ML20199F498
| ML20199F498 | |
| Person / Time | |
|---|---|
| Issue date: | 12/31/1985 |
| From: | NRC OFFICE OF STATE PROGRAMS (OSP) |
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.2 ENCLOSURE 1 INCENTIVE REGULATION OF NUCLEAR GENERATING FACILITIES BY STATE PUBLIC UTILITY COMMISSIONS December 31, 1985 Introduction This report provides information on the methodology and potential financial impacts of performance incentives applicable to individual nuclear power plants. It is an update of the report dated January 27, 1984, " Incentive Regulation of Nuclear Generation Facilities by State Public Utility Commissions", Enclosure 2. The purpose of this report is to describe how specific nuclear plant performance incentives work tb assist in the staff's evaluation of their possible safety effects. (The staff informed the Comission of this effort in SECY-85-260, July 26,1985.) This report does not attempt to reach conclusions that particular incentives may or may not be of concern to NRC because of safety considerations.
Since the January 1984 report, several incentive plans have been implemented and others have been revised by State public utility commissions. The newer incentives and the revisions are indicated in the sumary and table of contents following on pages four and five. Descriptions of the newer incentive plans are provided in the report as are descriptions of incentives that have been substantially revised since the January 1984 report. The remaining incentive plans that were covered in the previous report are cross-referenced to that report. New material is presented on the potential >
financial impacts on the utilities of the possible penalties and/or rewards under each incentive plan.
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As indicated in the individual plant reports herein, most of the incentive plans provide for penalties and/or rewards that are relatively insignificant when compared to the utility's total financial resources. Penalties or rewards under most of the incentives, even though they may potentially amount to several million dollars, are not likely to have a significant effect on the utility's overall financial condition or well-being or on its ability to obtain financing from its normal sources including borrowings and sale of stocks and bonds. This is not to say that the potential rewards and penalties are insignificant to a degree that they would not be given consideration by utility management. The rewards and penalties may become significant when compared to an individual plant budget or when measured in terms of plant-specific decisions regarding operation or construction. Therefore, it is probably incorrect to assume that utility management would measure the effects of potential penalties and rewards only in terms of total company resources.
Most of the utilities contacted for this survey seemed knowledgeable about performance incentives applicable to their facilities. They indicated an awareness of potential financial impacts under the incentives. Some indicated an up-to-date knowledge of the relationship between current and cumulative plant performance vis-a-vis potential penalties and rewards resulting from the incentives.
It is' intended that this report will be updated and distributed semiannually by the Office of State Programs. Users of the report are requested to provide comments and suggestions for future reports. Comments and questions should be directed to James C. Petersen, Office of State Programs, telephone 492-9883.
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r 1 SurtMARY AND TABLE OF CONTENTS State Facility Type of Incentive Status 1 Page Arizona Palo Verde 1 Operating New 6 Palo Verde 1, 2 & 3 Construction New 8 Arkansas Arkansas Nuclear 1 & 2 Operating Revised 10 California San Onofre 2 & 3 Operating Same 12 Colorado Fort St. Vrain Operating Revised 15 Connecticut Millstone 1, 2 & 3 Operating Same 17 Connecticut Yankee Florida Crystal River 3 Operating Same 19 St. Lucie 1 & 2 Turkey Point 3 & 4 St. Lucie 2 Operating Discontinued 22 Maryland Calvert Cliffs 1 & 2 Operating Revised 24 Massachusetts Pilgrim 1 Operating Revised 26 Michigan Big Rock Point -
Operating Discontinued 28 Palisades New Jersey Hope Creek 1 Construction Same 30 New Mexico Palo Verde 1 Operating New 32 New York Nine Mile Point 2 Construction Revised 34 1
Status is indicated (a) for "New" incentive plans, i.e., those not included in the previous report of January 27, 1984 (Enclosure 2); (b) for incentive plans having substantially " Revised" provisions from the January 1984 report; and (c) for incentives that are substantially the "Same" as reported in January 1984. Two incentives have been discontinued.
< n SU MARY AND TABLE OF CONTENTS (Continued)
State. Facility Type of Incentive Status Page North Carolina Brunswick 1 & 2 Operating Same 36 Robinson Oconee 1, 2 & 3 Catawba 1 McGuire 1 & 2 Surry 1 & 2 North Anna 1 & 2 .
Ohio Davis-Besse Operating Same 39 Oregon Trojan Operating New 41 Virginia Surry 1 & 2 Operating Same 43 North Anna 1 & 2 Surry 1 & 2 Operating Same 45 North Anna 1 & 2 FERC Surry 1 & 2 Operating New 47 North Anna 1 & 2
. 3 ARIZONA Palo Verde 1 Operating Performance Incentive Regulatory Authority: Arizona Corporation Commission Nuclear Plant: Palo Verde 1 .
Utility: Arizona Public Service Company Status: Initiated November 1984 Measure of Productivity: Capacity factor; equivalent availability.
Type of Incentive: Reward and Penalty
Description:
The Arizona Corporation Commission (ACC) has implemented operation and construction incentive plans for Pclo Verde 1. The operating incentive does not apply to Palo Verde Units 2 and 3. The construction incentive (also applicable to units 2 and 3) is covered under the next heading.
A capacity factor deadband of 60-75 percent was established which results in no penalty or reward. Capacity factors between 75 and 85 percent will result in a reward and between 50 and 60 percent will result in a penalty. The reward / penalty is equal to one-half the replacement fuel costs avoided / incurred. Capacity factors greater than 85 percent and below 50 percent (but not below 35 percent) will result in a reward / penalty equal to
the replacemer.t fuel'cests. The weighted average fuel costs of all Arizona Public Service Company (APS)-owned generating facilities except Palo Verde and Four Corners will be used as a proxy for " replacement costs."
