ML18017B448
| ML18017B448 | |
| Person / Time | |
|---|---|
| Site: | Brunswick, Harris  |
| Issue date: | 09/03/1981 |
| From: | Jackie Jones CAROLINA POWER & LIGHT CO. |
| To: | |
| Shared Package | |
| ML18017B447 | List: |
| References | |
| NUDOCS 8109090149 | |
| Download: ML18017B448 (81) | |
Text
UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION In the Matter of
)
)
CAROLINA POWER
& LIGHT COMPANY
)
)
(Shearon Harris Nuclear Power
)
- Plants, Units 1, 2, 3 and 4)
)
Docket Nos.
50-400 50-401 50-402 50-403 APPLICATION FOR AMENDMENT OF CONSTRUCTION PERMIT NOS ~
CPPR 15 8 g CPPR 15 9 g CPPR 1 60 AND CPPR-161 ADDING CO-OWNER Carolina Power
& Light Company
("CP&L") is presently the holder of Nuclear Regulatory Commission
("NRC" or the "Commission" )
Construction Permit Nos.
CPPR-158, CPPR-159, CPPR-160 and CPPR-161 for Units Nos.
1, 2,
3 and 4 of the Shearon Harris Nuclear Power Plant.
By this application, CP&L and the North Carolina Municipal Power Agency Number 3
("Power Agency" ) respectfully request that the Commission amend these Construction Permits to include Power Agency as a co-owner of Harris UnitsNos.
1, 2,
3 and 4 consistent with the agreements between CP&L and Power Agency as hereinafter described.
CP&L will retain exclusive responsibility for the design, construction and operation of Harris Units Nos.
1, 2, 3
and 4.
8109090i49 Bi0903,-
PDR ADOCK OS000400 A
1.
General Information a.
Name and Addre'ss of Pro osed Co-Owner North Carolina Municipal Power Agency Number 3
Post Office Box 95162 Raleigh, North Carolina 27625 b.
Descri tion o'f Bus'iness o'f Pro osed Co-Owner Power Agency is a public body corporate and politic and an instrumentality of the State of North Carolina, incorporated under North Carolina statutes in December, 1976.
Power Agency was created to plan, develop, construct, and operate generation 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 contracts with thirty-six political subdivisions, listed in Appendix A, under which Power Agency is to be the sole and exclusive bulk power supplier for each such political subdivision in excess of any allotment of federal power from Southeastern Power Administration or of the output of any resource such political subdivision may develop and install pursuant to provisions of the Supplemental Power Sales Agreement in effect between Power Agency and such political subdivision.
Each such political subdivision is obligated to 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, but not exceeding 50 years.
c.
Corporate Da'te Relati'n
'to Pro osed Co-Owner Power Agency is a body corporate and politic and an
instrumentality of the State of'orth 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 owned, controlled or dominated, by an alien, a foreign corporation or foreign government.
Power Agency's office is 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 Town of Apex Hon. Ralph M. Wallace Town of Belhaven Mr. Mark A.
Suggs'own of Ayden Mr. Robie G. Dunn Town of Benson Mr. Charles Stewart Town of Clayton Mr. James P. Ricks, Jr.
Town of Edenton Mr. Tommy M. Combs City of Elizabeth City Mr. J. A. Wooten, Jr.*
Town of Farmville Hon. B. D. Kimball Town of Enfield Mr. Devone Jones Town of Fremont Mr. Charles O'H. Horne, Jr.*
City of Greenville Hon.
W. D. Cox Town of Hertford Mr. W. P. Riley Town of Hamilton Hon. R.
G. Anthony Town of Hobgood Hon. Harry S. Taylor, Jr.
Town of Hookerton Mr. Edward B. Walters Town of LaGrange Hon.
Simon C. Sitterson, Jr.*
City of Kinston Mr. Peter Vandenberg*
City of Laurinburg
Ms. Lois Brown Wheless Town of Louisburg Mr. Russ Conner City of New Bern Hon. Furman K. Biggs, Jr.
City of Lumberton Mr. Raymond Glover Town of Pikeville Mr. John McNeill Town of Red Springs Mr. Ralph Mobley Town of Robersonville Hon. Frederick E. Turnage*
City of Rocky Mount Mr. W. Everette Prince Town of Selma Hon. Ferd L. Harrison Town of Scotland Neck Mr. Jonathan Hankins City of Southport Mr. Earl Langley Town of Smithfield Mr. David R. Taylor*
Town of Tarboro Mr. Guy C. Hill Town of Wake Forest Mr. William L. Ross Town of Waynesville Mr. T. R.
Shaw, Jr.
City of Windsor Mr. D. R. Jones City of Washington Mr. T. Bruce Boyette City of Wilson Mr. E. C. Hines Town of Winterville "Executive Committee Member
2.
RESPONSES TO INFORMATION REQUESTS OF NUCLEAR REGULATORY COMMISS'ION 'STAFF CONCERNING FINANC'IAL 'QUALIFICATIONSOF MUNI'CIPAL APPLICANT NORTH CAROLINA MUNICIPAL POWER AGENCY NUMBER 3 Question l Provide a detailed statement of the projected source
~
of funds for each municipal applicant's capital contribution to the subject project reflecting assumptions and detailed explanation.
Res onse to Question l Power Agency's ownership interest in the project will be financed through issuance of tax-exempt revenue bonds.
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 payment of interest.
charges and principal.
Res onse to uestion 2
Power 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.
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 make 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.l 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 by Power Agency and each Participant.
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.
Res onse to Question 3
Power Agency has not heretofore issued any such bonds.
I
Question 4
Provide copies of the official statements for the most recent bond issue.
Res onse to Question 4
See response to question 3.
0" Provide copies of the most recent annual financial report (June, 1980).
Res onse to uestion 5
Submitted herewith as Exhibit C is the report entitled'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 most recent annual financial.statements of the municipalities which may become Participants in the project.
0" Is each Participant's percentage ownership share in the facility equal to its percentage entitlement in the electrical capacity and output of the plant.
Res onse to uestion 6
Yes, they are equal.
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.
Res onse to Quest'ion 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. 159B-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 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 Z-), Power Agency covenants to set rates adequate to cover all its costs fPower Coordination Agreement, Section 26.1 (A); Operating Agreement, Section 19.1(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 fulfillthe terms of any agreement for the project.
Question 8
What 3.s the estimated dollar amount that will be payable by the applicant at the date of closing of the sale, and after closing through the completion of the units.
Res onse 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.
Provide copies of the joint ownership agreements.
Res onse to Question 9
Copies of the joint ownership agreements are being filed as a part of this Application.
estion 10 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.
Res onse 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", to Exhibit B.l, Section 5(e),
Section 6(b),
and Sections 12(c) and (d); and to Exhibit B.2, Section 7(c).
Explain the procedure to be used by the lead applicant for billing the municipalities for construction progress payments subsequent to closing the sale.
Res onse 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 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 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.
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.
Res onse to Question 12 Provisions for the creation of a Decommissioning Fund have been provided in the draft Bond Resolution (Exhibit G) which is to be adopted by the applicant's Board of Com-missioners.
In addition, costs of decommissioning the Bruns-wick and Harris Units have been included in the Preliminary Engineering Report of R.
W. Beck and Associates as a portion of the project's overall feasibility.
12 3.
Information Re uested b
the Attorne 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 December 27, 1974) and the Construction Permits for Shearon Harris Nuclear Power Plant Unit Nos.
1, 2, 3 and 4 ("Harris Units" ),
CPPR-158, CPPR-159, CPPR-160 and CPPR-161, respectively (issued January 27, 1978).
Applicants seek to have 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 include Power Agency as co-owner of the Brunswick Units and the 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 information requested by the Attorney 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 and because the capacity which will be available to Power Agency through the subject project is less than 1400 MW(e), Power Agency is not required to submit (Footnote continued on page following.)
INTRODUCTION A.
General Back round 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 S
Light Company's service area; sixteen are in Virginia Electric and Power Company's service area in northeastern North Carolina; and twenty-three of these 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 6 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 North Carolina.
This Act provides that municipal electric systems in the State of North Carolina may jointly plan, develop, construct, and operate generation and transmission facilities.
The new law provided that municipalities owning (Footnote continued from previous page.)
the information requested by the Attorney General described in 10 C.F.R. Part 50, Appendix L other than the information described in Section II, paragraph 9 of Appendix L.
- See, 18 C.F.R.
$50.33(a)(1),
(2).
CPEL and Power Agency are,
- however, hereby furnishing information concerning Power Agency in response to each of the requests set forth in Appendix L for the use of the Attorney General in reviewing this Application.
2/
Certain terms which are used in the narrative text are capitalized to signify that such terms are defined terms having specified meanings in the project agreements between Power Agency and CPSL, in the agreements between Power Agency and Virginia Electric and Power Company, or in the proposed bond resolution to be adopted by Power.Agency's Board of Commissioners.
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
37.5S ownership interest in the support facilities at the Catawba Nuclear Station.
Power Agency Number 1 closed on these ownership interests in November, 1978.
Power Agency Number 2 is composed of 15 municipalities that purchase their wholesale power supply directly or indirectly from Virginia Electric and Power Company
("VEPCO").
In the spring of 1980, members oZ Power Agency Number 2 began applying for membership in Power Agency Number 3 in anticipation of 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
acted to include the 14 members of Power Agency 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 wholesale power supply from CP&L and the 14 members that purchase power either directly or indirectly from VEPCO.
Under North Carolina law, Power Agency may be com-posed only of North Carolina municipalities.
Power Agency Number 3 was incorporated in December, 1976 after its formation by twenty-six North Carolina municipal systems in the CP&L service area.
Since that time, eight. municipal systems that are served at. wholesale through other Power Agency Number 3 members have withdrawn from Power Agency Number 3 and are expected to continue as wholesale customers of the Power Agency Number 3 members that now serve their 1/
One member of Power Agency Number 2, which is served at wholesale by an electric membership corporation, did not apply for membership in Power Agency Number 3.
16 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 Pro'ect and Related Power Su 1
Pro ram 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.
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 of all necessary backstand services for such resources plus supplemental power supply and transmission services
Also, through the operation of the Purchased 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 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 will have available assured power supply and transmission resources to provide the total all requirements bulk power supply needs of all Power Agency members through the year 2032 or until the last Joint Unit is retired or 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; the two 790 MW nuclear-.fueled units at the Brunswick Steam Electric Plant, in operation near Southport, North Carolina;
18-the two 720 MW coal-fired units at the Mayo Electric
'enerating
- 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 Pro 'ect A reements The acquisition and use of the project and other power resources, together with delivery of these resources over CPSL'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 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:
The Purchase, Construction and Ownershi A reement the "Sales A reement" This Agreement provides for:
a the purchase by Power Agency and conveyance by CPRL of undivided ownership interests in the Joint Units; (b) employment of CPEL as Power Agency" s project manager for the Construction, Initial Fueling, and placing into Commercial Operation of those of the Joint Units currently under construction; and (c) monthly payment to CPEL by Power Agency of its share of the Costs of Construction and Initial Fueling of the Joint Units including fees to CPGL as project manager.
19 2
~
The 0 eratin and Fuel A reement (the' eratzn Agreement Thx.s Agreement provides for:
a operation, maintenance, and fueling of the Joint Units by CPSL; (b)
CPRL's making of renewals, replacements and capital additions to the Joint Units; and (c) the ultimate retirement or decommissioning, by CP6L or a qualified contractor, of each of the Joint Units included in the project at the end of its useful life's 3
The Power Coordination A reement.
This Agreement prove.des for:
a xnterconnection between the CP&L system and the project; (b) backstand provisions, including Reserve Capacity and Deficiency Energy; (c) Retained Capacity from the proposed project; (d) Purchased Capacity and Energy sales to CP6L from Power Agency's entitlement to the output of the Mayo and Harris Units; (e)'urplus energy sales to CP&L or others from Power Agency's entitlements to the output of 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; (h) transmission service; and (i) purchase, lease or construction of delivery facilities.
This Agreement includes provisions relating to accounting, verification, costing, use of the project by Power Agency, and additional power supply resources that may be constructed or acquired for the benefit of the Participants of Power Agency.
4 ~
A reements 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 Agency for those members of Power Agency which 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 such Participants during a Transition Period through a combination of capacity from the project, partial requirements purchases from VEPCO at VEPCO's Schedule RS-A rates, and transmission service over the VEPCO system.
The Transition Period will extend from 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 Power Agency which become Participants in the 1/
In order for Power Agency to begin service in December 1981 to those Participants now served by VEPCO in the event there is no first closing with CP&L by the end of that month, Power Agency has agreed with VEPCO and with CP&L with respect to an Interim Period from December, 1981 through the Gate 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) 18.7% 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.l and B.2.
To the extent that any members of Power Agency elect not to become Participants in the project, 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 CPGL prior to its date of commercial operation, Power Agency's Ultimate Ownership Interest in the cancelled or decommissioned unit and all payment obligations related solely thereto will be reduced by 208.
Because the aggregate of Power Agency's ownership interests 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 CPEL 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 associated with Power Agency's ownership interests in the Joint Units which is not sold to CPEL as Purchased
- Capacity, and which may therefore be used to meet the Participants'oad requirements, is Power Agency,'
Retained Capacity.
Power Agency's Scheduled Retained Capacity Percentage applicable to each Mayo Unit and Harris Unit, and CPKL's Scheduled Purchased Capacity Percentage applicable to each such unit, 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.CP6L-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 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 CP5L as Supplemental Capacity l/ and will 1/
Also, during the Transition Period, there would be certain purchases of partial requirements power from VEPCO.
be equal to the Annual Peak ResOurce Demand (100$ peak load) of the Participants less Retained Capacity.
When Retained Capacity is operating at less than total capability, Reserve Capacity and associated energy purchased from CPEL would be used to meet the shortage.
If shortage still exists, energy associated with Unused Supplemental Capacity purchased from CPGL 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 CPEL and, in some circumstances, emergency power would be purchased by Power Agency from VEPCO.
D.
