ML20117A799
| ML20117A799 | |
| Person / Time | |
|---|---|
| Issue date: | 04/30/1985 |
| From: | Wood R NRC OFFICE OF STATE PROGRAMS (OSP) |
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| References | |
| NUREG-1131, NUDOCS 8505080348 | |
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a NUREG-1131 Financial Analysis of Potential Retrospective Premium Assessments Under the Price-Anderson System U.S. Nuclear Regulatory Commission Office of State Programs R. S. Wood I
8505000348 850430 31 R PDR
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4 NUREG-1131 Financial Analysis of Potential Retrospective 3remium Assessments Under the Price-Anderson System
=2srenr* "
R. S. Wood Office of State Programs U.S. Nuclear Regulatory Commission W:shington, D.C. 20565 f - s.,,
)
Table of Contents Page Table of Contents............................iii Acknowl ed gments -..............................
V I.
Background and Assumptions....................
1 II. Analysis.............................
2 A.
Analysi s of Earnings.....................
2 B.
Analysis of Internal Cash Flow................
4 I I I. Concl u s i on s............................
5 Table 1.
Impact of Various Assessments.....-...........
7 Table 2.
Number of Utilities Exceeding or Falling Under an Interest Coverage Ratio of 2.0............... 11 Table 3.
Number of Utilities Falling Within Particular Ranges of Rates of Retu rn...................... 12 Table 4.
Financial Impacts of Various Assessments: Three Year Averages, 1981 Thru 1983..................
13 Table 5.
Cash Flow Percentage Reductions...............
14 4
t
-iii-
Acknowledgments The author wishes to thank Darrel Nash and Jerome Saltzman of the Office of State Programs, Argil Toalston of the Office of Nuclear Reactor Regulation, and Sidney Feld of the Office-of Resource Management for their invaluable suggestions to improve this manuscript. Thanks should also go to Catherine Berney for her efficient, timely typing.
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Financial Analysis of Potential Retrospective Premium 4
Assessments Under the Price-Anderson System i
~
I.
Background and Assumptions
.I The 1975 amendments to the Price-Anderson Act introduced a system of retrospective assessments as the second tier of a~ comprehensive, three-tiered system for handling liability claims resulting from accidents at comercial nuclear power plants rated in excess of 4
-100MW(e).
In the event that such an accident produced liability claims exceeding the primary tier of coverage of advance premium liability; insurance (currently $160 million), licensees would be obligated to pay a pro-rata assessment up to the maximum specified in the NRC's regulations.
i From the beginning of the retrospective assessment feature of the
- Price-Anderson system, the-NRC staff has evaluated the ability of i:
reactor licensees to pay various levels of assessments. A study completed in 1976 by NRC consultant Ronald W. Melicher (Financial Implications of Retrospective Premium Assessments on Electric Utilities) (NR-AIG-003) established a methodology for evaluating.
several possible assessments by treating each such assessment as a before-tax operating expense and then examining its effect on such financial parameters as net income. return on common equity, interest coverage, earnings per share, net cash. flow and cash flow per share.
l-
' The methodology used by Melicher made several simplifying assumptions including the following: 1.
All assessments would be paid in full in i
the year made; 2.
The assessments would not be recoverable-from i
ratepayers; 3.
Utility management would take no actions to conserve cash such as reducing construction expenses or common stock dividends paid. Although these assumptions tend to overstate the effect that 4
assessments would have on utilities' finances, they are necessary both h
to keep the analysis on an equal basis for all utilities and to prevent the analysis from making overly speculative assumptions about 4,
how utility management or regulators would respond to any assessments.
The staff has subsequently updated Melicher's analysis. In 1979, the same four utilities that Melicher examined were. reanalyzed using 1978
. data.
(See Appendix A to Subject Report H,-The Price-Anderson Act -
The Third Decade, NUREG-0957, USNRC, 1983.) Additionally, potential assessments were increased to determine whether increased retrospective premiums then being considered by Congress would be able to be paid by utilities without significant adverse financial effects.
In 1982, a second reevaluation of the same four utilities using 1981
- data further increased theoretical retrospective assessments to include the effects of other retrospective' assessment insurance being i-introduced in the wake of the TMI-2 accident to provide increased coverage of property damage and new coverage of replacement power i
costs.
