ML15223A866
| ML15223A866 | |
| Person / Time | |
|---|---|
| Site: | Oconee, McGuire, 05000000 |
| Issue date: | 03/01/1983 |
| From: | Tucker H DUKE POWER CO. |
| To: | Harold Denton Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML15223A867 | List: |
| References | |
| NUDOCS 8303080084 | |
| Download: ML15223A866 (7) | |
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DUKE POWER COMPANY P.O. BOX 33189 CHARLOTTE, N.c. 28242 HAL B. TUCKER TELEPHONE VICE PRESIDEN (704) 373-4531 NUGLEAR PRODUGON March 1, 1983 Mr. Harold R. Denton, Director Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Washington, D. C. 20555 Attention: Document Control Desk.
Subject:
Oconee Nuclear Station McGuire Nuclear Station Docket Nos. 50-269, -270, -287; 50-369
Dear Sir:
Pursuant to Section 140.21 of 10 CFR Part 140, Duke Power submits the required information demonstrating that the company has and maintains financial protection for each licensed operating nuclear reactor as evidence of its guarantee of payment of deferred premiums. Attached are:
- 1).a statement of Duke Power Company as to available sources of funds to satisfy liability pursuant to 10 CFR 140.21; 2) the Duke Power Financial Forecast 1982-1984; 3) the 1981 Annual Report; and 4) the Annual Certified Financial Statements (which are included in the. Annual Report).
Very truly yours, Hal B. Tucker JCP/php Attachments 8303080084 830301 p00 PDR ADOCK 05000269 PDR
Statement of Duke Power Company As to Available Sources of Funds to Satisfy A Possible Liability Not Exceeding $40 Million Pursuant to the Provisions of 10 CFR 140.21 Pursuant to the requirements of Section 140.21 of the Nuclear Regulatory Commission regulations in 10 CFR Part 140, Duke Power Company (the Company) herein submits the 1981 Annual Report to Stockholders, annual certified financial statements, and its 1982 Financial Forecast as evidence of financial ability of guarantee of payment of deferred premiums in the amount of $10 million for each reactor it is licensed to operate. I certify that the Financial Forecasts, which include information relating to cash flow, were prepared in conformity with generally accepted accounting practices applied on a basis consistent with the accompanying financial statements.
As of December 31, 1981, the Company had bank lines of credit of $305 million with 77 commercial banks. During 1981, the Company's short-term debt averaged approximately $39 million, with a maximum amount of about $250 million, both of which were significantly below the available lines of credit. Further, the Company also has the option to sell substantial amounts of commercial paper as an alternative to using its bank liTesof credit, another source of credit.
Either of these sources would, in my opinion, be available as a source of funds to satisfy the assessment of retrospective premiums not exceeding $40 million.
It is the Company's opinion that it can meet its guarantee of payments of deferred premiums currently amounting to $40 million as required by Nuclear Regulatory Commission regulations, particularly in view of the relative insignificance of this amount to its total available cash and credit.
DUKE POWER COMPANY (COMPANY) by N. P. Morrow Controller Subscribed and sworn to before me this g A/ day of February, 1983.
Notary Public My commission expires:
00f /
DUKE POWER COMPANY Financial Forecast 1982-1984 DUKE POWER Projections listed herein are subject to change.
Inquiries concerning this forecast should be directed to:
March 1982 Richard J. Osborne -
Treasurer Telephone (704) 373-5159 Charles A. Markel -
Assistant Treasurer Telephone (704) 373-8695
Financial Data (Note 1)
Projected (Dollars in Millions)
Actual 1982-1984 1981 1982 1983 1984 Totals Capital Requirements 1 Construction Costs..........................
$ 675
$ 707
$ 715
$ 598
$2,020 2
Nuclear Fuel Costs..........................
129 156 148 210 514 3
Equity Component of ADC...................
(159)
(143)
(153)
(90)
(386) 4 Net Change in Working Capital................
93 (1) 27 (30)
(4) 5 Maturities, Sinking Funds and Other Requirements (Note 2)................
94 200 67 57 324 6
Total Capital Requirements...............