Power A enc Municipal Partici ants Currently, Power Agency's members individually contract with CPSL or VEPCO for the provision by such utility of wholesale power services.
Upon the commencement of the provision of services under the Power Coordination Agreement, this relationship between the Participants and CpaL 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 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 obligations under both Power Sales Agreements and to pay any and all other amounts payable from such revenues, including its 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.
0 25 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 Agency does not own any generation (either hydroelectric or thermal) resources.
Member municipalities of Power Agency currently purchase all of their power supply at wholesale (directly or indirectly) from CPSL or VEPCO except for a small allocation of hydroelectric power received by one member municipality (the 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.
Estimated system peak loads, energy requirements, annual load factor and total Retained Capacity for the period 1982-2000 are shown in the table on the page 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 which Power Agency will be selling Purchased Capacity to CP&L based on presently scheduled dates of commercial operation for the Mayo Units and the Harris Units).
TOTAL POWER AGENCY POWER AND ENERGY REQUIREMENTS (AT GENERATION LEVEL) (1/)
Year 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998
. 1999 2000 Peak Demand (KW) 1,010,528 1,054,557 1,098,585 1,142,613 1,186,641 1,230,669 1,274,697 1,318,726 1,362,754 1~406,782 1,450,810 1,494,838 1,538,867 1~582,895 1,626,923 1,670,951 li714,979 lg759,007 1,803i036 Total Annual Energy Requirements (MWH) 4,754,648 4,961,812 5,168,976 5,376,140 5,583,304 5,790,468 5,997,632 6,204,796 6,411~960 6,619,124 6,826,288 7,033,452 7,240,616 7,447,780 7,654,944 7,862,107 8,069~271 8,276,435 8,483,599 Annual Load Factor (a) 53.71 53.71 53.71 53.71 53.71 53.71 53.71 53.71 53.71 53.71 53.71 53.71 53.71 53.71 53.71 53
~ 71 53.71 53.71 53-71 Retained Capac ity (MW) 2/
381.3 440. 7 444. 7 522..9 526.9 535.7 619.0 632.8 706.1 723
~ 9 816 0
838.7 935-9 963.4 991.4 1,018.8 li046 8
1,070 '
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 x MNDC.
TAEIX LX-L POUXR ACXNCT RETAINED CAPACtTT (It brunswick plant Tear W
sr Tss Roxboro Unit No, 4 Ha o Unit No, Sc ed.
Harris Hatt Noe I'c e
~
Barris Unit No. 2
- Sched, Ha o Unit No 2
- 5ched, Harris Unit No, 4 5chede Barris Unit Noe 3
- Eched,
~Tear 3t ~XAL ~WS)
~Tear SL ~241 ~Wf)
~Tear 3) ~24)
~WS)
~Tear 31 ~24)
~WSI
~year 3) ~24)
~WS)
~Tear 3I ~XlL
~8M 5)
Total Retained Cepacl (W
v)
I 1SSe5 295.5 195.5 29Se5 29Se5 29$.5 19$.$
295e5 295.5 295e5 295.5 29$.5 295.5 295e5 29$ e5 29$.5 295.5 195.$
295ef 295.5 295.$
29Se5 295.5 295.5 295.5 29$.5 295.5 29$.5 1982 1983 1984 198f 1986 1981 1988 1989 1990 1991 1992 1993 1994 1995 1996 1991 1998 1999 2000 2001 2002 1003 1004 2005 2006 2001 2008 1009 hand subscSuent years 85.8 85e8 Sfed Sfed Sfed dfed
$5.8
$5.8
$5ed 85.8 8$.8 85.$
Sf.d 85ed SSed
$5.8 8$.8 85.8 85.8 8$.8 85ed
$ $.8 85.8
$ $.8 85.8 85.8 85.8 85.8 I
2 3
4 5
6 1
8 9
10ll 11 13li IS 16ll ld 19 20 21 22 23 24 25 26 21 50.0 f3.3 56e7 60.0 63.3 66.1 70.0 73e3 76.1
$0.0 83.3 86.7 90.0 93.3 96.1 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0-100 eo looeo 100.0 100.0 59.4 63ei 61 e3 lle3 75e2 79e2 83e2 81.1 91 el 95eo 99eo 103eo 106e9 lloe9 114 eS Ild.d Ilded 118.$
118.8 118e8 Ild.d 118.8 I l de 8 118.8 118 ed 118.8 118.8 I
I 2
3 4
5 6
1 8
9 IoII 12 13 14 15 16 17 18 19 20 21 22 23 24 50eo 50eo 53e3 56el 60.0 63e3 66el loco 73.3 76el Soeo 83e3 86 el 90eo 93e3 96e7 100.0 100.0 looeo looeo 100eo IOoeo looeo 100.0 100,0 74e3 74ef 79e2 84.2 89 ~I 94 el 99eo 104 eo 108 e9 113e9 118.8 123 e8 128 el 133.7 138.6 143.6 148.5 148.5 148.5 lide5 148 eS 148.5 14$.5 148.5 148.5 I
2 3
4 5
6 1
8=
10 11 12 13li 15 16 17 Id 19
'20 11 22 50eo 53.3 56.1 60eo 63.3 66el 70.0 73e3 76.7 80.0 83e3 SSel 90eo 93e3 96.1 100.0 looeo 100 eo 100.0 looeo 100.0 100.0 14.3 79e2 84.2 89 el 94.1 99.0 104,0 108.9 113.9 11$.8 123.8 ltde7 133el 138.6 143.6 148. 5 148.5 14$.5 148 eS 14$.5 148e5 148 ~ 5 I
1 3
5 6
7 8
9 Ioll 12 13 14 15 16 11 Id 19 20 50eo 53.3 56el 60eo 63e3 66.7 10.0 13.3 76.7 Eoeo 83.3 86.7 90.0 93e3 96.7 100.0 100eo 100.0 100.0 looeo 59.4 63.4 67.3 lle3 75.2 79.2 83.2 81 ~I 91.1 95.0 99.9 103.0 106.9 110.9 114.$
118e8 118.8 Ilde8 IlbeS 118.8 I
1 3
5 6
7 8
9 Ioll 12 13 14 15 16Il 18 50.0 53.3 56el 60.0 63e3 66el loco 13.3 76el 80.0 83.3 86.1 90eo 93.3 96.7 100.0 100.0 100.0 74e3 79e2 84e2 89.1 94.1 99.0 104.0 108.9 113.9 118.8 123.8 128.7 133.7 138.6 143.6 148.5 148.$
14d.5 I
1 3
4 5
6 1
8 9
10ll 12 13 14 15 16
$0.0 53.3 56.1 60.0 63.3 66.7 70.0 73.3 76.7 80.0 83.3 86.7 90.0 93.3 96.7 100.0 14 ~ 3 79.2 84.2 89 '
94.1 99.0 104.0 108.9 113 '
118.8 123.8 128.1 133.7 138.6 143. 6 148. 5 381. 3 440.1 444 '
$22.9
$26.9 53$.7 619.0 632.8 706.1 123.9 816.0 838.7 935.9 963.4 991.4 1,018.$
1.046.8 le010 3
1,09$.2 I,II1 e9 1,136.$
I, 155.$
1,169.
1,183 1,193.
1,203.0 le20$ 0 I ~2!2e9 Values are reported as of the end ot the calendar year.
Essed on current WDC ot 6$0 W for Roxboro Unit No. 4 snd 190 W for each Erunswlck Untt.
131 Schedule year I begins nn the date ot connerclal operation snd extends through Deccnber 31 of such year lf conncrctal operation ls prior to July I ~ If connerctal operation ls later than July I ~ schedule year I will extend to Dccenber 31 ot ths next calendar yeare (4L Scheduled Rctalned Capacity percentaXc pursuant to Section 5 ~ 3 ot the Power Coordlnatton Agreencnt.
LSL Resultant W of Retained Capacity Ownership Interest x Retatncd Capacity X x INDC.
Question 2
State applicant's estimated annual 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.
~Res ense:
Power Agency's estimated peak load growth and energy requirements at the generation level are set forth in the response to Question 1.
Power Agency's estimated annual peak load growth and energy requirements at the delivery point level 1/ for 1981 through 2000 are as follows:
Kilowatts x 103 Kilowatthours x 106 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 922 964 ls 006 ls 048 li090 1I 132 1 p 174 lg 216 1, 258 li300 1, 342 lg 384 li426 li468 lg510 lg 552 li594 lg636 lg678 li720 4, 338 4,535 4, 733 4~ 930 5,128 Si325 5p523 5,721 5,918 6,116 6,313 6~511 6t708 6,906 7g104 7,301 7,499 7i696 7i894 8g091 Average Annual Growth Rate (0):
1981-2000 3.33%
3.34%
e 1/ Total delivery point requirements of Power Agency members currently served by CPEL and Power Agency members currently served directly or indirectly by VEPCOe Question 3
State estimated annual load growth in kilowatts and kilowatt 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'dentify each company or pool member.
~Res esse:
Economic justification for the subject project is based solely on the growth in native loads on the Participants'ystems and Purchased Capacity and Purchased Energy sales to CP&L in the initial years of operation of each of the Mayo and Harris Units.
question 4
For the year the subject unit would first come on line, state estimated annual load growth in 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 planning functions.
Identify each company or pool member whose loads are indicated in the response thereto.
~Res ense:
On July 30, 1981, Power Agency and CPS L 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 Federal Energy Regulatory Commission for its approval or acceptance for filing without suspension.
CPSL'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:
CP&L peak Demand (including demands of Pc@ver Agency members rxau served directly or indirectly CP&L)
Served Menbers
'eak Demands at the CP&L Generation Level (1/)
Total Cp&L peak Demand (including denands of Pcwer Agency mmbers re served directly or indirectl VEPCO)
(1
)
1982 1983 (2/)
1984 1985 (g3) 1986 1987 1988 (4J) 1989 1990 (5/)
1991 1992 (6/)
1993 1994 (7/)
6i457 6,713 6, 982 7I 273 7,530 7,813 8, 147 8,469 8,727 8~ 988 9~240
9,497 9,752 95 (8/)
138 (8j) 387 403 419 434 450 466 481 497 513 528 544 6,552',851 7,369 7,676 7~949 8,247 8,597 8,935 9,208 9~485 9,753 10,025 10,296 1/ Values are based on the assumption 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 commercial operation of Harris Unit No. l.
4/ Estimated year of commercial operation of Harris Unit No. 2.
5/ Estimated year of commercial operation of Mayo Unit No.
2
~
6/ Estimated year of commercial operation of Harris Unit No. 4.
7/ Estimated year of commercial operation of Harris Unit No. 3.
8/
Transition period The Agreement for Interim Electric Service between 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 which are now served directly or indirectly by VEPCO and for the furnishing by VEPCO to Power Agency of emergency and economy energy services.
The Agreement for Transmission Use and Other Electric Service between Power Agency and VEPCO provides for transmission service over the VEPCO transmission system and also for emergency energy services to be rendered after the Transition Period.
These agreements will be submitted to the Federal Energy Regulatory Commission for its approval or acceptance for filing without suspension.
VEPCO's projected annual peak load (expressed in MW, and shown including and excluding the loads of Power Agency's members currently receiving service directly or indirectly from VEPCO) for the years 1981 through 1994 is presented in the table on the page following.
33 VEPCO Peak Darends (including demands of~ Agency members re served directly or indirectly Peak Demands of Agency hers Ncw Served Directly or Irxlirectly VEPCO VEPOO peak Demands (excluding demands of Power Agency chambers served directly or indirectly(/>
1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 8323 8330 8634 8876 9133 9405 9584 9715 10,020 10'15 10,621 10'33 llew 251 92 (2/)
134 (2/)
374 390 405 420 435 450 465 481 496 511 526 8231 8196 8260 8486 8728 8985 9149 9265 9555 9834 10gl25 10g422 10i725 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 Question 5
State applicant's minimum installed reserve cri-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, iden-tify the other systems and provide minimum installed reserve criterion (as a percentage of load) by contracting parties or pool for the period when the proposed unit will first come on line.
~Res onse:
Pursuant to Section'.4 of the Power Coordination Agreement, CP&L will sell and Power Agency will purchase in each year Reserve Capacity equal to a percentage of Power Agency's Retained Capacity in that year.
The percentage will be based on the percentage reserves maintained by CP&L for the Combined System (CP&L's System plus Power Agency's 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 CP&L a monthly Reserve Capacity charge for each kilowatt of Reserve Capacity based upon CP&L's overall average annual production costs and production capability.
A part of the reserves purchased by Power Agency are Spinning Reserves.
Spinning Reserves are reserve capability maintained on the CP&L System as capacity immediately available for rapid increases in load and when other resources are -unavailable due to forced outages.
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.',
(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).
~Res ense:
As noted in response to Question 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 preceding year for the Combined System.
Question 7
Indicate whether applicant's system interconnections are credited explicitly or implicitly in establishing applicant's installed reserves.
Power Agency's system interconnections are credited implicitly in establishing installed reserves.
0 Question 8
List rights to receive emergency power and obliga-tions to deliver emergency power, rights or obliga-tions to receive or deliver deficiency power or unit
- power, or other coordinating arrangements, by reference to applicant's Federal Power Commission (FPC) rate schedules (i.e.,
ABC Power and Light Co.,
FPC Rate Schedule No.
15 x,ncluding supplements 1-5),
and also by reference to applicant's state commission 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.
~Res onse:
The Power Coordination Agreement between CPEL 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 and Power Agency (the Agreement for Interim Electric Service and the Agreement. for Transmission Use and Other Electric Service) provide transmission, emergency and certain other services suitable for Power Agency's needs when combined with the arrangements with CPEL.
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 requirements for power and energy through Supplemental Capacity and Energy.
The backstand arrangements are firm as opposed to an "as available" basis.
38-Because the aggregate of Power Agency's ownership interests in the Joint Units is in excess of Power Agency' base load requirements 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 Agency's ownership interest in each Mayo and Harris Unit (Purchased Capacity and Purchased Energy).
In the first year of Commerical Operation of each 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 Capacity.
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 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 margin over Power Agency's costs which contributes to the economic desirability of the project.