(SeeSubjectReportH,NUREG-0957.)
i As Congress and the public prepare to consider a variety of p
alternative insurance schemes under the Price-Anderson system, the y
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_ _ - _ _ - _ _ _ _ _. staff believes that an expanded analysis of a wide range of retrospective premiums and their effects on several utilities is appropriate. The staff has increased the number of utilities studied to ten.
In addition to the original four, we have added six new utilities representing a cross-section of size, location, financial health, and degree of participation in nuclear power generation. We l
have also analyzed data over a three-year period, 1981-1983, to determine whether any patterns of financial impact are discernable j
that would not be apparent in a single year.* A multi-year analysis also helps to " smooth out" particularly egregious years, either good or bad, although performance in any particular year or period cannot accurately predict future financial health. The staff has chosen three levels of premiums - - $10, $20 and $50 million. The $5 million retrospective premium has been dropped because all previous analyses had shown little effect on utility finances at this level. Similarly, a premium in excess of $50 million per reactor was not considered because there is little question of its drastic impact on most utility finances. Finally, as indicated above, the staff has used Melicher's original assumptions with respect to payment of dividends, non-curtailment of construction programs, and rate treatment, because to do otherwise would require unverifiable speculation over specific strategies' that utility management might adopt. Thus, the analysis gives essentially a worst-case picture of the effect of a particular assessment on a utility's finances.
II. Analysis A.
Analysis of Earnings In general, the period from 1981 through 1983 was a difficult period for many electric utilities. The period partially coincides with the 1981-1983 recession with a falloff in electricity demand but with continued high interest rates causing capital costs to remain high and continued inflation increasing construction costs. During the latter part of the period the economy improved, a development reflected in the steady financial strengthening of most of the ten utilities evaluated. Thus, while in 1981 seven of the ten utilities achieved rates of return on comon equity exceeding 10%, eight did so in 1982 and nine did so in 1983, even as capital costs generally held steady during the period. Similarly, interest coverage ** improved during the period - - in 1981, six utilities exceeded and four fell below 2.0; in 1982, eight utilities were over 2.0; and for 1983, all ten surpassed the 2.0 level. (See Tables 1 and 2.)
The data used in this analysis upon which the measures of financial performance are based have been taken from Moody's Public Utility Manual, Vols.1 and 2,1984, published by Moody's Investors Service.
- Interest coverage is defined as interest on long-term debt plus net income divided by interest on long-tenn debt.
For the utility industry, a ratio of 2.0 is considered minimally acceptable and is the minimum coverage required under most utility bond indentures for the issuance of new bonds.
. Using as a base the results actually achieved in 1981 through 1983, we can evaluate how various measures of financial health would have been affected had the ten utilities been obligated to pay three different levels of retrospective premiums. An assessment of $10 million reactor would.have meant a reduction in earnings per. share (EPS)per of as high as 20% or as little as 2% in the three years studied. The average reduction in EPS would have been 11%. At a $20 million per reactor assessment, the average EPS would have fallen 21% with one
-utility experiencing as much as a 42% drop, and another as little as a 3% drop.
Increase the assessment to $50 million per reactor and one utility would have incurred a loss, a 104% decrease in EPS. The best potential performance at the $50 million assessment level was an 8%
falloff in EPS with the average being a 52% reduction. While these reductions in EPS are in some cases quite severe they are not in themselves particularly revealing because no given level of EPS by itself indicates good or poor financial performance.
For a less relativistic measure of the impact of assessments we look next at the effect of the various assessments on interest coverage, where we find a similar weakening as assessments are increased. As indicated above, an interest coverage ratio of 2.0 or above is generally considered marginally acceptable in the electric utility industry. Most utility bond indentures require a minimum coverage of 2.0 for the issuance of new bonds to finance utility plants. As shown in Table 2, with an assessment of $10 million per reactor in 1981, six utilities would have exceeded and four utilities would have fallen shy of the 2.0 target. This was the same result achieved without any assessment. At a $20 million assessment, five utilities would have exceeded and five would not have met the target. However, a $50 million assessment would have allowed only two utilities to achieve better than a 2.0 interest coverage ratio. The results in 1982 were similar but more gradual -- as assessments were increased, the number of utilities exceeding 2.0 dropped from 8 with no assessments to 6 at
$10 million, 4 at $20 million and 2 at $50 million. The 1983 results were slightly better.