$ 832
$ 919
$ 804
$ 745
$2,468 7
Provided by Internal Cash.................
94%
56%
63%
87%
68%
Sources of Capital Internal Cash 8
Depreciation and Amortization..............
$ 225
$ 292
$ 357
$ 471
$1,120 9
Other (Note 3)............................
554 221 149 178 548 10 Total Internal Cash......................
779 513 506 649 1,668 11 Outside Financing Required................
53 406 298 96 800 12 Total Sources of Capital.................
$ 832
$ 919
$ 804
$ 745
$2,468 Tentative Financing Program 131 Long-Term Debt (Note 2)...................
42
$ 339
$ 298 38
$ 676 14 Preferred Stock...........................
40 30 70 15 Common Stock (Note 4)...................
36 127 56 58 241 16 Net Change in Short-Term Debt...........
(25)
(100)
(86)
(187) 17 Total...................................
53
$ 406
$ 298 96
$ 800 Capital Structure (Note 4) 18 Capitalization............................
$5,400
$5,900
$6,400
$6,600 Ratios:
19 Long-Term Debt...........................
48%
47%
47%
45%
20 Preferred Stock...........................
13 12 12 11 21 Common Equity...........................
39 41 41 44 Other Significant Items 22 Deferred Income Taxes, Net.................
54 76 67 60
$ 203 Investment Tax Credit 23 Deferment 56
$ 108 83 48
$ 239 24 Amortization
- 5)
(8)
(10)
(14)
(32) 25 Net 51
$ 100 73 34
$ 207 26 Allowance for All Funds Used During Construction (ADC).................
$ 222
$ 200
$ 205
$ 121
$ 526 27 Effective Composite Income Tax Rate (Note 5)..................
57%
50%
50%
51%
50%
Sales and Load Data Projected Compound Actual Growth Rate 1981 1982 1983 1984 1981-84 Kilowatt-Hour Sales (Billions of KWH) 28 Residential.................................
13.9 13.9 14.3 13.8 (0.2)%
29 General Service.............................
9.7 10.0 10.3 11.5 5.8 30 Industrial...................................
20.7 21.2 22.2 23.7 4.6 31 Wholesale & Other....
8.3 8.9 9.5 9.4 4.2 32 Total Energy Sales.......................
52.6 54.0 56.3 58.4 3.5 33 Annual Growth Rate.......................
2.4%
2.7%
4.3%
3.7%
Kilowatt-Hour Generation 34 Total Generation............................
57.7 58.8 62.0 63.9 Source:
35 Coal.....................................
73%
67%
57%
45%
36 Nuclear..................................
25 30 40 53 37 Hydro & Other............................
2 3
3 2
Electric Peak Load (MW) 38 Summer (April-Sept.)
10,602 11,041 11,430 11,476 39 Winter (Oct.-March) 11,145 11,232 11,415 11,802 Total Capacity (Includes Firm Purchases) 40 Summer (April-Sept.)
12,141 13,377 13,377 14,557 41 Winter (Oct.-March) 13,377 13,377 14,557 15,702 Total Reserve Resources (Includes Interruptible Load) 42 Summer (April-Sept.).......................
1,571 2,445 2,153 3,385 43 Winter (Oct.-March)........................
2,263 2,225 3,281 4,098 Major Generating Units Currently Under Construction Estimated Construction Cost Date of Net KW Energy Planned Total Unit Capability Source Operation Per KW (Millions)
McGuire No. 2 (Note 6) 1,180,000 Nuclear 1983
$ 828*
$1,955*
Catawba No. 1 1,145,000 1984 Caab N.2(Note 7) 14500 Nuclear 195$1
,279*
$ 732*
Catawba No. 2 1,145,000 1985 Cherokee No. 1 1,280,000 Cherokee No. 2 1,280,000 Bad Creek (Note 9) 1,000,000 Hydro-
$ 861
$ 861 Electric
- Excludes initial fuel cores.