A capacity factor at Palo Verde 1 (PV-1) less than 35 percent will trigger an automatic reconsideration of APS's last rate case in order to determine appropriate rate base treatment of the unit. Claims by APS for special relief from the penalty clause due to an " extraordinary event" will trigger an automatic hearing.
.JThe operating incentive's effectiveness will be paased in during the year after PV-1 achieves commercial operation (after operation at 95 percent of full power for 100 consecutive hours). The incentive will be fully effective after a full 12 months' commercial operation.
Potential Financial Impacts on Utility Possible penalties per year range from $0 minimum to $4 million maximum.
Possible rewards per year range from $0 minimum to $4 million maximua. tio actual penalties or rewards have been given to date. The potential penul. f as i i
and rewards compare to APS' 1984 total operating revenues of $995 million, total operating expenses of $732 million, and net income of $271 million.
.- n ARIZONA Palo Verde 1, 2 and 3 Construction Performance Incentive Regulatory Authority: Arizona Corporation Commission Nuclear Plant: Palo Verde 1, 2, and 3 Utility: Arizona Public Service Company Status: Initiated November 1984 Measure of Productivity: Construction Cost Cap Type of Incentive: Penalty
Description:
The Arizona Corporation Commission (ACC) adopted a $2.86 billion construction cost cap to the Arizona Public Service Company (APS) share of all three Palo Verde units; there are no unit-by-unit cost caps. Amounts expended above the cap will be presumed to have been imprudently incurred. The burden
!' of proving he prudency of any excess cost will be on APS. For cost's incurred below the cap, the burden of proof of imprudency rests with the ACC. Any plant investment that would be determined imprudent by the ACC would neither be allowed to earn a return nor be covered in rates.
APS estimates that it will cost $2.7 billion to complete its share of all three Palo Verde units. This includes a contingency of approximately $200
t 1 million. As of August 1985, APS had spent $2.3 billion en all three units, including $990 million on PV-1. The cap's impact, if any, will not be felt until the cost accounting is completed on Unit 3, now projected for 1987.
Potential ~ Financial Impacts on Utility APS estimates that a $10 million imprudent plant investment in Palo Verde would reduce net income by about $0.6 million annually; a $50 million imprudent investment in Palo Verde would reduce net income by about $3.0 million. The potential penalties compare to APS' 1984 total operating revenues of $995 million, total operating expenses of $732 million, and net income of $271 million.
ARKANSAS Arkansas Nuclear One, Units 1 & 2 Operating Performance Incentive Regulatory Authority: Arkansas Public Service Comission Nuclear Plant: Arkansas Nuclear One, Units 1 and 2 Utility: Arkansas Power and Light Company Status: Initiated June 1980 Measure of Productivity: Capacity Factor Type of Incentive: Reward and Penalty
Description:
(See Enclosure 2, pp.13-17; additional infonnation follows.)
TheArkansasPublicServiceCommission(PSC)hasmodifiedprovisionsofthis perfonnance incentive as follows:
For the first cumulative 30 days (rather than each consecutive 30 days, as -
before the PSC modification) of outage (other than for refueling) during the 78 week fuel cycle, Arkansas Power and Light Company (AP&L) is penalized 90 percent of replacement power costs. For cumulative outages beyond 30 days, AP&L is now penalized ten percent of replacement power costs. This is a favorable change to AP&L because, previously, the 90 percent penalty applied to the first 30 days of any new outage. As revised, the 90 percent penalty
r t A can be applied only once to the first cumulative 30 days of outage during the 78 week fuel cycle.
Potential Financial Impacts on Utility Potential penalties and rewards both range from zero up to the actual cost of replacement fuel. The company has not calculated the upper limits of penalties and rewards because they fluctuate with the cost of replacement fuel.
The largest actual penalty (for both units combined) attributable to a single month was $15 million in November 1980. The cumulative net penalty (including some offsetting rewards) for the period June 1980 through August 1983 was $40 million for both units. Actual performance has improved (particularly in 1984) such that the cumulative net penalty for June 1980 through May 1985 was reduced to $13 million. Rewards were earned during the latter part of this period that offset earlier penalties to an extent.
The penalties and rewards compare to AP&L's 1984 total . operating revenues of
$1,308 million, total operating expenses of $1,065 million, and net income of
$143 million.
4 'I CALIFORNIA San Onofre 2 and 3 Operating Performance Incentive Regulatory Authority: California Public Utilities Commission Nuclear Plant: San Onofre Units 2 and 3 Utilities: Southern California Edison Company San Diego Gas and Electric Company Status: Initiated September 1983 Measure of Productivity: Capacity Factor Type of Incentive: Reward and Penalty
Description:
(See Enclosure 2, p.18; additional information follows.)
San Onofre Unit 3 is now also covered by this incentive plan. The licensee anticipates that San Onofre Unit I will also be placed under this incentive.
Southern California Edison Co. (SCE) and San Diego Gas and Electric Co.
(SDG&E) are appealing provisions of the incentive plan to the California PUC (CaPUC) since, in the utilities' view, penalties are much more likely than rewards. As discussed in Enclosure 2 (p.18), penalties are assessed for capacity factors below 55 percent and rewards are given above 80 percent.
According to SCE, near perfect operation with a relatively short refueling
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period would result in a theoretical maximum capacity factor of 84 percent, only four percentage points above the reward trigger. SCE believes that the units can be realistically expected to operate below 80 percent capacity factor on average. Units 2 and 3 each achieved a capacity factor slightly above 55 percent during the first fuel cycle, recently completed.