Progressing from no assessment to $50 million, those surpassing a 2.0 ratio decreased from ten utilities, to nine, to eight, to three, respectively. One utility would have achieved an interest coverage ratio of only 1.15 in 1981 with a $50 million assessment per reactor. At the opposite end of the range, another utility in 1983 would have obtained a ratio of 2.68 even with a $50 million assessment per reactor. Thus, although there was not a substantial degradation in.the interest coverage ratio up through a
$20 million assessment, a $50 million assessment would have significantly lowered most utilities below 2.0.
A third measure of the strength of a utility's earnings is rate of return on common equity. During the three-year period being analyzed, interest rates remained fairly high by historical standards with some softening in 1982 at the height of the recession.
It.is difficult to generalize about interest rates because they reflect the perceived risk of an investment as well as the changing cost of money, so that what is the market rate of return at any particular time for one entity may be too high or low for another. Nevertheless, a reasonable return on connon equity to expect from a fairly stable nuclear
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_ _ _ _ _ _ _ _ electric utility during this period would be 12% to 15%, with about 10% being the minimum needed to continue to attract adequate investment (see for example, Salomon Brothers, Inc., Stock Research Report on Electric Utilities; February 1,1985). Any return lower than 8% would indicate very serious problems in attracting capital.
An intermediate range of 8% to 10% was also chosen for evaluation to provide a general picture of how quickly an increase in assessments was affecting rate of return on common equity. As indicated in Tables 1 and 3, without any assessments utilities gradually improved their rates of return between 1981 and 1983.
In 1981, seven utilities achieved rates of return exceeding 10%; the three others fell between 8% and 10%.
In 1982, perfomance had improved to eight above 10% and two in the 8% to 10% range. By 1983, nine exceeded 10% and only one earned between 8% and 10%.
With a $10 million assessment, the utilities exceeding 10%, falling between 8% and 10%, or earning less than 8% were as follows: in 1981, six, three and one, respectively; in 1982, six, four and none; and in 1983, seven, three and none. At a $20 million assessment level, there was more pronounced variation from 1981 to 1983 and for all years there was a significantly greater impact on financial health than at a
$10 million level.
In the same order, the results for $20 million were as follows: in 1981, one, six and three; in 1982, five, two and three; and in 1983, six, three and one. At a $50 million assessment almost all utilities would fall below an 8% rate of return during each of the three years. In 1981 and 1983, seven of the ten utilities would have earned less than 8%; in 1982, eight utilities would have earned less than 8%.
In each of those years only one utility would have earned over 10% with a $50 million assessment. Thus, a $50 million assessment'would have had a very negative impact on rate of return on almost all utilities evaluated.
Table 4 provides additional perspective by showing the average return on equity and interest coverage for all ten utilities over the entire 1981-1983 period. On an average basis, return on equity would remain reasonably acceptable up through a $20 million assessment but would decline substantially after a $50 million assessment. Similarly, average interest coverage would fall below 2.0 only at the $50 million level. By point of comparison, the ten utility average return on equity and interest coverage for the three years after a $50 million assessment would be substantially better than that experienced by General Public Utilities, the owner of Three Mile Island, during the same period.
B.
Analysis of Internal Cash Flow Internal cash flow measures the amount of funds generated yearly by a company's operations.
It includes net income, depreciation on capital plant and equipment, fuel and other amortizations, and various deferred tax charges and credits. As indicated above, we have not included externally generated cash from equity or debt issues and we have also deducted from cash flow payment of both preferred and comon dividends. We have not subtracted from cash flow uses of funds such as construction programs and retirement of debt because these can
l usually be financed (or refinanced) externally or, in the case of construction, deferred when necessary.
In addition, by accounting convention such expenditures are not normally considered in analyses of internal cash flow. We believe that, taken together, cash flow is accurately respresented by these simplifying assumptions although, by building in conservatisms, actual cash flow will be understated for most utilities.