In addition, Surplus Energy from Power Agency's Retained Capacity in any Joint Unit may be sold to CP&L or to others pursuant to Article ll of the Power Coordination Agreement.
In light of CPEL'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 necessary 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.
Question 9
'List, and provide the mailing address for 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 the applicant.
Provide 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.
~Res ense:
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.
Power Agency does not have any generating or transmission facilities and therefore the request for a geographic one line diagram of its existing facilities is not applicable.
There are'a number of electric membership corporations served by CPSL and VEPCO which neighbor the members of Power Agency.
Those served by CPSL are:
0 Brunswick Electric Membership Corporation P.O.
Box 826
- Snallote, NC 28459 Carteret-Craven Electric Membership Corporation P.O.
Box 1499 Morehead City, NC 28557 Central Electric Membership Corporation P.O.
Box 1107
- Sanford, NC 27330 Four County Electric Membership Corporation P.O.
Box 667
- Burgaw, NC 28425 French Broad Electric Membership Corporation P.O.
Box 9
- Marshall, NC 28753 Halifax Electric Membership Corporation P.O.
Box 667
- Enfield, NC 27823 Haywood Electric Membership Corporation P.O.
Drawer 9
Waynesville, NC 28786 Harkers Island Electric Membership Corporation P.O.
Box 198 Harkers Island, NC 28531 Jones-Onslow Electric Membership Corporation 259 Western Boulevard Jacksonville, NC 28540 Lumbee River Electric Membership Corporation P.O.
Box 830 Red Springs, NC 28377 Pee Dee Electric Membership Corporation P.O.
Box 859 Wadesboro, NC 28170 Piedmont Electric Membership Corporation P.O.
Drawer 1179 Hillsborough, NC 27278 Pitt
& Greene Electric Membership Corporation P. O.
Box 249 Farmville, NC 27828 Randolph Electric Membership Corporation P.O.
Box 40
- Asheboro, NC 27203 South River Electric Membership Corporation P.O.
Drawer 931
- Dunn, NC
.28334 Tideland Electric Membership Corporation P.O.
Box 158
- Pantego, NC 27860 Tri-County Electric Membership Corporation P.O.
Box 130
- Dudley, NC 28333 Wake Electric Membership Corporation P.O.
Box 872 Wake Forest, NC 27587 One municipal electric system is a customer of CPEL 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, nine municipal electric systems are wholesale customers of members of Power, Agency.
They are:
Customers of the Cit of Wilson Town of Black Creek Black Creek Electric Department P.O
~
Box 8 Black Creek, NC 27813 Lucama Electric Department Town of,Lucama P.O.
Box 122
- Lucama, NC 27851 Town of Macclesfield P.O.
Box 185 Macclesfield, NC 27852 Town of Pinetops Drawer C
- Pinetops, NC 27864 Stantonsburg Municipal Light Department Town of Stantonsburg P.O.
Box 1'74 Stantonsburg, NC 27883 Walstonburg Electric Department Town of Walstonburg P.OS Box 86 Walstonburg, NC 27888 Customer of the Cit of Rock Mount Sharpsburg Electric Department Town of Sharpsburg P.O.
Box 305 Sharpsburg, NC 27878 Customer of the Town of Farmville Fountain Electric Department Town of Fountain Box ill
- Fountain, NC 27829 Customer of the Town of Tarboro 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.OS Box 26 Oak City, NC 27857 The electric membership corporations located in 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 Halifax Electric Membership Corporation P.O.
Box 667
- Enfield, NC 27823
44 Roanoke Electric Membership Corporation P.O.
Box 440 Rich Square, NC 27869 Tideland Electric Membership Corporation PE 0.
Box 158
- pantego, NC 27860
Question 10 List separately those systems 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 applicant.
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.
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.
46 Question ll 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 and kilowatt hour costs divided by the kilowatt hours.
If wholesale sales are made at varying
- voltages, indicate average costs at each voltage.
~Res ense:
At the present
- time, power Agency does not generate or sell power.
47 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 power supply expansion program of which the subject unit is a part, in terms of dollars per kilowatt per
- year, in mills per kilowatt hour and in both the kilowatt costs and kilowatt hour costs divided by the kilowatt hours.
Also state separately the most recently estimated cost of subject unit(s).
~Res ense:
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 fueling and placing into commercial operation of the Joint Units are shown in attached Tables X-2, X-3, and X-4 (lines 1-5).
Table 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,
$/kW of capacity, mills/kWh of energy costs, and total cost in mills/kWh.
Also shown are the project Retained Capacity, project output, and capacity factors.
The credit shown for capacity costs in some years reflects periods 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 costs 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 CP5L under the Power Coordination Agreement.
Charges in
$/kW/yr for Supplemental 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 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 CPEL System are also included in Schedule 3.
t TABLE X-2 ESTIMATED CLOSING AND INITIALFUELING COSTS FOR POWER AGENCY6S OWNERSHIP INTERESTS IN UNITS IN COMMERCIAL OPERATION THE BRUNSWICK UNITS AND ROXBORO UNIT NO. 4 [1)
~
(Dollars in Thousands)
Line No.
(a)
Brunswick Units (b)
Roxboro Unit No. 4 (c)
Estimated Closin Costs Costs as of December 31, 1979 f2J Plant Additions Subsequent to December,31, 1979:f3J 2
Direct Costs f4) 3
.Indirect Costs [5]
4 AFUDC f6]
5 Tax Effects f7) 6 Total Estimated Closing Costs
$1999436
.24 '69 861 1,796 1 221 6227 483
$36,115 2,542 1,435 652 640 855
$770/kw [8)
$476/kW [SJ 8
Total Estimated Costs of Initial'Fueli 9 16 765 [9[
9 2 027 [10[
$ 57/kN [8)
$ 24/kW [8]
Total Estimated Closing Costs and 10.
Costs of Initial Fueling 6244 248 842 882 12 Maximum Net Dependable Capability (MNDC)[ll]
$827/kW [8) 295+5 MW
$500/kW [8]
85' MR
'T1 of the Brunswick Units and 13 2X of Roxboro Unit No. 4 at each of three separate closings occurring January 1, July 1, and December 1,
1982, respectively, and 100X participation in the proposed Project by Power Agency Members.
[2)
Pursuant to Article 4 of the Sales Agreement.
[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.
[4J Direct costs include materials9 labor, and other construction costs.
[5)
Indirect costs include capitalised overheads such as certain taxes end employee beneffts.
f6)
Power Agency's share of CP&L's estimated AFUDC on plant additions after December 31, 1979 and AFUDC on the total Roxboro Unit No. 4 from December 31, 19?9 to the, date of commercial operation of this Unit.
[7)
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 on plant additions as pro-vided in the Sales Agreement.
[8)
Total estimated cost divided by MNDC as shown on line 12.
f9)
Based on CP&L estimates of the net nuclear fuel-in-reactor at Brunswick snd reload fuel-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.
[ll)
Based on assumptions outlined in footnote fl) above and an MNDC of 1580 MR for the Brunswick Units and the present rating of 650 MW for Roxboro Unit No, 48
TABLF K-3 EBTIHATED CMSINO CONSTRUCTION AND INITIALFUELINC O)STS FOR PONER ACENCI'8 ONNERSNIP INTERESTS IN UNITS M)ER C)NSTRUCTION TNE NATO AND HARRIS UNITS I Dol are in Thousan s
Page 1 nf 2 Lfne No, Estfnatcd Closin and Constructfon Costst Ha o Units Unit 1 2
Unit 2 Tbb T00 Harris Units Tote Unit 1 2
Unit 2 Unit 3 Unit T44
~e)
~i
~s
~a)
Total Closing Costs>
Dl.rect Costs
)4J'ndirect Costs )5)
Hanage23sent Fees (6)
AFUDC )7)
Tax Effects )8)
Total Closfng Costs S 62>590 19078 929 13,619 9 101
~8 Ml S
1,745 50 25 539 336 2,6 5 S 64 '35 1 ~ 128 954 14,158 9 437 7 90,0V S153,214 5,282 2,299 46,960 29 160 S2369923 S 32,074 1,067 485 13>574 7 930
~ss,T)o 7,287 173 110 2,984
~4774 12>328 S 11,462 310 172 50406 3 144 S
ZOSS9 S
204,037 6,832~
3,066 68,924 42 016
~032, 0 7 5 10 Construction Costs Subsequent to Closfngs>)9)
Direct Costs
)4J Indirect Costs (5)
Hansge2>ent Fees
)6)
Total Construction Costs Subsequent to Closfnge 6,010 416 89 S 91,660 1>492 1 373 S 97,670 1>908 1 462 S 57,427 7>501 890 S100>097 7>657 1 530 S216>707 15,993 3 317 S202,379 13,951 3 089 S
6,515 S 94,525
$101,040 S 65,818 S109,284 S236,017
$219,419 576,610 45,102 8 026 o
630,538 11 Total Eetfnated Closing and Construction Costs 12 S/KN )10)
Eitfnated Costs of Initial Fuelfn t 13 At Closinge 1
$790
$818
$804
$2,039
$ 1,107 Sl,672 Sl>616 Sl,608 S
l>451 S
1>451 S
S S
S
~
S
~93 032 0 97 220 8497 052 8302 741 S164 414
$24034S S239 913 8
955 413 14 Subsequent to Closinge )ff) 15 Total Eetfeeted Costi of Initial Fueling 16 8/kU )10)
$25
$52 S68
$88
$282 1 Sll 6 137 7 660 10 143 13 125 41 950
~2962 0
6 157 8
9 119 8
10 143 S 13 125 0 41 950 S245
$ 171 36 392 101 610~
8 36 392 8
101 610 Total Eetfuated Costs of Closing, 17 Construction, and Initial Fueling 0 96 794 8105 377 0200 171
~372 804 0177 539 8290 295 S276 305 Sl 057 023 18 S/kU )10)
Sgls
$870 S842
$20107
$ 1>196 Sl>955 S10861
$ 10779 Expected Maxfuun Net Dependable 19 Cepsbfffty (lO!DC) in MU ) l2) 11808 118.8 237.6 148 ~ 5 14805 148.5 148.5 594.0 20 Scheduled Date nf Im>>>crcfaf Operatlnn 4/1/83 4/I/90 10/1/85 4/1/88 4/1/94 4/1/92 (Fontnnte>>
nn fnffnSsfnR psSRe)
5l-TABLE X-3 Page 2 of 2 ESTIMATED CLOSING, CONSTRUCTION, AND INITIALFUELING COSTS FOR POWER AGENCY'S OWNERSHIP INTERESTS IN UNITS UNDER CONSTRUCTION THE MAYO AND HARPZS UNITS Footnotes
[1]
Assumes Power Agency closes on 33X, 36X, and 31X of its Ultimate Ownership Interest of 16.5X in each of the Mayo and Harris Units at each of three separate closings occurring January 1,
July 1,
and December 1,
- 1982, respectively; 100X participation in the proposed. Project by Power Agency Members; and the scheduled dates of Commercial Operation as shown on line 20.
[2)
Amounts for land and common facilities necessary for the operation of each of the Mayo and Harris Units are included in amounts shown for Mayo Unit 1 and Harris Unit 1, respectively.
[3]
Estimated aggregate amounts to be paid to CP&L by Power Agency at the clo-sings outlined in footnote [1] based on cost estimates provided by CP&L.
[4]
Direct costs include materials,
- labor, and other construction costs.
[5]
Indirect costs include capitalized overheads such as certain taxes and employee benefits.
[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 Harris Units calculated as 1.5X of CP&L's direct and indirect costs of construc-tion less gross investment in land, capitalized property
[7]
Power Agency's share of AFUDC incurred by CP&L prior to the closing dates 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 for CP&L's AFUDC as provided under the Sales Agreement.
[9]
Estimated amounts for Power Agency's share of construction costs subse-quent to the closings.
[10)
Total estimated cost divided by MNDC as shown on line 19.
fll) Estimates of costs associated with the Initial Core at each Harris Unit 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.
[12)
Based on assumptions outlined in footnote fl] above and the expected MMDC of 720 MW and 900 MW for each Mayo and Harris Unit, respectively.
TASLE R-4 TOTAL ESTINATED PRINCIPAL AIIOUNT OF SONDS ALLOCATED TO JOINT FACILITIES AND NORRINC CAPITAL Dol sre in Thousands Lfni Noe Srunsvlck Unite Roxboro Its o Units Unit No. l n t nt Harris Units nt Unt nt nt Ttt TER Ttt "Tlt
'Nocking Capital
~nd Povcr Agency Ex cases Totsl-Propoccd
~Pt Closfn Coastructfon snd Fuel Costs C ocfng en Construct on oats Intttal tuclfng Costs (3l Reload Fuel Expense (4)
Inlttal Cspttal Additions nfl
$2270483 16076f 12,591 73 370 gl0085$
2 0021 Ilg 8 93,832 20962
$ 91,220 6,lfy
$302 ~ 741 10,143 6,61f
$ 164,414 13,125 150445
$248,34f 41,9$ 0 24,992
$2390913 360392 20,292
$ 1160271 l2l
$ 1,531,0 129,$
79,941 15
$26 f
Total Direct Costs 6
Investacnt Earnings l6) 7 Nct Dtrect Costs
$272,223
~3 733)
~6)
~392>
$2690090
$43 024
$ 96,402
~>0 283)
$ 93,094
~695l)
~12 993)
~30 741)
~28 035)
$312054S
$ 1790991
$28le546
$268 ~ 562 8
Cross Interest During Construction [7) 8 40,326
$ 6,447
$ 51,092
$ 104,193
$343,660 9
10 11 tiaaacta Rc ulresents Dcpos ts tot Sond tund Reserve Account (SJ 40,326 Reserve end Contingency tund l9j 4,034 04 ttt 7<'l<
t 6 91 tt 80
~t I>el 12 031 6,4ly 19,223 64$
1,922
~2052 5 116
$271,409
$l99,426
$456,805 230126 S10018 530952 20313 80102 f0395 0 070 27 033 IS 525 91,900 8$,116 90190 80517 32 099 29 709
$430030
$ 960794
$ 103 ~ 311
$3190499
$ 1920984
$3150287
$2960597
$ 116 0 211
$ 116,271 14,138 10415 I 781
$ 107560068 (92 534>
$1,663,534 I
$ 1,113,358 bJ I
415,306 41,533 lll 22 ~
12 Total Eattsstcd Prfact al Asount of Sends
$366 601
~5S 615 ett>4 77352$
~l3D 004 6172 361
~H9 272
$ 927 161 6840 769 4136 611 64 034 9$ 5 (21 Prelfstnsry csttacte of Pover Agency's <<orking capital rcqulreaerits as each unit is placed tn service as <<ell ae adsinlstrattve expenses assoctntcd with untts under construction.