Note: Enclosures 3 and 4 are correspondence in September 1985 between the NRC staff and SCE, lead licensee for San Onofre. The letters deal with California PUC staff recommendations and pending CaPUC actions perceived by the licensee to create economic incentives pertaining to construction and operation of nuclear power plants. Although not part of formal incentive plans, the pending CaPUC actions may create economic incentives that could influence licensee decisionmaking. Hearings are in progress at the time of this report and a CaPUC decision is expected in the fourth quarter of 1986.
Potential Financial Impacts on_ Utilities u
Penalties and rewards are calculated on a fuel cycle basis (approximately 14-18 months), not en an annual basis. For capacity factors just below 55 l
percent, the penalty is $1.5 million per percent to SCE ($0.6 million per percent to SOG&E), increasing somewhat for lower capacity factors. There is no upper limit to the amount of the penalty. SCE indicates that, as a practical matter, the CaPUC would probably suspend the effectiveness of the plan if an extraordinary event caused a long-term outage of either unit. A long-term outage would otherwise cause incentive plan penalties.
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t E Rewards for capacity factors just above 80 percent are $1.2 million per percent to SCE ($0.4 million per percent to SDG&E), decreasing somewhat for higher capacity factors. As noted above, SCE indicates that the maximum achievable capacity factor is about 84 percent. This would result in a total reward for the fuel cycle of $4.8 million to SCE and $1.6 million to SDG&E, The first fuel cycle period for Units 2 and 3 resulted in capacity factors of 55.3 percent and 55.4 percent, respectively. Since both results were in the deadband range (55-80 percent), no penalties or rewards resulted.
The potential penalties and rewards applicable to SCE compare to SCE's 1984
) total operating revenues of $4,899 million, total operating expenses of $3,933 million, and net income of $732 million. The potential penalties and rewards applicable to SDG&E compare to SDG&E's 1984 total operating revenues of $1,621 million, total operating expenses of $1,369 million, and net income of $183 million.
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COLORADO Fort St. Vrain Operating Performance Incentive Regulatory Authority: Colorado Public Utilities Commission Nuclear Plant: Fort St. Vrain Utility: Public Service Company of Colorado Status: Initiated December 1980; modified November 1983; Effectiveness currently stayed by Colorado Supreme Court; disposition of incentive plan is pending, court decision expected mid-1986.
Measure of Productivity: Capacity Factor Type of Incentive: Penalty
Description:
(See Enclosure 2, p. 19; additional information follows.) The Fort St. Vrain incentive program was developed in response to problems with the plant's helium gas-cooling system and requires the company to refund excess fuel costs if the nuclear plant is not sufficiently reliable.
Refunds are based on a rolling 12-month average capacity factor. If this average is less than 53 percent then the penalty is applied to the shortfall.
For every consecutive month the plant remains nonoperational the monthly penalty increases as the rolling average capacity factor falls, reaching a f- ~
maximun refund of $3.8 million per month when the plant is out of service for 12 months.
The program compares the cost of power produced at Fort St. Vrain, valued at the authorized incremental base rate, to the imputed cost of the power valued at the rate that would be paid to independent producers. If that imputed cost is less than the cost of power produced at Fort St. Vrain, then the difference is refunded to the ratepayers.
Potential Financial Impacts on Utility Possible penalties per year range from $ minimum to $45.6 million maximum.
No actual penalties have been levied to date because of the court's stay of effectiveness noted above. Future effectiveness of the incentive plan is expected to be decided about mid-1986. If the plan were in effect, the maximum $45.6 million annual penalty would be a substantial percentage of the company's net income (see financial summary, below).
This incentive plan makes no provision for rewards.
Possible penalties compare to Public Service of Colorado's 1984 total operating revenues of $1,802 million, total operating expenses of $1,592 million, and net income of $145 million.
CONNECTICUT Millstone 1, 2, and 3 Conn. Yankee (Haddam Neck)
Operating Performance Incentive Regulatory Authority: Connnecticut Public Utilities Control Authority Nuclear Plants: Millstone 1, 2, and 3 Connecticut Yankee (Haddam Neck)
Utilities: Connecticut Light & Power Company Hartford Electric Light Company (merged into Connecticut Light &
PowerCo.)
Status: Initiated June 1979 Measure of Productivity: Capacity Factor i
Type of Incentive: Penalty
Description:
(See Enclosure 2, pp 19-20; additional information follows.) As indicated in Enclosure 2, for actual composite nuclear capaci;y factors above -
70 percent, the savings in replacement fuel costs by using nuclear generation rather than oil are credited to customers. Connecticut Light & Power Company (CL&P) receives no reward and pays nothing extra. For actual capacity factors between 55 percent and 70 percent, customers pay the differential between replacement fuel (normally oil) costs and nuclear fuel costs. The Connecticut Public Utilities Control Authority indicates that a problem with this
incentive plan is that the utility has no incentive to operate its nuclear plants above 70 percent capacity factor. The utility's only incentive is to avoid actual capacity factors below 55 percent where it must bear the differential between replacement fuel costs and nuclear fuel costs.
Potential Financial Impacts on Utility The only potential financial impact on CL&P is that it must pay replacement fuel costs when the nuclear capacity factor is below 55 percent. Neither the utility nor the DUC have quantified the potential penalty. It would be based on the actual differential between oil and nuclear fuel costs. A penalty has never been levied under this incentive plan because CL&P's composite nuclear capacity factor has been above 55 percent since the incentive plan was introduced. The actual composite nuclear capacity factor for the 12 months ended July 31, 1985 was 73.7 percent. The utility's projected capacity factor for the subsequent 12 months is 75.2 percent.
CL&P's 1984 total operating revenues were $1,779 million, total operating expenses were $1,488 million and net income was $284 million.