Unlike analyses of income, cash flow provides a fairly straightforward measure of a utility's ability to pay incurred expenses. Cash flow approaching zero or becoming negative is an indication of severe 1
financial distress, and if negative and not soon corrected, would precipitate bankruptcy.
(Asmentionedabove,however,inanactual situation both common and preferred stock dividends would be reduced or eliminated prior to bankruptcy.) For all the scenarios evaluated in this analysis, only at the $50 million assessment level would any utility's cash flow become negative, and even at this level, only in a few instances. For example in 1981, only one utility would have suffered a negative cash flow at the $50 million assessment level (see Table 1).
In 1982, two utilities would have failed to generate positive cash flow.
In 1983, no utilities would have obtained a negative cash flow even after a $50 million assessment.
Table 5 provides a percentage comparison of the effects of various assessments on cash flow.
In 1981, a $10 million assessment would have caused an average 13% reduction in cash flow. At $20 million, cash flow would have been reduced nearly 24% and at $50 million assessment level, the range of percentage decreases in cash flow ran from a low of a 12.6% reduction to a high of a 204% reduction.
1983 showed the least variation in the range of percentage reduction in cash flow at the $50 million level. An analysis of cash flow per share shows similar results. As a measure of the short-term ability of a utility to actually pay retrospective assessments, cash flow analysis suggests that most utilities would be able to pay even at the
$50 million assessment level, despite severe depletions of cash reserves. Table 4 shows how average cash flow for the ten utilities over the 1981-1983 period would be affected by the assessments.
III Conclusions This analysis has generally borne out the conclusions of previous NRC staff analyses. For any of the years 1981-1983, an assessment of $10 million per reactor wuld not appear to present a serious problem to most utilities.
If the assessment were increased to $20 million, signs of financial distress appear more regularly for many utilities, particularly in 1981, a particularly difficult year. Even at this level, if the assessment had occurred in 1983, most utilities would have beer able to meet it. Almost all utilities would have had severe financial problems paying a $50 million assessment in any of the three years analyzed.
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i It is interesting to note that even with an assessment of $50 million in 1983, many utilities would perform nearly as well or better as measured by some financial indicators than with only a $10 million or III even no assessment in 1981. For example, four utilities would achieve equivalent or better interest coverage in 1983 with a $50 million i4 assessment than with a $10 million assessment in 1981. Only three utilities would generate significantly less cash flow in 1983 with a
$50 million assessment and five utilities would do better in 1983 than without any assessment in 1981. Only one utility would have done worse on all five financial indicators in 1983 with a $50 million
-7 assessment than in 1981 with a $10 million assessment. What these observations seem to suggest is that many utilities have suffered from f
sufficiently poor financial performance at least occasionally in recent years that such performance is often equivalent in effect to 7
being subject to large assessments. But despite such performance, a
utilities survived and were ultimately able to improve their financial health. Clearly, then, even a $50 million assessment in one year,
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although severe, would not necessarily cause the dire results
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predicted by some.
It should be noted, however, that $50 million assessments during two or more years could have considerably worse effect on a utility's financial health. Also, performance during a g
particular period does not necessarily predict future performance.
As indicated in NUREG-0957, nearly a $50 million assessment could theoretically occur even if the retrospective premium assessment were 1
only $5 million, because of the other retroactive assessment insurance policies that utilities carry. Although this suggests that utilities y
are currently at their maximum ability to absorb retrospective assessments, the conservative assumptions built into this and earlier NRC analyses suggest that somewhat greater assessments could be handled.
Particularly if assessments are allowed to be passed on to ratepayers, as insurance costs generally are, utilities would be i
better able to cover even substantial short-tenn premium outlays if i
they could be confident that PUCs would allow recovery without significant delay. Similarly, the financial markets would probably not penalize utilities if they were confident that any outlays would a
only be uncompensated in the short run. Another factor that would ease the impact of any assessments is that the nature of liability (and, to a lesser extent, utility property) claims is such that they would be spaced over several years as damages were identified, evaluated and corrected or compensated.
Further, the property and j
replacement power retrospective insurance programs generally provide for a relatively small advance premium payment each year, not only for administrative expenses but also to build reserves to pay for future i
claims. As these reserves accumulate, the chances of a utility being i
required to pay its full potential assessment diminish.