[3) Pros Table 2 2 ~ Itnc he for Srunswfc'k Plant end Roxboro Unit No. 4 end froa Table X-30 line 15, for Nsyo snd Narrts Unite.
[4) Pover Agency's share of reload fuel payscnts through approxtaately tvelve aontbs followtng the closing dates for the Srunswick Unite and for tvelvc sonthe following the currently scheduled coaacrctal operation dates of each harris Untt, based on cstiaatcs provided by CP6L.
f Costs subsequent to the closing dates for capital additions under vay, authorised, or planned as of such dates as cstlsetcd by CPALD 6
At 122 tn 1982 on unexpended asounts deposited into the Construction Account froa Sond proceeds snd at 112 thereafter<
1 At 11'I on honda Issued ln 1982 end 102 on ell honda issued tbereeftere Accuses one year' funded interest on the portton of each Issue allocable to the Srunsvtck Untte end tn Roxboro Unit No. 4 and tvo years'unded interest after the currently scheduled cosserclal operation States of each Nsyo and Narrte Unft.
fgl Equal to sext<<us annual interest on all honda issued end allocated to each Joint tectltty end to vorklng capital and Power Agency expense.
l9J At 102 of the Rond Fund Reserve Account rcttutrcacnt
[IOI 84Iusl tn 3.52 of the total cattasted principal asount of Sands.
HORTH CAROLIHA flUHICIPAL POHER AOEHCI HUHSPR 3
PROJECTED OPBRATIHO RP>BOLTS URDAR PROIOSED ARAAHOBIIEHT HITS C I 6 l.
CASP. A SCIIBDULE 1 SUtltIARI OF PROJPCT COSTS DBSCRIPTIOM 1982 1983 1984 1985 1986 1987 1988 1989 BRUHSIIICK HBT CAPACITI COSTS HET BHr>RoI cosTs TOTAL HET COST.'I BOOO 0000 0000 tl)
(21 (31 0 (lr539) 0 21 ~ 119 3r 578
'lr838 0
2r039 0 28 ~ 956 0 45 ~ 667 9r 757 0
46,285 0 46r969 11 ~ 242..
12r 342 0 47,7l 4 13r 150 0
48> 536 15 ~ 136 0 49'31 18'70 0 55 424 0
57 527 B 59,312 B 60'64 0 53 ~ 671 D 67'01 HP>T PROJP>CT CAPACITI HE1'ROJFCT OEIfERATIOH CAPACITI FACTOR IUI OlfH til 158 ~ 3 295 >5 (51 738 '
1 ~ 490 '
(61 53r22 5'1 ~ 59 29S >5 lr746 ~ 1 67> 46 295r5 1 ~ 746 ~ 1 67 ~ 46 295 '
1 ~ 746 '
57'6 295 ~ 5 lr746 ~ 1 67'6 295 ~ 5 1 ~ 746 ~ 1 67'6 295 '
1 ~ 746 '
67'6 HEI PROJECT FIXP>D COSTS OIXff HEI PROJECT EffBROI COSTS HILLS TOTAL IIEl'ROJECT COSTS HILLS t7J (9>72) 71>48 (81 i>BS 5 ~ 26 t9) 2r76 19 ~ 43 154>56 5>59 31 r74 15'5 5>44 32 ~ 95 158> 97 7007 33r97 161 ~ 49 7>53 34>86 16'7 8'7 36>46 167 30 10'5 38'6 HARRIS HET CAPACITI COSTS HBT BHEROI COSTS TOTAL HET COSTS eooo 0000 F 000 t 1 I 1 (12) 0 (6,842) e(17.406) e(21 ~ 807) 0 (42,161) 0(62,630) e(45.545) 0 10,307 546 lr800.
Dr 261 4 ~ 917 0
11 ~ 611 7 ~ 090 f13f 0 (6 842) 0(17 406) 0(21 '07)
B (BI~ 615) 0(60 830) 0(43 28S) 0 15'24
~ 18 701 HBT PROJECT CAPACITI HET lROJECT OEUHRATIOH CAPACITI FACTOR HET PROJECT FIXED COSTS HBT PROJECT BHPROI COS1'S TOTAL HET PROJPCT COSTS IN AHII 0/KH IlIfLS tillLB (14 1 f15 J t 161 f 17)
(18) t 191 18> 6 132 ~ 8 Bl ~ 67 (2r 2'll ~ 29) i>i 1 (313> 38) 74' 396rB 61 F 00 (843.5O) ir54 (153'2) 79 '
468.1 67>46
( 5'l5 ~ 07) 4 83
( 92 ~ 48) 139 '
805 ~ 9 65 F 81 73 ~ 73 6 ~ lo 18 ~ 89 168. 3 949 ~ 8 64 F 42 68'9 7'7 19.69 ROXIIORO IIBT CAPACITI COSTS HET rHEROI COSTS TOTAL HPT COSTS OOOO BOOO 0000 (21) 0 (432) 0 3r 320 f221 4 ~ 735
'lr'164 B
6r 791 1 1 ~ 141 B
6r 871 0
6 ~ 964 0
7 ~ 046 9>234 12r991
. ll~ 130 0
7r 164 16r 306 0
7 ~ 262 12'64 (231 0
4 ~ 303 0
11 ~ 084 0 17r 932 0
16 ~ 105 0 19r 955 0 18r 1 16 0 '23r 470 0 19 ~ 726 HET PROJECT CAPACITI npT pRoJrcT op. IBRATIoH CAPACITI FACTOR HET PROJECT FIXPD COSTS HEI'ROJECT BIIEROI COSTS TOTAI> IIBT PROJECT Co.>TS
)N OIIII B/Klf IIILLB HID(>S f 24) f25)
(2<)
( 77) 1 7" 1 I 791 46 00 235 ~ 2 58>41 (9'9) 7.0 ~ 13 lA~ '29 85 '
327 '
43 ~ 53 3A ~ 69 2 3 ~ 73 33 ~ AA A5 ~ 8 437 ~ 4 58 20 79 ~ IS 25 ~ 47 40> 99 85 ~ 0 327 '
43 ~ 53 AO ~ 08 2A>22 49 ~ 22 85 ~ 8 437 '
58%20 Al ~ 17
- 7. 9 ~ 70 45'2 AS. 8 327 '
43>53 82 12 34 F 02 55 >55 85 ~ 8 437> 4 58 F 20 83 ~ 50 37 ~ 28 53 ~ 65 AS'
- 37. I ~ 2 43>53 Bing 64 3A ~ lo 60 ~ 29
NORTH CAROLINA tlUNICIPAL PONHR AOHNCI HUNBBR 3 PROTECTED OPPRATINO RFSULTS UNDER PROPOSED ARRANOENENT NITll C P
6 L CASFe h SCHHDUteF.
1 - SUNtlhRI OF PROJECT COSTS DWCRIPTIOH 1982 1983 1984 1985 1986 1987 1988 1989 NAIO NFI'APACITT COSTS NHT ENEROI COSTS TOTAL NHT COSTS 0000 0000 0000
( 31) f 32) 0 (2r254)
(33) 0 (2r254) 0(lle010) 0 (9e 926) ie905 5r139 0 (6e 105) 0 (3r 78't) 0 ~
6r 270 9e 073 0 llr798
- 8. 36S 0 11 ~ 362 12r319 0 10'98
)Or723 0
6 ~ 522 17r 403 0.
15 ~ 342 0 20 163 0 23r681 0 21 521 0 23,925 NET PROJECT CAPACITI HET PROJECT OHNERATIOH CAPACITI FACTOR till OMN
( 34)
(35 )
f36) 44 '
228 '
58'7 63 '
242 '
43'9 57 ~ 3 34 3 ~ '2 5Se20 71 ~ 3 272 '
43 ~ 69 75 '
383 '
SRe20 79 ~ 2 303 ~ 1 43'9 83 ~ 2 424 '
58 ~ 20 NEF PROJECT FIXED COSTS 0/KN NET PROJECT ENEROI COSTS HILLS TOTAL NET PROJECT COSTS HILLS t 37) f38)
(39)
(247'5) 2le50 (26'6)
(156 ~ 65) 25 ~ 31 (1$ ~ 6'2) 93 ~ 13 26 ~ 43 44 ~ 70 165 '1 30'6 73'1 151 01 32e)1 61e73 136 '4 3S.38 71 F 00 78 ~ 43 41 e05 56 ~ 43
'TOTAL PROJECT COSTS NET CAPACITI COSTS NHT HHEROI COSTS TOTAL HHT COSTS 0000 0000 0000 (101) 0(11'6't)
(102)
Br 313 f.103) 0 (2r 754 )
0 (3e978) 0 20e725 20'07 27r037 0
17r 265 30r 095 0
3,101 35r499 0 20r577 38e 859 0 76 ~ 804 47'82 0 74r 826 55'27 0 16 529 0 47 762 0
47 359 0
38 600 0 59 436 0123 886 0129 853 NEF PROJECT CAPACITI HHT PROJECT 0)91HRATIOH CAPACITI FACTOR Elf OHll (104) 204 '
(105) 973 '
( 105) 54 ~ 39 425 '
2r045 ~ 8 54'5 444 '
2'26eO 52 ~ 29 467e 1 2r 549e 3
. 62'0 S26.8 2r853 ~ 1 61'3 535 '
600 '
2r 924 e 9 3r 292 ~ 6 62'3 62'2 632 ~ 7 3r 447 ~ 0 62 ~ 19 HFT PROJECT FIXED COSTS NET PROJECT ENFROI COSTS TOl'AL NET PROJECT COSTS 0llrN tlILLS HILLS (107)
(Sie17) f 108)
Be54
( 109)
(2e 83)
(9 ~ 34) 10 F 02 8 F 08 46e 61 11 14 19e69 35'6 11 81 18e58 5 ~ 89 12 ~ 4 ~
13e53 38 ~ 41 13e29 20'2 127.95 14'0 37 63 118 26 lse96 37'7 to Ol OO 0'r lO IV O
I
NonTlr chRoLIHA trvNIcIPAL POHER AOEHcr Hvtlnnn 3 pnoJECTED or EHATltro RrsvLTS vrrven PROPOSED ARRANOPdrEHT ttITlr C P 6 L CASE A ScrlEDvt.E l - SUNHARI nF PROJECT COSTS DESCRIPTION 1990 1991 1992 1993 1994 1995 1996 1997 BRUHSltICK HET CAPACITI COSTS trET ENEROI COSTS TOTAl HET COSTS e000 rrvoo 0000 fll
)2) f3)
B sor419 21 ~ 731 0 51 ~ 508 27'29 e S2,69S 33r Ilrrn 8 53 ~ 998 36r 247 0 72 150 0 78 537 0
86 576 B 90 245 0 55'35 39r895 0
95 ~ 330.