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FLORIDA Crystal River 3 St. Lucie 1 & 2 Turkey Point 3 & 4 Operating Performance Incentive Regulatory Authority: Florida Public Service Comission Nuclear Plants: Crystal River 3 St. Lucie 1 & 2 Turkey Point 3 & 4 Utilities: Florida Power Corporation Florida Power and Light Company Status: Initiated September 1980 Measure of Productivity: Equivalent Availability; Heat Rate Type of Incentive: Reward and Penalty
Description:
(See Enclosure 2, pp. 21-23.) -
Potential Financial Impacts on Utilities Florida Power Corporation Possible penalties and possible rewards (attributable to Crystal River Unit 3) both range from zero to $720,000 every six months.
The company incurred the following rewards for the six-month periods indicated:
October '83 - March '84 + $680,000 April '84 - Sept. '84 + $540,000 October '84 - March '85 + $720,000 The penalties and rewards compare to Florida Progress Corporation's 1984 total operating revenues of $1,350 million, total operating expenses of $1,035 million, and net incot.. of $116 million. (Florida Power Corporation, the utility licensee, is the primary subsidiary of Florida Progress Corporation, a holdingcompany.)
Potential Financial Impacts on Utilities, continued Florida Power and Light Company Possible penalties and possible rewards (attributable to each nuclear unit) both range from zero to approximately $1.0-$1.3 million every six months.
The company incurred the following actual net penalties attributable to each nuclear unit for the six-month calculation periods indicated.
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October '83- April '84- October '84-March '84 Sept. '84 March '85 Possible Actual Possible Actual Possible Actual Turkey Point 3 $1.1 -$1.1 i $1.3 -$0.8 i $1.3 -$1.2 Turkey Point 4 $1.3 -$0.8 1 1.2 -$1.1 $1.1 -$1.1 St. Lucie 1 y -
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$1.0 -$0.9 y Not covered by performance incentive this period.
The penalties and rewards compare to Florida Power and Light's 1984 total operating revenues of $3,940 million, total operating expenses of $3,347 million, and net income of $352 million.
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FLORIDA St. Lucie 2 Operating Performance Incentive Regulatory Authority: Florida Public Service Commission Nuclear Plant: St. Lucie 2 '
Utility: Florida Power and Light Company Status: Was in effect for one year only, August 1983-August 1984; now discontinued Measure of Productivity: Capacity Factor Type of Incentive: Reward and Penalty
Description:
The PSC set a capacity factor target of 89 percent for St. Lucie
- 2. For every percentage point that St. Lucie 2's actual annual capacity factor was over or under the 89 percent target, the Commission rewarded / penalized FP&L $1 million. The $1 million reward / penalty amount was only applicable within a 75 to 100 percent capacity factor range. No reward could exceed total fuel savings.
Potential Financial Impacts on Utility Possible penalties per year ranged from $0 minimum to $14 million maximum.
Possible rewards per year ranged from $0 minimum to $11 million maximum.
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1 St. Lucie 2's actual capacity factor .for the one year that this incentive was effective was 92.48 percent. The total ireward for the year was $3.48 million, s
The possible penalties and rewards compare to Florida Power and Light's 1984 total operating revenues of $3,940 million, total operating expenses of $3,347 million, and net income of $352 million.
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MARYLAND Calvert Cliffs 1 & 2 Operating Performance Incentive 3 gulatory Authority: Maryland Public Service Commission Nuclear Plant: Calvert Cliffs 1 and 2 .
Utility: Baltimore Gas and Electric Company Status: Pending; case-by-case reviews of individual unit outages continue (see Enclosure 2, pp. 24-26) while Public Service Comission considers proposals for a formal incentive plan.
Measure of Productivity: Capacity factor (one proposed plan)
Type of Incentive: Rewards and Penalties (one proposed plan)
Description:
(See Enclosure ?, pp. 24-26; additional information follows.)
The Maryland Public Service Comission policy of conducting reviews of individual unit outages continues as described in Enclosure 2. Baltimore Gas and Electric Co. (BG&E) and other Maryland utilities have filed proposals for a formal incentive plan that would replace the case-by-case review of individual unit outages. One proposed program includes standards for the capacity factor of nuclear units. There is a deadband on either side of the target capacity factor which would result in no reward or penalty. Rewards and penalties outsi#e the deadband are based on replacement power cost as
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capped,at 1 percent of the equity investment in covered units, it is expected
, that a formal incentive plan will replace the case-by-cas_e reviews, but not -
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Potential Financial Impacts on Utility:
4 Potenkialfinancialimpactshavenotyetbeenquantified. BG&E's 1984 total operating revenues were $1,208 million, total operating expenses were $931 million, and net income was $244 million. .
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MASSACHUSETTS Pilgrim Operating Perfomance Incentive Regulatory Authority: Massachusetts Department of Public Utilities Nuclear Plant: Pilgrim Utility: Boston Edison Company Status: Initiated August 1981; revised 1983; revised 1985' Measure of Productivity: Equivalent Availability; Heat Rate h of Incentive: Penalty
Description:
(See Enclosure 2, pp. 26-28; additional information follows.)
Targets for plant efficiency factors are filed annually by all Massachusetts utilities. These are compared to monthly plant statistics filed by the utilities to aid in judging the prudency of utility fuel expenditures. In a 1983 decision, Boston Edison was ordered to compare its plant performances (with separate analyses for fossil and nuclear units) with the plant performances of a selected group of companies. The Department of Public Utilities selects the sample to analyze. In a 1984 decision, the Company's proposed targets were rejected. The most recent decision, in 1985, sets optimal equivalent availability targets at the eighty-fifth percentile of the sample analyzed. If a plart misses a performance goal there is an
investigation of replacement power costs. Whatever expenses are found to be imprudent are denied.