3 I
4 E
Table 1 Impact of Various Assessments 1981 1981 1981 1981 1982 1982 1982 1982 1983
.1983 1983.
1983 BASE' 10x=
20x=
50x=
BASE 10x=
20x=
50x=
BASE 10x=
20x=-
50x=
BOSTON EDISON
=11.9M
=23.8M
=59.5M
=11.9M
=23.8M
=59.5M
=11.9M
=23.8M
=59.5M (1.19 Reactors)
EPS($)
4.80 3.87 2.94 0.15 3.81 3.15 2.47 0.47 3.60 2.91 2.21 0.12 X Interest 2.43 2.17 1.91 1.15 1.92 1.78 1.63 1.19 2.08 1.92 1.75 1.26 Ret on C.E. (%)
12.95 10.4 7.9 0.4 10.25 8.5 6.6 1.3 11.0 8.9 6.7 0.4 Net C.F. ($ mill.)
126.7 113.6 100.4 61.1 100.3 90.7 81.0 52.1 121.0 110.7 100.3 69.2 C.F./ Share ($)
8.99 8.06 7.12 4.33 6.96 6.30 5.62 3.61 8.12 7.43 6.73 4.64 COM40NWEALTH. ED.
=65M
=130M
=325M
=75M
=150M
=375M
=75M
=150M
=375M (7.5 Reactors, j
6.5 in 1981)
EPS ($ mill.)
3.06 2.49 2.20 0.81 3.75 3.32 2.89 1.60
'4.39 4.00 3.60 2.42 X Interest 1.83 1.71 1.64 1.37 2.01 1.91 1.81 1.52 2.31 2.20 2.10 1.80 i
Ret,onC.E.(%))
10.9 8.9 7.8-3.2 12.9 11.4 9.9 5.5 15.0 13.7 12.3 8.3 NetC.F.($ pill.
122.0 56.9 22.6
-126.9 268.2 210.3 152.2
-22.1 646.8 585.0 522.2 335.2 C.F./ Share ($)
1.06 0.50 0.20
-1.10 1.99 1.56 1.13
-0.16 4.09 3.70 3.30 2.12 a
l CONSUMERS POWER
=10M
=20M
=50M
=10M
=20M
=50M
=10M
=20M
=50M (1 Reactor)
EPS ($)
3.16 2.98 2.80 2.27 3.16 2.99 2.83 2.35 2.86 2.74 2.62 2.27 X Interest 1.96 1.92 1.88 1.76 2.07 1.96 1.93 1,81 2.07 2.04 2.01 1.92.
Ret. on C.E. (%)
9.14 8.6 8.1 6.6 8.6 8.2 7.8 6.4 9.0 8.7 8.3 7.2 Net C.F. ($ mill.)
128.8 120.6 110.3 79.4 114.2 103.7 93.3 62.2 70.2 60,1 49.8 19.0 l
C.F./ Share ($)
2.22 2,08 1.90 1.37 1.78 1.62 1.45 0.97 0.81 0.69 0.57 0.22 Key: EP5 = Earnings Per Share X Interest = Interest Coverage Ratio Ret, on C. E. = Rate of Return on Comon Equity Net C. F. = Net Cash Flow C.F./ Share = Cash Flow Per Share i
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Table 1 (cont'd.)
Impact of Various Assessments 1981 1981 1981 1981 1982 1982 1982 1982 1983 1983 1983 1983 BASE 10x=
20x=
50x=
BASE 10x=
20x=
50x=
BASE 10x=
20x=
50x=
DUKE POWER
=40M
=80M
=200M
=40M
=80M
=200M
=50M
=100M
=250M (5 Reactors, 4 in '81 & '82)
EPS ($)
3.19 2.78 2.37 1.14 3.59 3.23 2.87 1.80 3.70 3.20 2.69 1.18 X Interest 2.38 2.23 2.08 1.64 2.57 2.44 2.31 1.91 2.57 2.39 2.21 1.66 Ret. on C.E. (%)
13.2 11.5 9.8 4.7 14.1 12.7 11.3 7.1 14.1 12.2 10.2 4.5 Net C.F. ($ mill.)