e 57,ooo 43r 466 0 58r 729 47 ~ 539 B 60 ~ 625 51 '83 Bloods 467 0106 '68 6112 ~ 608 HET PROJECT CAPACITI NET PROJECT CEHERATION CAPACITI FACTOR NET PROJECT FIXED coSTS e/rrH NET PROJEcT ElrEROI coSTS HILLS TOThl NET PROJFCT COSTS III'LLS fil
'29 5 ~ 5 f5) 1 ~ 746rl f6J 67 46 fV) 170 '5 fe)
, 12'5 f9) 41 ~ 32 295 as lr746 1
67'6 174 ~ 33 15 48 44 98 295 '
1 ~ 746 ~ 1 67'6 178 35 19r40 49r58 295 ~ 5 1 ~ 746r 1 67 ~ 46 182'6 20'6 S1.6e 295 '
1 ~ 746+1 67 F 46 187e62
'2 ~ 85 54'0 295 is 1 ~ 746 ~ 1 67 ~ 46 192'2 24+89 5V F 54 295 rS 1 ~ 746rt 67'6 198 ~ 77 27 23 60+86 295 ~ 5 1 ~ 746 '
67.46 Zose19 29 F 77 64'9 llhn'nls NET CAPACITI COSTS NPT ENEROI COSTS TOTAL HET COSTS en00 0000 flZJ 8 55r930 9r 686 rr 56r 313 13r 728 8 40 ~ 039 23r 380 8 30r 283 28r 350 o 89.238 39r 416 trl23r856 4 fr 924 rrZ Isr 884 57 F 299 0250 ~ 605 67'45 0000 f13J 0 65 ~ 616 8 70 ~ 041 8 63 ~ 419 0 58 632 0128,655 rrlVI~ 779 8273 183 e317 651 NET PROJECT CAPACITI NET PROJECT OENERATIolr CAPACITI FACTOR trH f14) olrfr f 15) f 16) 178 ~ 1 1 ~ 052 '
67'6 188 F 1 lrlllr6 67'6 253r6 1 ~ 478 ~ 7 66 ~ 55 287 '
1 ~ 651 r 9 6s.6e 357 ~ 6 2 ~ 093r 0 66 ~ 82 396ro 2'95 F 4 66+17 415 ~ 7 435 6
2'57 '
2'74 '
67'6 67'6 NPT PROJECT FIXED COSTS 6/XH flVJ NET PROJECT EHEROI COSTS trILLS fle)
TOTAL HET PROJECT COSTS trIILS f19) 313'5 9'0 62'2'99~38 12r35 63rol 15V F 86 15 ~ 81 42'9 los.ie 17r 16 35 ~ 49 249 r56 lent 83 61'7 312r77 Zo.ee 74 '4 519 F 26 23r 32 ll1 19 575'1 26 ~ 04
. 123'9 Roxrrono NET CAPACITY COSTS NEl'HEROI COSTS Boon f 21) 8000 f 22) 8 Vr 396 rr 7 515 lrrr013 14 ~ 6SO e
7r 683 22r 570 0
7'25 ler235 rr Br 018 24'05 0
8 ~ 191 21 ~ 404 B
8'24 31r198 0
Br 626 25 F 440 TOI'AL NET COSTS 0000 f 23) 8 Z5r 409 0 22 165 B 30 ~ 253 rr 26 ~ 060 0 32, 923 0 29 595 8 39 ~ 623 8
34 ~ 066 HET PROJPCT CAPACITI NET PROJECT OEHERATION CAPACITT FACTOR tlET PROJECT FIXEfr COSTS trET PROJECT EHEROT COSTS TOTAL tfFT PROJECT COSTS trH f24)
OHIr f25 J
~ f 26)
BIKH f 27)
HILLS f 2fl) trILtA f29) 8' 437 F 4 58'0 86 ~ 20 41 ~ 18 sn+09 85 ~ 8 327 ~ 2 43 ~ 53 87 ~ 58 44 ~ 7fl 67 ~ 75 85 '
437 ~ 4 58 ~ 20 8'5 51 '0 69 ~ 16 85 ~ 8 327 '
43+53 9lr20 55'4 re 65 85 ~ 8 437 '
5.8 ~ 20 93'5 56 ~ '93 75 ~ 26 85' 327 ~ 2 43+53 95 ~ 47 65 ~ 42 90 F 46 es. e 437 '
sent 20 98 ~ 18 71 ~ 32 90'n 85 ~ 8 327 r2 43r53 100'3 77'6 104'2
NORTH CAROI,INA tlUNICIPAL PollFR ACFNCT NUflHPR 3 PROJECTED OPERATINC RESULTS UNDER PROPOSED ARRANCPNPNT MITS C P 6 L CASE h SCHEDULE I SUNNART OF PROJECT COSTS DESCRIPTION 1990 1991 1992 1993 1994 l995 1996 1991 NATO NET CAPACITT COSTS NET ENERCT COSTS TOTAL HEI'OSTS 0000 0000 eooo
)31)
) 32J 0
1 ~ 519 25rzl5 0
3r 344 34'36 e 24r062 35r 757 0 32r.843 42 ~ 182 0 34 ~ 495
. 47rl43 0 36r 211 56'57 8 38r 030 61 '70 8 39r 990 72 ~ 684
)33) 8 26 734 0 37 580 0 59'19 0 75'25 0 81'39 0 92'68 0 99 F 400 0112 ~ 674 NET PROJECT CAPACITT NET PROJECT ClÃERATION CAPACITT FACTOR Nll CNH (34)
(35)
) 36) 131 e7 561 o6 48 ~ 69 154 ~ 4 70600 52 ~ 18 162.4 707+0 49 ~ 71 1'lo ~ 3 776m 5 52'6 I'I8 ~ 2 777 ~ 7 49 ~ 82 l86 ~ I 841 el 51 ~ 96 194eo 848 ~ 3 49 ~ 91 202 ~ 3 919 F 4 51 ~ 88 NET PROJECT FIXED COSTS 0/Xff NET PROJECT ENERCT COSTS HILLS TOTAL NET PROJFCT COSTS HILLS
) 31)
)38)
'(39) 11'4 44'0 47+60 Zl ~ 65 48'9 53+23 148+20 50'8 84+61 192 F 88 54'2 96'1 193 SB 194'6 60'2 66'9 104 98 109roi 195 '9
- 12. ~ 34 117'7 19'I ~ 69 79 F 05 lzzoSS TOTAL PROJECT COSTS HET CAPACITI COSTS NET ENERCT COSTS TOTAL NET COSTS 0000 0000 8000
)101)
) 102)
) 103) eilS,z65 74 ~ 645 0189r 910
~
0118r680 89r642 0124r480 115'87 0124,949 125r013 0187r IB'I 151 ~ 360 0225 ~ 258 168 ~ 951 832lr068 191 ~ 406 0359r 846 217 ~ 1S3 8208 ~ 322 0'240 061 0249 963 0338 547 B394 209 8518 474 BS76 ~ 999 NET PROJECT CAPACITT NFT PROJECT CENERATION CAI'ACITT FACTOR Nlt CNH (104)
)105 J
. )106) 691 o I 3r'198 ~ 0 6'2 ~ 74 723+8 3r890 ~ 9 61'7 797+ 3 4 ~ 369+2 62'd 838 ~ 6 4 ~ 501 ~ 7 61 ~ 28 917+0 Sr054 ~
'2 62 963 ~ 4 5 ~ 215 ~ 8 61 F 80 991 1
5'88 '
63'2 1 ~ 019+2 5 ~ S67 oo 62'6 NET PROJECT FIXED COSTS NPT PROJECT FNPRCT COST'S TOTAL NET I'ROJHCT COSTS 0/Elf NILLS HILLS
) 101)
(108)
) 109) 166+79 19'5 So+00 163m 97 23 04 53+54 156 ~ 13 26+ 45 Sic 94 148m 99 204 o 12 27r77 29'5 55r53 66i98 233.82 32'9
'IS r58 32 3 ~ 97 3S ~ 96 94'6 353eoo 39 ~ Ol 103 65
NORTH CAAol.IHA MUNICIPAL POMPR ACENCI NUMBER 3 PROJECTED OPHRATINO ADULTS UNDER PROPOSED AAAANOHMHAT HITII C P 6 L
- CASP, A
SCIIBDULH I - SUMMARI OF PAOJBCT COSTS DBSCRIPTIOH 1998 1999 2000 2ool 2002 2003 BRUNSNICK NET CAPACITI COSTS HF>>T EHHRCI COSTS TOTAL NPT COSTS 0000 0000 t 1 l t2) 0 62r 104 56 ~ 609 0 54 ~ 980 61 824 0 57>>4BS 67 ~ 602 0119>> 312 0l26r>>I04 0135>>081 0 70'30 73>> 912 0144 '42 0 73>>242 Bor 801 0154 ~ 043 0 76 ~ SSS 88>>309 0164.e6s NEl'ROJECT CAPACITI NEI PROJECT CEHBRATIOH CAPACITI FACTOR NET PROJECT EIXPD COSTS NEI'ROJECT EHERCI COSTS TOTAL HBT PROJECT COSTS HARRIS NH CHN 0/XH NIlLS NILM til ts) t6) t7) feJ t9) 295>>5 1 ~ 746>>l 51>> l6 212 F 22 32 F 42 6A ~ 33 295 '
I ~ 746 '
57 ~ 45 219'3 35 ~ll 12 ~ 62 295 5
I ~ 746 ~ 1 67>> 46 728 ~ 41 38'2 71>> 37 295 S
1 ~ 746>> 1 67>> 46 237 70 42>>33 82'5 295 5
1 ~ 746 ~ 1 57.i5 247'9 46'8 88'2 295>>5 1'746 1
61 ~ 46 259 11 50>>58 94'2 I
I HET CAPACITI COSTS NET EHBRCI COSTS TOTAL HBT COSTS 000O 000O 0000 fll)
. )12) 0261r 769 17>> 622 0280 ~ 211 90r 005 0293>> 574 104 ~ 291 0301 ~ 220 120r165 03 l9 ~ 428 136>> 698 0332r084 154 '23 f 13) 0345 391 0310 276 0397 865 0427 385 0456 126 0486 ~ 901 NPT PROJECT CAPACITI NBT PROJECT CEHERATION CAPACITI FACTOR NH CHN fli) t 15) f 15J 455 '
2>>691 ~ 0 67'6 415 ~ 2 2r 808>> 3 61 ~ 46 495>>4 2 ~ 928 ~ 0 67'8 514 ~ 8 3>> 042 ~ 3 61 46 530>> I 3 ~ l33 i 1 61>>41 544 '
3 ~ 217 ~ 9 61 ~ 46 HET PROJECT FIXED COSTS NBT PROJECT PAHRCI COSTS TOThl HEI'ROJECT COSTS 0/XH NILLS NILES t 17) fle) f19)
SBB ~ 05 28'4 128>> 35 589>>80 32 ~ 05 131 ~ 85 592>>64 35'2 13s.ee 5 96>>18 602 ~ 62 39'0 43'3 140 48 145 58 609>>89 48>>ll 151 '1 ROXDORO HHT CAPACITI COSTS NBT ENHRCI COSTS 0000 0000 f21 J t22) 0 Br 911 37>>002 0
9>> 151 30>> 239 0
9 494 0
-9 ~ 785 44'76 35>>940 0 10 ~ 181 52>> 388 0 10>>532 42>> 118 TOThl HEI'OSTS NHT PROJECT CAPACITI NHT PROJECT CHHHRATION CAPhCITI FACTOR 0000 NH CHN f24 J f 25 J t 26)
BS>>8 431>>l 58>>20 85 '
327 F 2 43'3 es.e 437' Se ~ 20 85' 327 ~ 2 43 ~ 53 es.e 431 ~ 4 SB ~ 20 Bs.e 327>>2 43>>53 f23) 0 45 993 0 39 389 0 53 569 0 45 ~ 125
~ 62 575 0 53 ~ 250 tD Ol 00 O' Qm IhJ NHT PROJECT FIXED COSTS NHT PROJECT EHHACT COSTII TOTAI>> NHT PROJECT COSTS 0/XH Nlt,LS MILLS t 21)
)7e) f29 J l03 ~ 85 84'7 los F 14 106 ~ 65 92'2 l20 ~ 39 l I 0 ~ 65 100 ~ 16 122 ~ 46 1 14 ~ 04 109'5 l 39 ~ 15 I le ~ 73 ll9~ 76 l43 F 05 122>>7S 130 ~ Sl 162'6
HORTII CAROl.IHA HUNICIPAL POHPR ACPHCT HUIIDHR 3 PROJECTED OPERATIHC RESULTS UHDER PROPOSED ARRAHCN1EIIT HITII C P 6 L CASE A SCHEDUI.E l - SvtltlhRT OF PROJECT COSTS DESCRI PTI ON 1998 1999 2000 2001 2002 2003 llhTO NET CAPACITT COSTS NET EHERCT COSTS TOTAL HET COSTS 0000 0000 0000 f31) 0 ily933 f 32) 79e277 f33) 0121 ~ 210 B 43'06 91 i 151 0 44'99 98'46 B 46'76 1 I 1 ~ BS7 0 lsd 462 122r258 0 50e40$
137 ~ 133
~134,558 el43.545 el$ 8,534 0170.720 el81.539 NET PROJECT CAPACITI HET PROJECT CFHERATION CAPACITT FACTOR HH CHII f34) 209+9 f 35]
919+0 f36]
49 ~ 99 213+ 8 968 ~ I Sleds 217 '
221 '
959 '
998+3 50'9
$ 1 ~ 39 225 '
999 '
50~56 229+7 1 '28 '
51 12 HET PROJECT FIXED COSTS NET PROJECT ENERCT COSTS TOTAL HEI'ROJECT COSTS TOTht PROJECT COSTS 0/KH tlILLS llILLS f 37) 199 o V9 f38) 86 ~ 26 f39J 131'9 202+98 94'd 138'9 206 ~ dl 102+72 14 9e 62 210 ~ 48 112 ~ 05 1$ 8.80
- 214 +70 122'8 170+76 219 F 46 133'3 182+ 34 I
Vl I
NET CAPACITT COSTS NET EHERCT COSI'S TOThL HET COSTS 0000 0000 0000 f 101) 0381 31V f102) 250y590 f 103) 0631, 907
~397'01 273'19 0415y552 314 i514 0433 911 34 I 874 045lr318 392r 146
~469 576 422 '84 B671 021 0730 067 0775 ~ VBS 0843 464 0892 ~ $ 60 HET PROJECT CAPACITI HPT PROJECT CEHERATIOH CAPACITT FACTOR HQ CHN f 104) 1 '46 '
f 10S J 5 ~ 't93 ~ 6 f l06 J 63+20 1 ~ 070 ~ 3 5 ~ 849+ 7 62 ~ 39 I ~ 094 ~ 4 I ~ 1 1 V ~ 8 1 ~ 137 ~ 0 1 ~ 155 ~ 4 6'F071 ~ 0 dell3o9
- de 316 ~ 4 6 ~ 319 ~ 6 63e32 62 ~ 44 63+41 62 ~ 44 NET PROJECT FIXED COSTS 0/XH NET PROJLCT ENPRCT COSTS IIILLS TOTAL HEl'ROJECT COSTS tlILLS f 107) 364 o 38 f 108 J 43+25 f 109 J 109o07 371 F 68 46 ~ 71 114+71 379 F 70 51 F 81 120o2$