In its next case, Boston Edison is required to produce a time-line shcwing its plan to reach these targets. This modification of the original program may be extended to all utilities.
The program applies to all utilities even if a plant is located outside th.e State. It also applies to plant owners even if the utility headquarters are outside the State and the utility is not the plant operator (thus, most of the Yankee companies would be affected). The latter is subject to a court ruling, however. There is no decision at this time.
Potential Financial Impacts on Utility There is no cap on the amount of penalty up to the full amount of the replacement power cost. There are no rewards other than full fuel cost recovery if an outage is found to be prudent. So far there have been two penalties--one about $3 million and one in the $6 million range. This compares to Boston Edison's 1984 total operating revenues of $1,317 million, total operating expenses of $1,165 million, and net income of $89 million.
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MICHIGAN Big Rock Point Palisades Operating Performance Incentive Regulatory Authority: Michigan Public Service Commission Nuclear Plants: Big Rock Point Palisades Utility: Consumers Power Company Status: Discontinued 4
Measure of Productivity: Availability Type of Incentive: Reward and Penalty
Description:
(See Enclosure 2, pp. 28-31.) Thisdiscontinuedincentive(the
" Availability Incentive Provision") allowed for a higher return (up to 0.5 percent) if power plant availability goals were met or a lower return up to -
0.25 percent for availability goals not met. The program was discontinued as a result of consumer-sponsored referendums and legislative actions banning automatic rate adjustments.
Potential Financial Impacts on Utility Financial impacts have not been calculated because this incentive has been discontinued.
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NEW JERSEY Hope Creek 1 Construction Performance Incentive Regulatory Authority: New Jersey Board of Public Utilities Nuclear Plant:' Hope Creek 1 Utilities: Public Service Electric and Gas Co.
Atlantic City Electric Company
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Status: Initiated July 1983 4
L Measure of Productivity: Total construction costs Type of Incentive: Reward and Penalty
Description:
(See Enclosure 2, pp. 37-38) i Potential Financial Impacts on Utility l
Public Service Elt'ctric and Gas Company (PSE&G) (95 percent owner) and l
Atlantic City Electric Company (5 percent owner) have spent approximately I $3.825 billion on Hope Creek through November 1985. They expect that the l total cost.will be in the range of $4.15 billion to $4.3 billion, depending on the commercial operation date, now projected for some time in the second half of 1986.
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A total actual cost of $4.15 billion would exceed the cost cap ($3.76 billion) by $390 million. Under the incentive plan formula established by the New Jersey Board of Public Utilities, prudent expenditures up to $310 million of the $390 million overrun could be recovered from customers; at least $80 million would be disallowed.
A total actual cost of $4.3 billion (the upper end of PSE&G's current estimate) would exceed the cost cap by $540 million. Prudent expenditures up to $415 million of the overrun could be recovered from customers; at least
$125 million would be disallowed.
The potential disallowances discussed above are based on PSE&G's current cost estimate and would be spread over the useful life of the facility. For example, a range of $80 million to $125 million total disallowance spread over a 40-year plant life (assuming a 10 percent overall rate of return) would translate into an approximate annual revenue loss between $10 million and $15 million for the life of the facility. PSE&G's 1984 total operating revenues were $4,196 million, total operating expenses were $3,598 million, and net income was $490 million.
NEW MEXICO Palo Verde 1 Operating Performance Incentive Regulatory Authority: New Mexico Public Service Commission Nuclear Plant: Palo Verde 1 Utility: Public Service Company of New Mexico Status: Initiated January 1984 Measure of Productivity: Excess Generation Capacity 1
Type of Incentive: Penal ty
Description:
When a coal-fired unit and the Palo Verde plant come on line, the Public Service Commission has ruled that PSNM will have generation plant in excess of its requirements. The PSC has stipulated that plant will be allowed in rate base only to the level of the system peak plus 20 percent reserve margin. The remaining plant will be inventoried. The inventoried plant will be the newer plants and will earn AFUDC, which will be amortized -
over the remaining life of the plant once it comes out of inventory. PSNM must file a report by October 1 of each year to the PSC. After opportunity for public hearing, the Commission determines the amount that must be inventoried for the following year.
There is a cap on the amount of AFUDC which can be accumulated, in that the net book value of the plant including AFUDC must grow by no more than 4 to 5 percent per year, excluding betterments (exact percent depends on how many years the plant has been in inventory). The incentive of the program is to encourage sales of electricity to off-system customers, outside New Mexico.
Revenues from these sales can be applied to any penalty resulting from the cap on AFUDC. The program affects how load is dispatched. It applies only to retail sales. Thus PSNM would attempt to avoid FERC-regulated sales (wholesale)frominventoriedplants. The aims of this economic incentive are to shield the ratepayers from the rate shock associated with large additions to rate base, provide some protection for shareholders and give PSNM an incentive to make off-system sales from the excess capacity.
Potential Financial Impacts on Utility No penalties have been given due to the newness of inventoried plants. The coal plant was inventoried in 1985 and Palo Verde 1 will be inventoried in 1986. It is difficult to estimate a maximum impact because of offsetting program features.
l Recently, PSNM sold a portion of its 10.2 percent share of Palo Verde 1 to an investment group and is leasing it back. This sale and leaseback does not change the relationship of PSNM to the PSC with regard to ratemaking. It is i
uncertain how this sale and leaseback will affect the incentive program; however, it can reasonably be expected to be minor. PSNM's 1984 total operating revenues were $445 million, total operating expenses were $299 millton, and net income was $133 million.