269.5 233.8 198.0 90.6 344.2 310.9 277.5 177.0 660.2 609.9 599.6 408.9 C.F./ Share ($)
3.09 2.68 2.27 1.04 3.67 3.32 2.96 1.89 6.63 6.12 5.62 4.11 DUQUESNE
=4.75M
=9.5M
=23.75M
=4.75M
=9.5M
=23,75M
=4.75M
=9.5M
=23,75M
(.475 Reactors) a3 EPS ($)
2.06 1.97 1.88 1.62 1.95 1.88 1.81 1.59 2.10 2.04 1.98 1.80 X Interest 2.14 2.08 2.04 1.93 2.05 2.02 1.98 1.89 2.23 2.20 2.17 2.08 Ret. on C.E. (%)
8.9 8.6 8.2 7.1 8.8 8.5 8.2 7.2 10.7 10.4 10.1 9.2 Net C.F. ($ mill.)
86.4 82.8 79.2 68.4 53.2 49.7 46.1 35.4 62.8 58.4 55.7 45.0 C.F./ Share ($)
2.07 1.98 1.89 1.63 1.10 1.03 0.96 0.73 1.08 1.00 0.95 0.77 FLORIDA P&L
=30M
=60M
=150M
=30M
=60M
=150M
=38.5M
=77M
=192.5M (3.85 Reactors, 3 in '81 & '82)
EPS ($)
4.16 3.60 3.04 1.35 5.24 4.72 4.19 2.61 4.76 4.36 3.97 2.77 X Interest 1.99 1.88 1.77 1.43 2.18 2.08 1.98 1.67 2.30 2.21 2.12 1.83 Ret. on C.E. (%)
11.6 10.0 8.5 3.8 13.9 12.5 11.1 6.9 12.2 11.2 10.2 7.1 Net C.F. ($ mill.)
415.1 389.8 364.4 288.3 926.4 900.0 873.4 794.0 571.1 549.1 526.4 459.4 C.F./ Share ($)
9.16 8.60 8.04 6.36 18.38 17.86 17.33 15.75 10.14 9.75 9.35 8.16 L_
4 Table 1 (cont'd.)
Impact of Various Assessments 1981 1981 1981 1981 1982 1982 1982 1982 1983 1983
'1983 1983s BASE 10x=
20x=
50x=
BASE 10x=
20x=
50x=
BASE ~
-10x=
20x=
50x=
. NORTHERN STATES
=30M
=60M
=150M
=30M
=60M
=150M
=30M
=60M
=150ML (3 Reactors)
J
~
EPS ($)
3.89 3.29 2.68 0.85 4.78 4.20 3.61 1.86
'5.60 4.91 4.22 2.14 X Interest 3.03 2.75 2.46 1.61 2.98 2.76 2.54 1.88 3.23
. 2.98-2.72 1.95 Ret. on C.E. (%)
12.6 10.7 8.7 2.8
-14.5 12.7 10.9 5.6 16.3 14.3 12.2 6.2 Net C.F. ($ mill.)
163.6
-145.8
-128.0 74.5 220.4 202.8 185.2 132.4 419.7 398.6 377.6 314.4 C.F./ Share ($)
5.58 4.97 4.37.
2.54 7.32 6.74 6.15 4.40 13.81 13.11 12.42 10.34 P.S. COLORADO
=10M
=20M
.=50M
=10M
=20M
=50M
=10M-
=20M
=50M (1 Reactor)
EPS($)
1.88 1.73 1.57 1.11 2.11 1.98 1.85 1.45 1.82 1.69 1.56 1.18-u>
X Interest 2.70 2.58 2.46 2.12 2.70 2.61 2.52 2.25 2.53 2.44 2.35 2.07 Ret on C.E. (%)
11.5 10.5 9.6 6.8 12.7 11.9 11.1 8.7 10.9 10.1 9.4 7.1 Net C.F. ($ mill.)