Notes 1 In 1981, the Company sold a 75 percent interest in Unit 1 and a 37.5 percent interest in the support facilities of the Catawba Nuclear Station to groups of its Rural Electric Cooperative customers. In 1978, 75 percent of Unit 2 and a 37.5 percent interest in the support facilities of that station were sold to an agency representing some of -the Company's North Carolina municipal customers.
The sales essentially provide the purchasers portions of the capability and generation of Catawba and accordingly affect the Company's projected "Kilowatt-hour Sales" and "Kilowatt-hour Generation" beginning in 1984 when Unit 1 commences commercial operation.
In addition, the Company has an agreement to sell the remaining 25 percent interest in Unit 2 to an agency represent ing some of its South Carolina municipal customers. No effects of that sale are included in the forecast. The sale is subject to the purchasers' ability to arrange adequate financing. If consummated by mid-1982, the sale would provide the Company approximately $250 million at that time and would reduce projected construction and nuclear fuel costs by $51 million in 1982, $59 million in 1983 and $40 million in 1984.
2 "Maturities, Sinking Funds and Other Requirements" includes maturities and sinking funds related to long-term debt and preferred stock and the principal portions of payments on capitalized leases. Maturities and "Long-Term Debt" financings include $39 million in 1982, $48 million in 1983 and $38 million in 1984 related to projected consumption and refinancing of nuclear fuel through. existing nuclear fuel trusts.
Also included for 1982 is $120 million related to the retirement of long-term debt exchanged in January 1982 for common stock with a market value of approximately $73 million.
3 "Internal Cash-Other" for 1981 includes $521 million attributable to the sale of a portion of the Catawba Nuclear Station. Without that sale, the percentage of capital requirements provided by internal cash would have been approx imately 31 percent.
"Internal Cash-Other" for 1982-1984 assumes that rate increases become effective as necessary to enable the Company to earn the allowed rates of return on common equity in the Company's retail jurisdictions, 16.5 percent in North Carolina and 13 percent in South Carolina. The Company has not achieved the allowed jurisdictional rates of return in recent years and cannot predict whether such levels of return will be achieved during the period covered by this forecast.
A The projected capital structures include current maturities of long-term debt, but exclude short-term notes payable.
4"Common Stock" includes sales of common stock through the Company's Stock Purchase Program for Employees, Dividend Reinvestment and Stock Purchase Plan and the Employees' Stock Ownership Plan. For 1982, "Common Stock" also includes approximately $73 million issued in exchange for portions of the Company's outstanding first mortgage bonds.
The "Effective Composite Income Tax Rate" is calculated by dividing total income tax provisions (current federal and state income taxes, net deferred income taxes and net investment tax credit) by pre-tax income excluding allowance for all funds used during construction, earnings of subsidiaries and other non-taxed income. The effective income tax rates differ from the Company's statutory tax rate of 49.24 percent, principally because of differences in book and tax property bases. The effective tax rate in 1981 includes the effect of the sale of a portion of the Catawba Nuclear Station.
Cost estimates for the McGuire Nuclear Station are on a total station, basis. Thus, estimated construction costs include costs related to both Unit 1 and Unit 2.
7 Estimated costs for the Catawba Nuclear Station do not include the costs of the undivided interests sold to an agency 7representing some of the Company's North Carolina municipal customers in 1978 and to groups of the Company's cooperative customers in 1981, and assume no further sale of the Company's remaining interest in the Catawba Nuclear Station. The Catawba construction schedule is now being reviewed. Any delay in planned operation dates would increase the total estimated construction costs.
8 Units 1 and 2 of the Cherokee Nuclear Station, previously scheduled for completion in 1990 and 1993, respectively, have been delayed indefinitely due to difficulties in attracting the necessary capital. Work on Unit 1 has been substantially reduced and work on Unit 2 has been interrupted while the Company fully evaluates its long-term options with respect to Cherokee. Construction costs for the three year period 1982-1984 include approximately $300 million to continue limited construction activities at Cherokee. Any change in the status of the units would increase estimated costs for this period.
9 The Bad Creek hydroelectric pumped storage facility will consist of four 250,000 KW units. Although construction completion has not been definitely scheduled, estimated construction costs assume commercial operation dates for the four units of 1990 and 1991.