NEW YORK Nine Mile Point 2 Construction Performance Incentive Regulatory Authority: New York Public Service Comission Nuclear Plant: Nine Mile Point 2 Utilities: Niagara Mohawk Power Corporation (lead licensee)
Central Hudson Gas and Electric Corporation Long Island Lighting Company New York State Electric and Gas Corporation Rochester Gas and Electric Corporation Status: Initiated February 1982; revised incentive being considered by New York Public Service Comission Measure of Productivity: Total construction costs Type of Incentive: Reward and Penalty
Description:
(See Enclosure 2, pp. 38-39; information on proposed revision to incentive follows.)
In July 1985 the New York Public Service Commission (N.Y. PSC) initiated an investigation into the prudence of Nine Mile Point 2 construction costs. It resulted in a September 1985 joint settlement offer agreed to by the five utility co-owners and the N.Y. PSC staff. The offer, now being considered by
the N.Y. PSC, would eliminate provisions of the previous incentive plan and would substitute a $4.45 billion total construction cost cap on the facility.
A PSC decision is due by March 1986. Under the proposed plan, prudent costs up to the new cap could be recovered from ratepayers; all excess costs would be borne by the utilities and their stockholders. The utilities now estimate their total cost to complete construction at $5.35 billion, creating a $900 million overrun.
Potential Financial Impacts on Utilities Provisions of the proposed revision are subject to change by the N.Y. PSC.
However, as an example of potential effects under the proposed revised plan, Niagara Mohawk, lead owner, would bear 41 percent (its ownership percentage) of any penalty. $369 million of the projected $900 million overrun would be borne by Niagara Mohawk. Assuming a 40-year plant life and a 10 percent overall rate of return, Niagara Mohawk would be penalized approximately $46 million in forgone revenues per year for the life of the facility. Niagara Mohawk's 1984 total operating revenues were $2,786 million, total operating expenses were $2,393 million, and net income was $360 million.
NORTH CAROLINA Brunswick 1 & 2 Robinson Oconee 1, 2 & 3 Catawba 1 McGuire 1 & 2
_Surry 1 & 2 North Anna 1 & 2 Operating Performance Incentive Regulatory Authority: North Carolina Utilities Commission Nuclear Plants: Brunswick 1 and 2 (CP&L) McGuire 1 & 2 (Duke)
Robinson (CP&L) Surry 1 & 2 (VEPC0)
Oconee 1, 2 & 3 (Duke) North Anna 1 & 2 (VEPCO)
Catawba 1 (Duke)
Utilities: Carolina Power and Light Company Duke Power Company Virginia Electric and Power Company Status: Initiated June 1982 Measure of Productivity: Fuel and Purchased Power Costs l
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Type of Incentive: Reward and Penalty l
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Description:
(See Enclosure 2, pp. 31-34; additional information follows.)
The. Utilities Commission allows electric utilities to include a fuel charge adjustment as a rider to their rates. For each utility engaged in the generation and production of electric power by fossil or nuclear fuels, the
-Utilities Commission holds a full evidentiary hearing to determine whether an increment or decrement rider is in order. This total fuel factor amount can only be reset once every 12 months or during general rate hearings. Until recently, fuel costs were forecasted for a normalized historic test year and were based, in part, on expected plant capacity and availability factors. A recent decision of the Utilities Commission is to use lifetime average capacity factor by unit.
The Utilities Commission allows only that portion of a requested fuel charge that is based on adjusted and reasonable fuel expenses prudently incurred under efficient management and economic operations. Until recently utilities could keep any fuel cost savings below the forecast and must absorb any fuel cost overruns. Now the Utilities Commission has adopted a limitation on reward / penalty. If there is an overrun of costs, the utility must cover 90 percent of the overrun; if there is an underrun the utility may keep 10 percent of the underrun. This provision is now before the state supreme court. The program keys on capacity factor. As indicated above, the historical capacity factor of each unit is used for the test period. For nuclear units these are in the 60 percent range.
Another incentive program relates to the utility's allowed rate of return.
The Utilities Commission may adjust up or down the rate of return which would i
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otherwise be justified. This is to recognize excellent performance and management or to penalize deficient management.
Potential Financial Impacts on Utilities Potential impacts are examined in relation to the two utilities that could be most affected, Duke and Carolina Power and Light. Potential impacts would be significantly less on VEPC0 since the majority of its service area is not in North Carolina.
Carolina Power and Light. A 1984 reduction in return on common equity to penalize faulty management resulted in a $13 million revcnue cut. A generalized reduction due to a fuel penalty was " smaller than the $13 million," according to the company, but no evaluation has been done as to the exact amount. These penaltic.s compare to CP&L's 1984 total operating revenues of $1,854 million, total operai tng expenses of $1,508 million, and net income of $294 million.
l Duke Power Company. Until the court case noted above is decided, the i
financial impact will not be known. It could be from a $2 million to a $20 million penalty spread over several years. In the most recent Commission l
decision, the rate of return was set at 1/4 point higher than otherwise justified to recognize excellent performance and management. The above l
l penalties compare to Duke's 1984 total operating revenues of $2,717 million, total operating expenses of $2,169 million, and net income of
$461 million.
OHIO Davis-Besse Operating Performance Incentive Regulatory Authority: Ohio Public Utility Commission Nuclear Plant: Davis-Besse Utilities: Toledo Edison Company Cleveland Electric Illuminating Company Status: Implemented February 1981 Measure of Productivity: Combination of operating efficiency measures Type of Incentive: Reward and Penalty
Description:
(See Enclosure 2, pp. 34-35; additional information follows.)
This program involves a number of efficiency measures including fuel utilization, fuel procurement, sales pricing policy, and purchased power policy. These factors tend to converge so that in practice the rewards or penalties are modest.
The PUC has a hearing about every six months to decide what fuel cost recovery can be allowed for the ensuing six months. Factors considered include current and expected fuel costs, reconciliation for any over- or under-recovery in the prior period, and system loss adjustment.