91.4 84.5 77.5 56.8 197.8 191.5 185.3 166.6 114.3 108.0 101.6 82.6 C.F./ Share ($)
2.04 1.88 1.73 1.27 4.21 4.07 3.94 3.54 2.32 2.20 2.07
=8M
=16M
=40M
=23.3M
=46.6M
=116.6M
=23.3M
=46.6M
=116.6M (2.33 Reactors,
.8 in '81)
EPS ($)
4.83 4.75 4.67 4.43 5.00 4.79 4.60 4.02 6.21 6.05 5.89 5.41 X Interest 2.81 2.78 2.75 2.68 2.54 2.49 2.44 2.28 2.63 2.59 2.56 2.44 Ret. on C.E. (%)
14.7 13.9 13.7 13.0 14.2 13.7 13.1 11.5 16.2 15.8 15.4 14.1 Net C.F. ($ mill.)
273.8 266.9 260.0 239.3 52.7 34.1 15.5
-40.4 390.1 374.4 358.5 311.0 C.F./ Share ($)
3.14 3.06 2.99 2.75 0.54 0.35 0.16
-0.42' 3.93 3.77 3.61 3.14
Table 1 (cont'd.)
Impact of Various Assessments 1981 1981 1981 1981 1982 1982
-1982 1982 1983
- 1983 1983 1983 BASE
-10x=.
20x=
50x=
BASE 10x=
20x=
50x=
BASE 10x=
20x=
.50x=
=40M
=80M
=200M
=40M'
=80M
=200M
=40M
=80M
=200M-(4 Reactors)
EPS ($)
1,72 1.36 1.00
-0.07 1.86 1.51 1.16 0.13 2.15 1.83 1.52 0.59-X Interest 1.85 1.71 1.58 1.18 1.94 1.80 1.66
.1.24 2.14 2.00 1.86 1.46 Ret. on C.E.'(%)
.9.2 7.3
~ 5.4
-0.4 10.1 8.2 6.4 0.7 11.5 9.8 L8.1-3.1 Net C. F.. ($ mill.) 245.4 207.7 170.1 57.0.
356.7 315.4 274.2
-150.4' 421.8 382.8 344.4 229.2.
C.F./ Share ($)
2.34 1.98
<1.62 0.54 2.98
_2.64 2.29 1.26 3.41 3.09 2.78 1.85 EI
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Table 4 Financial Impacts of Various Assessments Three Year Averages, 1981 Thru 1983 Return on X Interest Net Cash Flow Equity (%)
Coverage
($ in Millions)
Average for Ten Utilities Zero Assessment 12.05 2.34 267.8
$10 Million/ Reactor 10.79 2.22 245.0
$20 Million/ Reactor 9.57 2.11 224.3
$50 Million/ Reactor 5.87 1.77 155.7 General Public Utilities Zero Assessment 1.63 1.15 252.1 1
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BIBLIOGRAPHIC DATA SHEET NUREG-1131 f
,e 2 te.
o.
y 3 TITLE AND Su8 TITLE 4 RECIPIENT $ ACCE SSION N GEH Financia Analysis of Potential Retrospective Premium f
Assessmen Under the Price-Anderson System
- o^'E aEPoar cowwrto MONTH IvtAR '1985 March 6.AUTHORi&)
7 DATE REP i Im>E D l*"
R. S. Wood jj 1985 9P JECTiT ASEMORE UNIT NuwSER 8 PE A,ORMING ORGANS 2AT60N NAME AND MAILING ORE S$ ldesc%de le Codel Licensee Relations Section Office of State Programs io..~ Nu
.E R U.S. Nuclear Regulatory Commis on Washington, D.C.
20555 il SPONgQRING ORGANIZATION N AME ANO MAILING ADORE 55 ffarwar t.
oars 12e TYPE OF REPORT Same as 8 above.
120 PERIOD COVERE D fiac4sese Werest 13 SUPPLEMENT ARY NOTES 14 4.051aLCT (200 soorfs er essi Ten representative nuclear utilities ha been analyz over the period 1981-1983 to evaluate the effects of three level of retrospectiv remiums on various finanical indicators. This analysis ontinues and expan on earlier analyses prepared as background for delibera4 ons by the U.S. Congr for possible extension or modification of the P tce-Anderson Act.
l
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f te IEE V IP ORDS AND DOCuwtNT ANA ~StS I SO D E SCRIP T QR $
l Financial Analy s of Utilities Price-Anderson etrospective Premiums f
Cash Flow Analysis
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