3S8.1S 5$ ~ 92 126 89 396 e92 62 F 08 133+54 406.40 66 ~ 93 Iilo24 Ie CO U
O O
P M m
I W
Vl
HOATll Chnollnh llUHICIPAL POHBA Aototcl notISPR 3
PROJECTED OPERATIHO RHSUlTS UHDBR PnoroSBD hnnhnontIBHT llITR c P 6 L CASE h SCIIEDUl E 2 PARTIAL AEQUIAEIIBHTS PURCHASES moll CPCL bHSCAIPTIOH 1982 1983 1984 1985 1986 198'7 1988 1989 1990 1>>
SUPPI EIIBHTAL POIIBR SUPPLt2IBHTAL DHtlhHD COST CAPACITI COSTS tnt f 111) 0/KH/ln f 112) 0ooo f113) 806>>2 55>>87 045ro42 628 ~ '7 59'6 037r450 65400 61>>00 039r 891 6'ls ~ 5 69 ~ 71 043>>128 659 ~ 9 695 >>0 102'8 99'3 0 67r426 0 68 F 959 674 ~ 4 l I 3>>96 0 76r 859 686 '
lls>> 64 0 79e 326 671>>1 119>>18 0 80>>053 SUPPLEHEHTAL EHEROI COST EHEAOI COSl'8 TOTAL 8UPPLEtlENTA'L COSTS Onll IIILLS
~000 0000 f 1 l4) f 115 J f 116J 3e 358 ~ 2 15 F 01 050,411 095 ~ 4S1 2rlei ~ 6 16>>65 036e 385 0'73>> 835 I>779 4
2 014>>8 19>> 36 20>>20 034 ~ 457 040>>'loe I>>997 ~ 6 21 ~ 05
~ 42e 051 le 809 '
22 ~ 31 0 Aoe 391 le 'T26>> 3 22>>11 39e 307 l ~ 445>>3
'26 ~ 03 0 3V>>623 1 ~ 434>>0 29 ~ 1'1 0 41 ~ 830 014 348 081 ~ 836 0109 471 0109 350 0116 166 0116 ~ 949 0121 ~ 883 2>> PAOJECE'BSERVE SERVICE RPSERVE CAPACITI IIN f 118)
COST 0/KH/IR f119)
CAPACITI COSTS 0000 f 120) 4'7 ~ 8 54 ~ 17 0 2>>592 80 ~ 6 62'0 0 5'25 109 ~ 1 66 ~ 62 V>> 269 42>>2 T9>> 91 0 fr36S Ve ~ 1
)l9 ~ 6 113 1'7 113 31 0
.8,90V
~ i3,549 107 ~ 4 128 ~ 53 0
13>> 802 149 1
13'6
~ 20esoo 130>>6 1 ~ l >>34 0
18>> ~ 61 RESERVE ENEROI COST RESERVE EHBROY COSTS OHII tllLLS 0000 ff21) f122 )
f 123) 41o.T 15 ~ 01
~
6e 314
'706>>B 16>>65
~ 11'72 955>>8 807>>6 19 ~ 36 20>>10 01e,soe ole.319 689 '
21 F 05 14 ~ 513 l e041e4 21 ~ 32
~ 23r 315 94l ~ 1 22>> 'lT 0 21,42e 1e306
~ 4 26>>03
~ 34 ~ 008 1 ~ 144 ~ 5 29 ~ l'1 0 33e 386 bPPICIENCI EHEAOY COST DrrlcIEncr Eni.nor COSTS ONH NllLS 0OOO f 124) f125) f 126) 2>>5 20>> 93 0
51 24' 22'5 0
562 7>>7 26>>53
~
205 4 ~ 4 27>>8'7 0
124
~ 3 ~ 2 31>>79 0
I~ 313 8>>2 33 ~ 57
~
276 3T>>7 36>>80 0
le386 6 ~ l 41>>92 0
25'7 35 '
45'7 0
I ~ 631 SPlntllno RESERVES COST SPINNINO RESERVES COSTS TOThl RESBRV 8 COSTS 3>> TRANStIISSIOH 88nltICE tin HILLS 0OOO JOOO f 127) f128) f 129) f130J 9>>1 li~ 12
~
120
~
9>>OTB 20>>1 l5 ~ 28 0
2'll 11>> I 15>>18 281 22>>2 16>>95 0
329 25 '
25 F 4 le ~ 76 18>>58 0
411 0
28 ~ 5 20 F 88
~
512 30.1 2l ~ 0'7
~
555 32 ~ 8 24 ~ 13
~
694 01'7 e 630 026 ~ 263 024 ~ 137 0 25 ~ 204 0 31 ~ 614 0 31 ~ 13'7
'0 55 ~ 320
'0 54 ~ 111 CAPACITI AEQUIREIIBHTS COST CAPACITY COSTS TUTAL TRANSHIQSICH SEnvlcE TOTAI. PAATIhl, AHQUIRFAEHTS rlXED COSTS vhAIAALHcosT5 TOTAL F000 f 131) 0000 0000 0000
)13e) t 134) f 140) lln f 131) 0/KH/IR f 132 J
~ooo f 133)
Icolo es 12>>46 012rS95
. 012e595 060>> 228 56>> 096 11'fr 125
~ 14 ~ 431 017>> 134 021 ~ 595 056 '08 064>>294 44 ~ 990
~ 53r 45l 105>> 099 II'r 744 076 F 088 57>>480 133 F 560 l>>054 ~ 6 I ~ 098 ~ 6 1 ~ 142 ~ 6 13>>II9 15 ~ 60 18>> 90 014,434 01Te 134 021 ~ 595 I, le6.6 21 ~ 92 0 26>>016 I e230>>7 22 ~ 87 0 28>>150 1>>274 F 7 22>>88 0 29e 161 1 ~ 318>>7 23>>00 30e 334 l ~ 362 ~ 8 23 ~ 24 0
31 ~ 675 0102>> 318 58 ~ 348 dllo>>658 64 ~ 451 0119>>828 6'2>>642 0130>> 160 12>> 442 0130 '89 11 ~ 5 40 160r 691 175 ~ 115 102 ~ 4'lo 202 ~ 603
'20 t ~ 130 0 26,ol6 0 2e,iso 0 29.167 0 3o.334 0 31.615
NORTll Chnol IHA ttotfICIPAL Polfnn ACENCY ttUNDER 3 PRO fECTED OPRRATIHC RESULTS UNDER PROPOSFD ARRANCRtlrltT lfITH C P
C L CASE A scnRDUl.E 2 PARTIAL NEftUIREtlEHTs PUNCHASEs FRotl cPcL DESCRIPT IOH 1991 1992 1994 1995 1996 1991 1998 lr SUPPl.nllENTAL POHER SUPPLENENTAL DEtlhnll COST chphcITr cosrs lllf f 1 1 1 )
0/tfn/YR f 112 )
eooo f 113) de3'.o lie. 41 0 Bor911 653o 6 656 ~ 2 139'0 140+72 0 9lr031 0 92r 340 621 ~ 8 156 ~ 34 0 97r214 619 ~ 5 155o03
~ 9dr 041 635 ~ 9 151 ~ '26
~ 96,184 65l 8
170.61 dlllr201 668 '
198 71 0132r03$
sUPPLEtlENTAl ENEROY COST FNEROY coBTs TOThl SUPPLENRNTAL COSTS
'2r PROJECT RESERVE SERVICE OHN HILLS
~000 0000 flli) f115) f 116) f 117) 1 '35r7 1 ~ 019 '
32.89 34.o3 0 ior Bio 0 3ir685 7ldr 5 36 ~ 42 0 26r091 513r2 299r7 31 ~ 01 40 ~ 57
~
1 et 994 0 12r 161 443 ~ 6 44.84 0
19'90 012lt551
~ 0125t 122 011St 437 0116t207 dloet 202 0116 ~ 014 642 ~ 4 49r 91 0 32r063 0143r263 559+7 5'9
~ 3l.ool 0163re36 NESERVR CAPACITY COST chpAcITY cosT8 tfH f118) 0/RH/IR fll9) oooo f 12o )
161 oe 14'6 b 24'06 158r2 21'l 202r9 173r29 184r45 208+86 21t 066 0 39t 491.
0 4'2t 367
'266 ~ 4 222'0 0 59r375 228o2 191o9 224o93 251'6 0 51 ~ 338 0 49t110 217 '
285 F 85
~ 62o131 nESEnvn RNEncr COST RESERVE ENERCY COSTS cnn illLLS 0000 f 121)
'f 122) f 123) 1 ~ 469r1 32 ~ 89 0 48t338 1 ~ 368ri 34.o3
~ idr563 lr16lr6 I ~ 629 '
36'2 3'tool 0 64 F 161
~ dor294 1 ~ 918o1 40o57 0 7'lr 842 1 ~ 688 ~ 2 44.84 0 'le 701 1 ~ 564 '
49'l 0 78'67 1 ~ 643o1 55 ~ 39 0 9lr014 DEFICIENCY ENRnor COST DEFICIENCY Elfnnor COSTS CHH illLLS 0000 f 124) f125) fl2d) 22oB 49r58
~
1 ~ 132 69 '
52004 0
3r 801 53 ~ 1 56+26 0
3r020 44oo 13' dorS7 6'lo44 0
2r618 0
913 34 ~ 3 13oSB 0
2r 531 88 ad 80 ~ 53 0
'le 132 l2 r9 87+62 0
6r 389 Sl'INHINC RESERVES COST SPINHINC NRSRRVRS COSTS HH llILLS 0000 f127) f 128) f129) 34.4 25o82 0
172 37 ~ 9 28r 63
~
950 39o 8 31 ~ 02 0
1 ~ 110 i'd 35o55 0
1 ~ 351 45oe 39'0 0
1 ~ 599 47r I 45 ~ 61 0
1 ~ Sel
~ 48
~
49 'l 50r27 5'2 0
2 ~ 132 0
2o 4 I 8
'TOTAL RESERVE COSTS 3o TRAHStlISSIOlf SERVICE 0000 f130)
~ 74 ~ 84d
~ 18o 185 0107r782 dlodr 698 0139r J30 0131 ~ 451
~131toio 0ldl ~ 951 CAPACITY NRQUIRtnfRttTS COST CAPACI?I COSTS Nt
. f131)
~Itfnlrn f 132) 0000 f 133) 1 ~ 408 ~ 8 23o51 0 33r078 I~ 450o 8 23o79 34, 5l 1 1 ~ 494 ~ 8 2ir03 0 3$ r 922 1 r538 ~ 9 24o 31
- 31r500 it582o 9 24 ~ 81
~ 38r 951 1 F 82' 24 hei 0 40 F 406 1 ~6:tl ~ 0 25'5 il~ 862 lr115 ~ 0 25r26 0 43r 315 TOTAI TNAlfellISSIOlf SERVICE ToThl, PARTIAL RRftolnnntot TS FIXED COSTS VARIADLE COST.'l TOTAL
~000 0000 00OO 0000 f 13'l) f 138,)
f 139) f 140) 013e,595 90 ~ neo 229r 414 0152 ~ 613 85 ~ ft05 23fl~ 418 0187r753 94 ~ 388 2f:2rlii 0111 ~ 081 83 ~ 122 2nor 403
~ 194 ~ 313 0187r 928 92r 5l 8 loot 003 Redo NO9 281, nel 0202 'l73 119r 393 0238r 281 130r 820 322 F 166 369rlol 0 33to'l8 0 34 ~ 511
~ 35r 922 0 37t 500
~ 38t9$ 1 0 ioo 406 0 ilted2
~ 43 ~ 315
NORTH ChROLINA IIUHICIPAL I'ONER ACBNCX HUHDRR 3 PROJECTRD OPRRhTINC RESULTS UNDER PROPOSED ARRAHCEtlENT HITII C P 0 t.
CASE h SCIIRDULS 2 - PANTIAL NRQUIRBtIENT8 PURCIIASES FROII CPCL DESCRIPTIOH 1999 2000 20 0l 2002 2003 SUPPt BIIBNTAL PURER SUPPLEIIENTAL DPIIAND COST CAPACITT COSTS tlH fll1 )
o/KH/TR f 112) 0000 f 113}
68 8o't 202 ~ 60 0139r 533 70 8 ~ 6 7'29 ~ 2 22't o 57 263 o41 0 let ~ 259 0192e 134 154eO 270o 02 020'12 119 o1 30'6
~236r992 8UPPt BREHTAL BHENCT COST EHERCT COSTS CNH f 1 14) llILLS f 115 )
0000 file) 483o3 191 ~ 9 6lo75 68'0 0 29r 856 0 54 ~ 651 t37e1
't6e 16 0 56r 184 640 ~ 2 Blo47 0 54r078 92't ~ 8 9'0
~ Ber 751 2 ~
TOTAt SUPPt EIIBHTAL COSTS 0000 f117) 0169e390 0215e 915 0248r319 0257re89 0323r143 PROJECT RFAERVS SERV'ICS RESERVE CAPACITT COST CAPACITT COSTS
. ftIB) 0/KH/XR f 119 )
oooo f lzo) 251 ez 307 F 22 0 't1r 179 188 o0 336 F 62 0 63r'291 218oB 380o45
~ 83r22t 248 '
398o 61 98r910 zlzoB 436e66 0 92r935 RESERVE EHBRCT COST RPABRVS EHRRCT COSTS ClfH f 121 )
IIILLS
. f 122) 0000 f 123 }
}~ 890eO ele75 OlIee 709 1 ~ 414 o2 68o50
~ l00 ~ 985 I ~ 733rD 76 ~ 16 0131 ~ 994 1 '78oO o
1 ~ 723ez Bl ~ 41 93e50
~158r 638 Ol e'er 120 DEFICIIrHCT S4SRC I COST DBFIcIBHcr BHRNCT cOSTS CHH f 124)
IIItt8 f 125) 0000
. f 126) 53e2 95'9 0
5r109 140e5 106 o 1 104'5 114'4 ling 690
~ 12rli't 63 ~ 4 125o06
~
7r 921 134 ~ 4 l36o 49 0 18r We SPIHHIHC RPABRVRS COST SPINIIIIIC RESBNVlB COSTS TOTAL RESPRVR COSTS TRA(ISIIISSIOH SPRV ICPi tftf f 121) tltLMI f 128) 0000.
f 129) 0000 f 130 )
50o8 61 o03 0
2r 118 0201 ~ 709 52eO 67'2 0
3r 051 53o1
'f2e 89 0
3r 390 54oO
'l9e 15 0
3r 143 54 ~ 9 85o95 4 ~ 132
~ 182 0?2 0230 758 0269 220 0276 524 CAPACITX NEQUINRHPHTS COST CAPACITT COSTS IIII 131 }
0/KH/TN 132}
0000 133) 1 ~ 759 ~ 0 25el2 0 44r1l5 I~ 803o 0 25o 51
~ ler096 1 ~ 841 ~ 1
'25e 72 0 41r 513 I~ 891 ~ 1 25 ~ 86 0 48r910 lr935 ~ I 26e01 0 50e431 TOTht TRAlfSIIISSIOtf SERVICE 0000 f 131) 0 44 ~ 115 0 46r 096 0 4'tr513 0 48r 910
~ 50r451 TOTht PARTIAL REQUIREIIEHTS FIXED COSTS
'VARIARtR COSTS'OTAf, 0000 f 138) 0000 f199}
oooo flin)
~261 ~ 421 154r 392 415 ~ Bl 3 444 '34 526r 391 HI5r RZO 650r'lift 0270 ~ ele 0322 ~ 875 0351 ~ 432 0380 ~ 318 173,388.
