIRRMRWTS 190LK PONRR SUPPLT CPSL CIT!!!St FIRED COSTS e/gW/MO (191) 38.61 40.02 40.64 43.69 45.25 46.30 VARI ABLE COSTS MILLS (192) 48.99 53.43 59.47 64.92 71.65 78.75 COSTS ASSOCI ATRD WITM ARRAp0EMBN13 It!TN TRPCOI FIRED COSTS e/RW/MO (193) 3.34 3.40 3.44 3.53 3.59 3.64 VARIARLR COSTS MILLS
[1943 1.93 2.11 2.35 2.56 2.03 3.11 VRPCO CITIRSt
- W H FINED COSTS e/RW/MG
( 195 )
41.95 43.42 44.08 41.22 40.93 50.45
$h VARIAME,8 COSTS MILLS (196) 5 0.811 55.54 61.42 47.49 74.49 e1.96 ft y II' M AVRRAGE ADDITIONAL COSTS
,a y roR VRPCO CITIe9 MILT.S (1973 e.63 n.92 9.25 9.62 10.00 10.3n
- w
e
.. - Question 13 List and describe all requests for, or indications of interest in, interconnection and/or coordination and pu>cciases or sales of coordinating power and 4
energy from adjacent utilities listed in Item 9 since 1960 and state applicant's response thereto.
List and describe all requests for, or indications of intereat in, supply of full or partial require-ments of bulk power for the same period and state applicant's response thereto.
Responses Not applicable to Power Agency. However, during the middle and late 1970's, North Carolina Municipal Power Agency Number 2 had studied various power supply alternatives and negotiated with VEPCO.
None of these alternatives were under-taken, but an interconnection agreement with VEPCO was negotiated and executed.
I 4
'f f
4 e
-v--p
Question 14
' List (a) agreements to which applicant is a party (reproducing relevant paragraphs) and (b) State laws j
(supply citations only) which restrict or preclude i
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 laws (supply citations only) 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 applicant to systems identified in Items 8 and 9.
Where the contract provision appears in contracts or rate schedules on 1
file with a Federal agency, 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 unless it has been supplied pursuant to another item hereto.
Where it is not in writ ing, it should be described.
Response.
Power Agency has no knowledge of any State laws and Power Agency is not a party to any agreements which restrict or preclude coordir..ation by, with, between or among any electric utilities, or which restrict or preclude substitution of resale service or establishment of resale service of full or partial bulk power supply requirements by an electric utility, other than Power Agency, to systems identified in Items 8 and 9.
Article 6 of the Power Ccordination Agreement between Power Agency and CP&L, supplied with this Application, requires Power Agency to give eight years prior written notice to CP&L if Power Agency desires to reduce the amount of its Supplemental Capacity obligation.
However, that Article 6 r
l
.. permits Power Agency under certain circumstances to reduce its supplemental Capacity obligation on less than eight years notice.
Power Agency is required to give ten years wricten notice to VEPCO to terminate service under the Agreement for Transnaission Use and Other Electric Service, but it may terminate service at any delivery point upon five years written notice (with service to the City of Washington's delivery point being permitted to be terminated earlier if written notice is given within six months of July 30, 1981).
Section 3 of the Supplemental Power Sales Agreement between Power Agency and each Participant provides for Power Agency to sell and the Participants to purchase all requirements bulk power supply.
This all requirements bulk power supply is in excess of any allotment of power which a Participant may receive from bdPA or certain resources which a Participant may install pursuant to Section 3 of the Supplemental Power Sales Agreement.
Pursuant to the provisions of Section 2 of the Supplemental Power Sales Agreement, a Participant may terminate the Agreement on ten years prior written notice to Power Agency.
4 4
O Question 15 State, at point of delivery, average future costs of power purchased from applicant to adjacent systems identified in applicant's response to item 9 in terms of dollars / month /kw for capacity, mills /kwh for cnergy and mills /kwh for both power and enetgy at purchaser's present load factor (a) at present load, (t) at 50 percent increase over present load, (c) at 100 percent. increase over present load, and (d) at 200 percent increase over present load.
(All costs should be determined under present rate scheduler )
Where sales are made under contracts or rate schedules on file with a Federal agency and not included in the response to Item 9, identify each in 4
the same form as in previous responses.
Where the
]
contract has not been filed with a Federal agency, a q
copy should be supplied.
Responses i
Not applicable.
j a
l i
i
e s
. Question 16 State whether applicant has prepared, caused t<
be prepared, or received engineering studies for generation and transmission expansion programs which include loads of each system in Item 9.