At each six month test period there is always an under-recovery or over-recovery of fuel costs because the expected fuel costs and actual fuel costs for the period are different. If the utility's efficiency measures are above an acceptable level, the utility does not have to absorb all of the fuel cost under-recovery, nor do they have to refund all of the over-recovery.
In practice, the program works more as a positive reward than as a penalty.
However, in the long run, customers are not expected to pay more than they would without the program.
Potential Financial Impacts on Utility The program does not have the potential for having a major impact on the company. There is a cap on over-recovery but not on under-recovery. No real effort has been made to isolate the actual impact of the program on revenues.
The maximum penalty is estimated to be between $500,000 and $1 million within a six month test period. This compares to Toledo Edison's 1984 total operating revenues of $551 million, total operating expenses of $428 million, and net income of $154 million. Cleveland Electric's 1984 total operating revenues were $1,215 million, total operating expenses were $953 million, and net income was $292 million.
OREGON Trojan Operating Performance Incentive Regulatory Authority: Oregon Public Utility Commission Nuclear Plant: Trojan Utility: Portland General Electric Company Status: Initiated 1980 Measure of Productivity: Fuel and Purchased Power Costs Type of Incentive: Reward and Penalty
Description:
The Power Cost Adjustment Program sets targets for fuel and purchased power costs, estimated quarterly, as part of regular rate case proceedings. At the beginning of the quarter variable operating costs are estimated based on expected use of thermal and hydro plants. At the end of the quarter a comparison is made with actual costs. The reward / penalty incentive associated with this program enables the Company to retain 20 percent of any savings from keeping fuel and puchased power costs under the target level and to absorb 80 percent of any excess fuel and purchased power costs.
This is a company-wide program and is greatly impacted by how much the hydro capacity is used. If Trojan operates well this improves company-wide cost
performance. The PUC has the authority to change any regulatory program if it is not operating properly.
Potential Financial Impacts on the Utility The overall effect is to reduce utility earnings. The base rates were set with some conservatism. The impacts during the last two years have been around $15 million in penalty per year. There can be no more than 4 mills per kilowatt hour reward or penalty per quarter.
If there is, the excess is transferred to later quarters. The cap is therefore about $15 million per quarter. These figures compare to Portland General's 1984 total operating revenues of $722 million, total operating expenses of $451 million, and net income of $158 million.
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VIRGINIA Surry 1 & 2 North Anna 1 & 2 Operating Performance Incentive Regulatory Authority: Virginia State Corporati6n Commission (VCC)
Nuclear Plants: Surry 1 and 2 North Anna 1 and 2 Utility: Virginia Electric and Power Company Status: Initiated January 1979 Measure of Productivity: Fuel and Purchased Power Costs Type of Incentive: Reward and Penalty
Description:
(See Enc 1ciure 2, pp. 36-37.)
Potential Financial Impacts on Utility i
There is no specific set of rewards and penalties as they are included as a subjective decision factor in the fuel cost recovery allowance. P5tential l
, penalties and rewards therefore can not be quantified, although they are a l
l real factor in VEPC0 rates. They are factored into rates during the annual Y
VCC fuel recovery clause. proceeding. This was most recently considered in the fall 1985.
-VEPC0's 1984 total operating revenues were $2,605 million, total operating expenses were $2,041 million, and net income was $343 million.
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VIRGINIA Surry 1 & 2 North Anna 1 & 2 Operating Performance Incentive Regulatory Authority: Virginia State Corporation Commission Nuclear Plants: Surry 1 and 2 North Anna 1 and 2 Utility: Virginia Electric and Power Company -
Status: Initiated January 1979 Measure of Productivity: Generating Unit Performance Type of Incentive: Reward and Penalty
Description:
The Virginia Corporation Commission (VCC) provides incentives based on improved generating unit perfornance. During general rate cases, the composite test-year performance of the company's nuclear and fossil plants is compared to historical performance. For the purpose of ratemaking, a range for return on common equity is selected. Within that range, the VCC recommends a specific return for the company based on the units' performance during the test period.and over time.
Potential Financial Impacts on Utility Potential rewards and penalties are based on subjective judgment presented in individual rate case testimony. In principle, this incentive provides that the better the plant performance, the higher should be the allowed return on equity. Because of its subjective nature, VEPC0 has not attempted to quantify the possible financial effects of this incentive. Indeed, in the last rate case where the incentive would have been applicable (1983), no penalty or reward was given. VEPC0's 1984 total operating revenues were $2,605 million, 4
total operating expenses were $2,041 million, and net income was $343 million.
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FERC Surry 1 & 2 North Anna 1 & 2 Operating Performance Incentive Regulatory Authority: Federal Energy Regulatory rc_, mission Nuclear Plant: Surry 1 and 2 North Anna 1 and 2 Utility: Virginia Electric and Power Company Status: Initiated May 1983; continuing (3-year trial basis)
Measure of Productivity: Capacity Factor Type of Incentive: Reward and Penalty
Description:
The rate of return on equity (ROE) allowed by the Federal Energy Regulatory Commission will vary up to one percent depending on how closely actual composite performance of 12 coal and four nuclear units matches predetermined equivalent availability and heat rate standards for the coal units and capacity factor standard fce nuclear units.
The company must exceed the composite coal and nuclear performance standard by at least five percent to trigger a reward. Likewise, the company must ,,
_. -- underrud'the performance standard by at least five percent to trigger a
,> * l
48 -
penal ty. This amounts to a deadband of plus or minus five percent around the performance standard. Any rewards or penalties are limited to 100 basis points (one percent) of the allowed R0E.