203,71e 224,388 270.340
NORTH CARol INA tlUHICIPAL POHER AOEHCI HftHBER 3 PROIECTHD OPERATIlfO RESULTS UlfDER PROPOSED hlfRAHOEtlEHT lfITH C P d L CASE h SCflPDULH 3 - TOTAI AOEHCI COSTS DESCRIPTIOH 1983 1984 1985 1986 1981 1988 1989 ADDITIONALAOftlCT COSTS AOEHCI h 6 0 lofPEHSES DEBT SERIVCE HORffIHO CAPITAL SUBTOTAI COSTS ASSOCIATED NITfl ARRAHOEtlEHTS NITfl VEPCO TOTAL ADDITIONALCOSTS 0000 f151) e 2 012 e
2 259 e
'2 462 8
2 683 8
2 925 d
3 188 e
3 475 0
3 788 eooo f 152)
. Ir331 2r fldo 3r 081 3e289 ir015 4.58O 5 ~ 111 6e 244 eooo f153) 8 3,4o9 8
5,119
~
5.543
~
5.912 0
6 940
~
7 168 8
8 652 8
10 032 6000 f 154) 6e 834 7r 315
'lr821 Br 119 Br559 8 ~ 924 9r260 9e 656 OooO f155) e Io,243
~ 12,434 e 13,364 e ii.o91
~ 15 499 e
16 ~ 692 e
17 912 e
19 688 FT ffED COSTS VARIABLE COSTS TOTAL COSTS F000 fidlJ 8 59r405 F 000 fl62) 65,20fl 8000 f 163) 8124 ~ 614 TOTAf, COSTS UNDER AOENCT ARRANOENEHT 8 65r 364 69e 49't 8 98r383 Bor 481 8101r 444 87 ~ 575 8120 '49 93r 847
~147r926 103i316 I
8214 544 1224 674 109r 124 127 ~ 410
~ 134 ~ Bd2
~I'fBr fl70 8195 r O19 eg lie 796 1251 ~ 243 8324,268 8 352 ~ 144 DENAND AHD ElfEROI RPQUillHNEHTS f OENERATIOH LEVEl.
CPCL CITIESl PEhtf DEffhHDS ElfEROI REQUIRENENTS VEPCO CITIESl PEAK DEflAHDS FHPROI RERUIRfofEHTS TOTAL AOENCIl PEAR DEtfhlfDS EHEROI REQUIREtlEHTS llH OHIl Illf Olflf lllf Olfff f 1'l3) fI'tiJ f 1'tSJ f 11d) 355o9 3'll ~ 5 1 ~.'f02 ~ 5
. I ~ 117 ~ 4 1.010.5 1.054.8 4r 154 ed 4 ~ 961 ~ 8 38'lo2
- 1. 852.2 1 ~ 098o 6 51169 ~ 0 f171 J 654.7 683.O 111.4 f 1'l2) 3r052o2 3e lff4~ 5 3 ~ 316o7
'l39o 'I 3e 449 ~ 0 402 ~ 9 ie921 ~ I 1 ~ 142 ~ 6 5 ~ 376 ~ I 768 '
3 ~ 581o3 418 ~ 6 2r002oo 1e 186.8 5 ~ 583o3
'f96 ~ 4 3r 719 ~ 6 434 '
2eo'16 ~ 9 1 r 23Oo'I 5 't90 ~ 5 824o7 3e845
~ 8 450 '
2 ~ 151 ~ 8 lr27io7 5 '97 ad 853 1
3o 9'fB ~ 1 46' 2 ~ '226 ~ 1 1 '18o'l 6 ~ 204oB O Iol 0
~
~
rI IIORTII CAROLIHA tlU!ftCIPAL l'OHFR AOPHCT IIUIIBFR 3 PROJRCTED OPRRATIHO RFSULTII UHDFR PROPOSED ARRAHOFIIEHT HITH C P 6 L ChfIE A SCIIEDULE 3 - Torht. AOEHCT cosrs DRSCRIPTIOH 1983 1984 1985 1986 1987 1988 1989 ALLOCATED BULX POHRR SUPPLT COSTS CPCL CITIEst FIXED COSTS VARIABLF'OSTS TOTAL COSTS VEPCO CITIESt FIXED COSTS VARIABLE COSTS TOThf COSTS TOTAL AOEIfC'Tt FIXED COSTS VARIABLE COSTS TOTht, COSTS 0000 0000 0000 0000 0000 0000 0000 0000
~000
( l77)
~ 34e 058 I 118) 4 le 860
)179) 0 75e918
) 180)
~ 25e 34'f
) 181) 23e 349
)182) d 48e696 (183)
~ 59e 405 (184) 65 ~ 209
) 185)
~ 124 ~ 814
~
31e 597 4 4 ~.603
~ 58e 641 Sl ~ 645 0 64 ~ 301 0 72e'f43
~ 56el83 60'96 0 S9 ~ 95l 66e259 dl32e820 70 '58 0139e 095 Sly 725 0 27 ~ 761 24e 89S 0
39 ~ 742 28e 84'2 e 43,144 31'92
~
4Se 205 33e 651 0 57e975 37'5'f 0 Sl. ~ 724 39 ~ 366 0
85e 579 45e'five 0 52e662 0 68,584
~ 74,536
~ 81.856 0 95.O32 el2l,O91 0 65,364 0 98,383 dlO7,444 69 491 80 48'f 81 5 IS
~)20e 949 93e 841 dl 41e 926 103e 316 0214 ~ 544 109e 724
~ 134 ff62 dl18,870 dl95 019 0214 196 0251 ~ 243 0324 ~ 268 013l ~ 324 I
0224 e 674 127 ~ 470 0352 0 82,2oo ello,286 0120,483 ei32,940 0156.2io. 02o3.178 e22o.820 DFHAHD AHD EHEROT DElIVPRIFei CPCL CITIEst BILLIHO DEHAHDS RlftIROT DFtIVERIES VrPCO CITIES t BILLIHO DEIIAHDS EHEROT DELIVERIES tiff-tlo OMH Nf-tlo OHIf f 1$ 8) 6e 320e'9
) 181) 2e 951e5
) 188) 3e 372 ~ I
( 189) 1 ~ 583e7 6e 5'93e8 Se 079 e ~
3e520 ~ 2 1'53 F 4 3e668
~ 3 1 ~ 123 1
3e 816 ~ 4 ie 792 e7 6e 866e8
'fe 13'9 ~ 7
.3e207
~ 3 3e 335e2
'f~ 412 ~ 6 3, 463e l 3e 964 ~ 5 le862ei 1e 885e 6 Se59l eo 4 ~ 112 ~ 6 1 '32eo 1e 958 ~ 5 3e'f 18 ~ 9 ie260 e1
. 2 ~ 001 ~ 'I
.Be 231 ~ 4 3 F 846 '
4 ~ 408eB
. 2'71 ~ 4 AVERhoR cosrs or At.t. REQUIRalEHTS BULK POHPR SUPPf T lJ'!L CITIRSt rtxED cosrs VARIABIE COSTS COSTS ASSOCIATED ltITR ARRAHOEtlFHTS IIITtl VFPCOI FIXED Cosrs VARIABLE COSTS VFP Co C IT I ES I f'IXED COSTS vhRthnt,R cosrs AVERAOE ADDtTIOHAt, COSTS FOR VPPCO CITIFS 0/IIH/HO tltILS 0/XH/tlo IlIILS 0/IIH/Ho IlII,LS (191) 5 ~ 39 t 192) 1 ~ ~ 18
) 193) 2e 13 t 194)
~ 56
) 195) 1e52
) 196) iie14 t197) 5'3 5 ~ 'to 14 ~ 48 2el9
~ 5'f
'f ~ $ 9 15 ~ 06 5 ~ 16 Be 54 16 ~ lo 2e29
~ 64 lo ~ 03 16 ~ 'I4 5'2 9 ~ Ol i6.85 9eOl 17e38 1 1 ~ 3o 17+51 12e l6 18 eo'f F 45 5I 2'0 2'5
~ 6'f
~ 69 11 010 18e 45 2e39
~ I3 lle lo 19 ~ 18 5e 69 16 ~ 69 18+92 2 ~ 49
~ 15 l9 ~ 18 19e67 5.86 16%90 21 ~ 24 2e51
~ 84 19ei'I 22 ~ OO 6+00 00 tF O V
NORTH CAROLINA lfUHIcIPAL PoMPn AOHNCT NUtlBPR 3 PROJECTED OPERATINO lfESULTS UHDPR JnoPoSED hnnhnorffNNT lflTH c P 6 L CASE h SCJJEDULH 3 - TOTAL AOHHCT COSTS DESCRIPTIolf 1990 1991 1992 1993 1994 1995 1996
~
1997 hbDITIOHAL AOENCT COSTS AOEHCT h 8 O EXPENSES DEBT SERIVCE-NORRIlfo CAPITAL SUBTOTAL COSTS ASSOCIATED ffITH ARRANOEJftofTS NITJJ VHPCO TOTAL ADDITIONALCOSTS eooo eooo 8000 eooo Bono f152) dr 833 vr 424 0
f 153) 8 lor962
~ 11 ~ 924 f IS4) 1O,18V 1OrRO1 0 0 f 155) e 21 ~ 149
~ 22r 131 8.434 10'72 lor'l83 le 'ldl lo ~ 162 10 ~ 159 e 13.339 8 15,519
~ ld.dll 8 17,133
- e. 17,686 e l8,306 Ilr434 12 ~lll 12r745 1k ~ 335 13rdBl li~ 410 8 24 ~ 773 t 27 830 8 29 358 8 30 ~ 468
~
31 ~ 587 e
32 116 f 151) e 4 ~ 129 e
ir500 8
4 ~ 905 e
5r 347
~
5 ~ 828
~
6 ~ 352 e
6 ~ 924 e
7rsi'l TOTAL coSTS UNDEn AOENCT AnnhNOEHEHT
~
~
FIXED COSTS VAlfIABIECOSTS TOTht, COSTS i000 F000 8000 fldlf 8288r603 8280 ~ 008 e30! ~ 866 f182) 152r 186 ldor522..
201 '92
~0 ~ ~&
0 W W>>
~
~
f 183)
~il8,v88 8480.528 8503.258 8320 ~ 333 8393r624 8450r099 e540 ~ 563 8595r 335 219r 401 234r 882.
281r 466 291 ~ 409 336 ~ 546 8539r 734 8828r 308 evllr565 8837 ~ 973 e 931 r 881 DElfhHD AHD ENJSJOT REQUIRPJJHHTS 8 OEHEnhTIoN t EVEt CPCL CITIESf PEAR DEJJANDS ENI'.ROT REQUIREffANTS VEPCO CITIF>f PEAR DEtfhnbn ENPROT REQUIREHHNTS TOTAL AOENCTJ PEAR DEtfhNDS Elfl',ROT RPQUIREHENTS lflf OffH lflf ONH f171)
Bdiri 909r8 938 ~ I 9$8rs f l72) ir1lo ~ ~
4 ~ 242rv 4 ~ 374 ~ 9 4g 50102 f l13) 481 r 3 491ro 5l2rv 528r 4 flvi) 2r 301 r 6 2r 378r 5 2r 45l ~ 3 2r 52dr 2 flvS) 1,.382.8 lr4O8.8 1.450.8 1,494.8 flvd) 8 ~ 412 ~ 0 8 819 1
6 82d 3 vr 033 5 994 ~ 8 ir839rs 544ri 2rdol ~ 1 1 ~ 538r 9 7 ~ 240rd I+023I2 4r171rd 559rv 2 ~dvdro l,s82.9
'7 ~ 443rd I~oslrs 4'04ro 575 ~ 4
.2r750 ~ 9 1 ~ 626r 9 vr654,9 1 ~ 079+8 5'36 '
591 ~ 1 2r825 ad 1 ~ 87l oo 1 ~ 882 ~ l
(.,0 NORTH CAROLINA KUNICIPhl, POXHR AOFNCT NUKBHR 3 PROJECTED OPERATINO RESULTS UlfDHR PROPOSED ARRANORtlPNT ffITN C P C l.
CASP. A SCKPDUI,F 3 - TOTAL AOFNCT COSTS DESCRIPTION 1990 1991 1992 1994 199$
1996 1997 ALLOCATFD BULX POXER SIJPPLY COSTS CPCL CITIRSl FIXED COSTS VARIABLE COSTS 0000 0000
( I't7 )
01 6$ ~ 849 0 114 e 092 01 81r 198
) 118) 91r559 11$ e709 129e07!
0199r 2't5 lior59S 024'20 150e375 0282 ~ 315 167e521 e3io,ioo 190 '32 0375 '19 215 '85 TOTAl COSTS VFPCO CITIFst FIXED COSTS VARIABLE COSTS TOTAI COSTS TOTAL AOPtfCTt FltfED COSTS VARIABLE COSTS 0000 F 000 0000 0000 0000 0000
( 180) 0100, 754 t 181) 54 ~ 627 0105 ~ 914 64r 813 0114 '68
'f2'21 0121 ~ 0$ 8 78e803 0147e403 84 ~ 30't
) 182) 0155r 981 0170 ~ 72'I 0186e 389 el99r Bdl 0231 ~'llI 0167 784.