Response
None by or for Power Agency.
However, North Carolina Municipal Power Agency Number 2 had a study of a combustion turbine project prepared for it in 1976 and a preliminary study of several power supply alternatives prepared for it in 1978.
4 I
4 i
4 a
l L
l
e-6
. Question 17 List adjacent systems to which applicant has offered to sponsor or to conduct system surveys in con-templation of an offer by applicant to purchase, merge or consolidate with said adjacent system, sub-sequent to January 1, 1960.
Response
None.
D e
1
e
'l [
Question 18 List applicant's offers or proposals to purchese, merge or consolidate with electric utilities, sub-sequent to January 1, 1960.
i
Response
None.
4 4
4 4
4 1
l J
i 4
i i
i 1
1 7.-
-w.<
..n-
.n-e,.
n,,
a
. - Question 19 List all acquisitions of or mergers or con-solidations with electric utilities by applicant, subsequent to January 1, 1960, including:
(a)
The name and principal place of business of the system prior to acquisition, merger or consolidation:
(b)
The date the acquisition, merger or con-solidation was consummated; (c)
Gross annual revenue and most recent peak load, dependable capacity and the largest thermal generating unit of the system, prior to the date of consummation.
Response
None.
i
i*
o
. Questior. 20 State applicant's six (or fewer if there are not six) lowest industrial or large commercial rates for firm electric power supply in terms of cost for power and energy in mills per kilowatt hour (and separately, the demand and energy components) and indicate the portion of the charge attributed to bulk power supply.
State the rates or rate blocks applicant utilizes for its six (or fewer if there are not six) promotional services such as electric space heating, electric hot water heating, and the like, in terms of mills per kilowatt hour for power and energy and indicate the portion of the rate or rate blocks attributed to bulk power supply.
Response
Pursuant to Chapter 159B of the General Statutes of North Carolina, Power Agency is authorized "[t]o generate, produce, transmit, deliver, exchange, purchase, or sell for resale on1v, electric power or energy, and to enter into contracts for any or all such purposes" (Section 159B-11(15)).
Accordingly, Power Agency does not have, and does not comtemplate having, any rates of the type set forth in Question 20.
t
,30 o*
, APPENDIX A LIST OF POWER AGENCY'S HEMBERS l
Town of Apex Town of Ayden l
Town of Belhaven*
Toen of Benson Town of Clayton Town of Edenton*
City of Elizabeth City
- Town of Enfield*
Town of Farmville l
Town of Fremont City of Greenville*
Town of Hamilton
- Town of Hertford*
l Town of Hobgood*
Town of Hookerton City of Kinston l
Town of LaGrange City of Laurinburg Town of Louisburg City of Lumberton City of New Bern Town of Pikeville Town of Red Springs Town of Robersonville*
City of Rocky Mount Town of Scotland Neck
- Town of Selma Town of Smithfield City of Southport Town of Tarboro*
Town of Wake Forest City of Washington
- l Town of Waynesville l
City of Wilson l
Town of Windsor
- l Town of Winterville*
{
Members served by VEPCO (directly or indirectly) as of the date of this Application.
l l
L.
- se..
4.
Communications CP&L will be solely responsible hereafter for communications with NRC related to this application for Brunswick Units Nos. I and 2.
Accordingly, all communications to CP&L or Power Agency pertaining _to this application for Brunswick Units Nos. 1 and 2 should be sent to:
J. A. Jones Vice Chairman Carolina Power & Light Company Post Office Box 1551 Raleigh, North Carolina 27602 and in addition, to:
Charles D.
Barham, Jr.
Vice President and Senior Counsel Carolina Power & Light Company
~
Post Office Box 1551-Raleigh, North Carolina 27602 CAROLINA POWER & LIGHT COMPANY BY:
A MS Vicc/'Chairmad/
J. A Jones Sworn to and subscribed before me, this day of M., 1981.
f
.AAAhW$
Notary Public F/
' * *.,V
'/
- $4 My Commission Expires: 5 f h-h-T{I :5,
.<eit-NORTHCAROLINAMUNICIPAk ERAGEl$dY[
NUMBER 3
- ........ **h.9 00051b
'sie,'s iioW's BY:
M A
istant Secretary-Treasurer Sworn to and subscribed before me, 'this 3l day of klLS.
1981.
V
[
. /awhrc/hlIMbno)
Notary Public My Commission Expires:
// - g - >TS
..