93e 946 0261 ~ 729 0200e 164 106 818 0219 916 l20 ~ 96l
~307e04l 0340 ~ 811
( 189) t266e 609 (184) 152 186 028O.OO6 180e 522 030) F 866 20le392 0320 ~ 333 0393e 624 219e 401 234 ~ 682 0450 '99 2dl ~ 466 0540 '63 297 ~ 409 0595 ~ 33$
336 ~ $ 46
) 119) 0263r408 0289r 801 0316e869 0339r 873 0396r 595 0449r 836 0530r 931 0591 ~ Ooi TOTAL COSTS 0OOO (185) 0418,788 046O,528 t503 258 0539 134 t628 306 t711 5650837
~ 9'73 0931 ~ 881 DFtlhND AND RNRROT DRlIVERIES CPCL CITIEst BILLINO DEflhNDS HXFROT DFf IVRRIES VEPCO CITIESt BIl.l,INO DFtlhNDS ENEROT DELIVERIES Ktf-tlo OXfl tiff-flo Otffl
) 186)
Be 504 ~ 4
) 187) 9r 914 e7
) 188) i.558.9
< 189)
- 2. iii.o Se't77e 3 iei02e1 4'05eo 2i 210e't 9e0$ 0 ~ 2 4'30ed i.853.1 2r280ri 9e 929e2 4 ~ 358 ~ 5 5eool e2 2 ~ 350 ~ 0 9r 59de I 4'86 F 4 5el49 ~ 3 2r419r7 9r869ro 4 ~ 614 ~ 9 5e297 F 4 2r489e4 10 ~ 1 42 ~ 0 4'42e2 5'45 F 5 2e559ro loe414
~ 9 4 ~ 870 '
5e 593 ~ 6 2'28 ~ 7 AVERAOE COSTS Or hLI, REQUIREKPNTS fNLX POXRR SUPPLT CPCL CITIHSt FIXED COSTS VARIABLE COSTS COSTS ASSOCIATED 'NITfl ARRANOt2fpffTS lfITK VRPCO!
FIXED COSTS
'VARIABIR COSTS VPPCO CITIEst FIXED COSTS VARIABI,E COSTS
~/XX/KO tl ILL'.f 0/XN/Ko tillLS
~/XN/Ko fill,ltl
) 199) 2edl
( 194 )
~ 97
) 195) 22 ~ 11
) 196) 25e51 2'8 I ~ II 22r51 29 ~ 32
) l91) 19 ~ 50 19 83
) 192) 24 ~ 5 ~
28 ~ 20 20 ~ 'I5 30'1 2 ~ 15 1 e21 23e50 31r71 21e 37 32r26 2e83 1 r21 24.2l 33e53 25 ~ 66 33 ~ 52 2'7 I ~ 32 28'3 34 ~ Si 28 ~ 6l 36r 30 3 ~ 01 I r 49 31 F 67 37r t4 33 ~ 56 40 ~ lS 3 ~ 19 1 ~ 59 36 ~ 16 41 ~ 't7 36r 05 44 ~2t 3r 27 I ~ 75 39'2
~ 6 ~ 02 AVPRAOE ADDITIONALCOSTS t'OR VFPCO CITIES tllLLS
) 191 )
6 ~ 30 6 ~ 59 6 ~ Sh 7007 1 ~ 36 7 ~ 65 Sr03 8'2
HORTII CAROI IHA tIUHICIPhl PolfFR AOBIICI HUtlMR 3 PRIMBCTRD OPBRATIHO RPSULTS UHDER PROPOSFD ARRAIIOFHFNT lfITII C P 6 l CASE h BC)IBDULR 3 TOTAL AORHCI COSTS DBSCRIPTIOH 1998 1999 2000 2ool 2002 2003 ADDITIONA'LAOBNC'I COSTS AOFIICT A ! 0 PXPEHSES DEBT SBRIVCB KORXIHO CAPITAL SUBTOTAL COSTS ASSOCIATED KITfl ARRA!foBIlBHTS HITII VEPCO TOThl ADDITIolfhLCOSTS 0000 conn 1000 4000 8000 f152) lor754
. 10 ~ 15l f 153) d Ibr981 d
19r 118 f154) 14'11 15r483 f 155 J
~
33r 892 d
35r 201 lor757 lor 741 10 ~ 741 lor7il 20r531 d
21r395 d
~
22r354 d
23r399 16r043 16r 627 11 ~ 202 17r761 d
36 574 d
38'22 d
39 556
~
il~ 160 f 151 )
4 Br221 0
Br 967 0
9r 774 0
10 ~ 654 0
I 1 ~ 613 0
12r 658 TOTAL COSTS UHDER AOEHCI ARRANOEtIRNT FI XED COSTS VARIABLE COSTS TOThl, COSTS 4000 F 000 8000 f 161 )
4 653r 490 d
694 ~ 430
[162 j 3rl ~ II
~ 27
$ 12 f 163) dlr034 ~ 900
~ 1 ~ 122roil d
'l22r1'l2 48'02 4
194rBOB 545 ~ 590 e
842. 306 616 '34 0
891 '15 693 '23 Bl~ '2lo ~ 674
~I ~ 340 ~ 398 dl 458 ~ 840 d I ~ 584 ~ 438 DPtlhllD AHD EHBROI REQUIREIIBNTS R 0FHF RATION I RP BL CP4 I CITIPSl PBAII DMhHDS EHPROI RRQUIREIIRHTS iEPCO CITlref PRAII DRIIAHDS EHEROI RBQUIRERBHTS TOTAL AOBNCYl PBAII DEHANDS EHEROI REQUIRFHBNTS tiff Olftl f 111) 1 ~ 108 ~ '2 I ~ 136e5 l ~ l64 ~ 9 1 ~ 193 ~ 2 f172) 5r 168+6 5 ~ 300r 9
'5 ~ 433r2 5r 565 ~ 4 f 113 J 606 r8 622 e5 638 ~ '2 653 e8 f 114 J 2r 900e7 2r 9tS r6 3r 050 ~ ~
3r 125 ~ 3 f115)
I;715.O 1.159.O 1.803.O.
1,841.1 fl76J 8 069 ~ 3 8 276 4
8 483,6 8 690,8 lr221.6 Sr691 ~ 't 669r5 3r 200 ~ '2 1 r 891 ~I Br 897 ~ 9 Ir249e9 5 ~ 830ro 685 '
3r2'le 1 1 ~ 935 ~ 1 9ri05 F 1 ta 00 0' I
NORTH CAROLINA HUlflCIPAl PONBR AOHHCI tletlBER 3 PROJECTED OPBHATIHO RBQULTII UHDFR PROPOSED ARRhHOBHBNT NITH C P
C L CASH h SCHHDUI B 3 TOTAL AOIRICI COSTS DBSCRIPTIOH 1998 1999 2000 2001 2002 2003 ALLOCATED BULK PONER SUPPII.COSTS CPCI CITIES5 FlXBD COSTS VARIABLE COSTS TOTAL COSTS VBPCO CITIBSt FIXED COSTS VARIABLE COSTS TOTAL COSTS TOTAL AOPNCIt FIXED COSTS VARIABLE COSTS TOTAL COSTS 0000 eooo 0000 0000 0000 0000 0000 0000 0OOO f I IT) 0 412r 631 f 178) 244 ~ 304 f 119) 0 656r 941 f 180) 0 240e 853 f 181 )
137r lod t 182) 0 371r 959 f 183) 0 653r 490 f Iei) 3e I,411 f 185) 01 ~ 034 e 900 0
43er 681 273r BT6
~
456r592 312 ~ 467 0
502 ~ 112.
0 532 ~ 983 349'8t 394 '92 0
564'07 443r934 0
712 557
~
769 059 0
852 100 0
921 ~ 715 01 008 041 0
255 ~ 748 153r '136 266rleo 175 '35 0
292 ~ 095 196r203 0
309 ~ 323 221. ~ 742
~
321rooe 249e 389 0
409r 484
~
4 41 ~ 615
~
488e 298 0
531 ~ 066
~
516 ~ 397
~
d94e 430 427r 612 0
't22 ~ '112 ie7,9o2 i 794.eoe 545'90
~
. 842r 306 616r 534
~
89lr 115 693r 323 0lr122 Oil 01 210 674 01 340 ~ 398 elr458 ~ 840 01 ~ 584 438 DBHAHD AIID EHBROI DEf IVERIES CPCI CITIFAt BIILIHO bFIIANDS ENEROY DELIVERIES VFPCO CITIES'I BllLINO DEtlhNbS FHBROI bELIVERIES HN-Xo ONH Hlf-No ONH f186) lor 681 ~ 8 f 181) ir998ro f IOII) 5e74l r7 f189) 2 ~ 698 ~ ~
1 or 960 ~ 8 Srl25r9 Sre89re 2r768ro llr233r7 Sr253r9 de037r 9 2r 831r 7 llr506 ~ 6 5'81 '
drledro 2,901r 3 11 ~ 179r6 5 ~509r7 ee334
~I 2r9'1'tro 12e052 rS 5'31 ~ 6 dr482 ~
'2 3r 046r 't AVBRAOP. COSTS OF All RBQUIREIIBNTS BULK PURER SUPPLZ CPCL CITIBSt FIXED COSTS VARIABLE COSTS COSTS ASSOCIATED IfITH AIIRANOBIIEHTS IIITH 'VFPCOI FIXBD COSTS Vh'RIABLE COSTS VFICO CITIBSt FIXED COSTS VARIABLE COSTS AVERAOE hbDITIOHhl COSTS FOR VFPCO CITIES 0/KN/llo tlILl8
~/KN/tlo tillLS f 193) f 194) f 195) f t'96) tfllfrS f 191) 0/KN/tlo f 191)
HILLS tl92)
- 38. 61 4e.ee 3r34 1 ~ 93 41 ~ 95 50 ~ flI Or 63
~Or02 53r43 3 ~ 40 2 ~ll 43r 42 55 ~ 54 8'2
~ 0 ~ 64 59 ~ 47 3r44 2r35 44roe 61 ~ 82 9r25 43.69 6 ~ r92 3 ~ 53 2 ~ 56 47r22 67 ~ 49 9r62 45'5 Tlat 65 3'9 2'3 48 ~ 83
'tie 48 10 F 00 id.eo TerTS 3 ~ 64 3 11 50 ~ 45 Ol.ed 10'8 Question 13 List and describe all requests for, or indications of interest in, interconnection and/or coordination and purchases or sales of coordinating power and energy from adjacent utilities listed in Item 9 since 1960 and state applicant's response thereto.
List and describe all requests for, or indications of interest in, supply of full or partial require-ments 'of bulk power for the same period and state applicant's response thereto.
~Res ense:
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.
Question 14 List (a) agreements to which applicant is a party (reproducing relevant paragraphs) and (b) State laws (supply citations only) which restrict or preclude coordination by, with, between, or among any electric utilities or systems identified in applicant's response" to Items 8 and 9.
List (a) agreements to which the applicant is a party (reproducing relevant paragraphs) and (b) State laws (supply citations only) which restrict or preclude substitution of service or establishment of service of'ull 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 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 writing, it should be described.
~Res onse.
Power Agency has no knowledge of any State laws and Power Agency is not a party to any agreements which restrict or preclude coordination 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 Coordination 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 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 written notice to VEPCO to terminate service under the.Agreement for Transmission Use and Other Electric Service, but it may terminate service at any delivery point upon five years C
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 SEPA 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.
0 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 energy and mills/kwh for both power and energy at purchaser's present load factor (a) at present
- load, (b) at 50 percent increase over present
- load, (c) at 100 percent increase over present
- load, and (d) at 200 percent increase over present load.
(All costs should be determined under present rate schedules.)
Where sales are made under contracts or rate schedules on file with a Federal agency and not included in the response to Item 9, identify each in the same form as in previous responses.
Where the contract has not been filed with a Federal
- agency, a
copy should be supplied.
~Res ense:
Not applicable.
Question 16 State whether applicant has prepared, caused to be
- prepared, or received engineering studies for generation and transmission expansion programs which include loads of each system in Item 9.
~Res ense:
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.
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.
~Res ense:
None.
74 Question 18 List applicant's offers or proposals to purchase, merge or consolidate with electric utilities, sub-sequent to January 1, 1960.
Res onse:
None.
~- 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 pea)c load, dependable capacity and the largest thermal generating unit of the system, prior to the date of consummation.
~Res ense:
None.
Question 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 en'ergy 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.
~Res ense:
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 only, electric power or energy, and to enter into contracts for any or all such purposes" (Section 159B-ll(15)).
Accordingly, Power Agency does not have, and does not comtemplate having, any rates of the type set forth in Question 20.
77-APPENDIX A LIST OF POWER AGENCY'S MEMBERS Town Town Town Town Town Town City Town Town Town City Town Town Town Town City Town City Town City City Town Town Town City Town Town Town City Town Town City Town City Town Town of of of of of of of of of of of of of of of of of of of of of of of of of of of of of of of of of of of of Apex Ayden Belhaven*
Benson Clayton Edenton*
Elizabeth City*
Enfield*
Farmville Fremont Greenville*
Hamilton*
Hertford*
Hobgood*
Hookerton Kinston LaGrange Laurinburg Louisburg Lumberton New Bern Pikevil le Red Springs Robersonville*
Rocky Mount Scotland Neck*
Selma Smithfield Southport Tarboro*
Wake Forest Washington*
Waynesville Wilson Windsor*
Winterville*
Members served by VEPCO (directly or indirectly) as of the date of this Application.
78 4.
Communications CPGL will be solely responsible hereafter for communications with NRC related to this application for Harris Units Nos. 1, 2,
3 and 4.
Accordingly, all communications to" CPGL or Power Agency pertaining to this application for Harris Units Nos.
1, 2,
3 and 4
should be sent to:
J. A. Jones Vice Chairman Carolina Power 6 Light Company Post Office Box 1551
- Raleigh, North Carolina 27602 and in addition, to:
t Charles D. Barham, Jr.
Vice President and Senior Counsel Carolina Power 6 Light Company Post Office Box 1551
- Raleigh, North Carolina 27602 CAROLINA POWER 6 LIGHT COMPANY BY: J.
A J'ne Vice Chair ma Sworn to and subscribed before me, this 3 day of~,
1981.
ggiullllgff Notary Public
- ~QTAR)
My Commission Expires:
.. 8-9' NORTH CAROLINA MUNICIPAL P SNEQ&
NUMBER 3 BY:
A stant Secretary-Treasurer Sworn to and subscribed before me, this 3(
day of
, 1981.
s Notary Public MY Commission Expires:
'b