It is unknown at this time whether this three-year trial basis incentive will be continued beyond May 1986.
Potential Financial Impacts on Utility The magnitude of potential penalties and rewards fluctuates with the amount of the current rate base and the allowed R0E. The company does not keep records of potential financial effects of the incentive. Since inception of this performance incentive, VEPC0 received a $141,000 reward in 1983, and no penalties or rewards in 1984 and 1985.
VEPCO's 1984 total operating revenues were $2,605 million, total operating expenses were $2,041 million, and net income was $343 million.
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.1 NUCLEAR REGULATORY COMMISSION WASHINGTON, D. C. 20666 i
% ,, ,,, # January 27. 1984 PEMORANDUM FOR: Frank H. Rowsome. Assistant Director for Tesnology.
Division of Safety Technology. NRR FROM: Jemme.Saltzman. Assistant Director for State and Licensee Relations. OSP
SUBJECT:
INCENTIVE REGULATION OF NUCLEAR GENERATION FACILITIES BY STATE PUCs Enclosed is our report on the subject of incentive regulation of generation facilities by State public utility cosuitssions. The incentive programs reported herein are those specifically applicable to nuclear facilities. Other programs apply to fossil plants. In drawing from the three current studies on the subject, an attempt was made to sort out fmm a large amount of information that material that may be of interest to reactor safety regulatdes. If there are questions related to this material please contact Jim Petersen of this office on 492-9883.
/sl it?CMT R*:Ty?*%
Jerome Saltzman. Assistant Dimetor State and Licensee Relations Office of State Programs
Enclosure:
As stated l
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' January 27, 1984 ENCLOSURE 2
,- INCENTIVE REGULATION OF GENERATION FACILITIES BY STATE PUCs Incentive plans aimed at increasing the efficiency of operation of nuclear power plants are in effect in eleven States. Two States have plans providing cost incentives related to construction of nuclear plants. This paper sumarizes the provisions of such incentive plans.
It. also sunnarizes the findings pertinent to nuclear power of the three recent national studies on this subject. An attempt has been made to sort out'and higt'ight the studies' findings that may be most interesting to reactor safety regdlators. The recent studies have been done by the National Association of Regulatory Utility Comissioners (NARUC)II , the S. M. Stoller Corporation (for the California PUC) I ,
and the Quadrex Corporation (for EEI). 3/
1/"IncentiveRegulationintheElectricUtilityIndustry,"preparedby the NARUC Subcomittee on Electricity, September 1983.
-2/ " Standards of Performance Study, SONGS 1," 5. M. Stoller Corporation, for California PUC, under contract to Southern California Edison Co.,
A 3/ "ugust 1983.
Incentive Re (final draft)gulation Programs
, Quadrex Corp., forinEEI, theJuly Electric 1983.Utility Industry,"
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Summary of Findings - NARUC Although the NARUC study is primarily a survey and descrip ion of individual State incentive plans, it does provide some overall findings and conclusions. NARUC, the national organization of State public utility commissioners and other utility regulators and their staffs (note: NRC is a member of NARUC), says that a very significant level of regulatory effort is being exerted to develop incentive regulation in the electric utility industry.
"It appears t,o be widely recognized that incentives may provide a means of assuring relisble electric service at a more reasonable cost than a continuous, rigorous, and detailed review of each utility's operations (as has been the traditional PUC mode of operation). Limitations on the budgets of regulatery agencies, which have always existed, but have become more acutt, also indicate the necessity for more effective and efficitnt regulatory tools. Currently, the greatest regulatory effort appears to be directed at the efficiency of operation and utilization of generation facilities. This is particularly understandable in those States where energy costsh(fuel,a' dn purchased power) represent 50 percent and more of the electric utilities' total cost of operation." b s
s S/ NARUC Study, p. 1-1.
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." The NARUC study recomenhed further regulatory initiatives in the area of perfomance incentives and said that regulatory agencies should establish a high priority for such projects. NARUC recommended the following approaches in carrying this out:
o The appropriate allocation of replacement energy cost between ratepayers and stockholders.
o A combination of continuing regulatory review of detailed perfomance indicators with an indexing system to be applied between major operation reviews (general rate cases).
o The application of decision analytic techniques to the measurement of relative perfomance.
o Aggregate performance as measured by such indicators as average unit revenue and the growth rate of operating and maintenance expenses.
Sumary of Findinos - Stoller In October 1981, the California Public Utility Commission (CPUC) directed Southern California Edison Company (Edison) to engage a consultant to carry out a standards of perfomance study for the SONGS-1 nuclear unit. In November 1982, the CPUC selected the S. M. Stoller Corporation (Stoller) to perfom the study. In the course of its study Stoller reviewed and reported on performance standards programs
-4 proinul, gated in other states which cculd impact the fomulation of a program for SONGS-1. Stoller makes the following observation in the background of its report:
7 "In the past several years, there has been! increasing regulatory interest in the perfomance of large central. station generating units, both fossil and nuclear. This interest prenarily reflects the well-publicized increasing cost of construction, but as well the increased cost of operation, of such units. Improvements in availability and capacity factor performance of existing units can thus represent very material savings to'the ratepayers and to the owner utility, both in
. deferral of future system additions, and also for low incremental cost units, such as nuclear units, in reduced overall system generating costs.
The SONGS-1 study ordered by CPUC is consistent with the increasing efforts by util.ity regulators across the country in encouraging efforts to improve availability by the establishment of explicit standards of performance for large generating units. These programs incorporate some formulistic mechanism inteaded to be capable of simple interpretation and implementation, by which " good" performance of a unit on a utility system can be rewarded, or " poor" performance penalized. Such standard programs are seen as producing two potentially desirable effects:
, _ , . . , _ . . _ __,,. _ . . . . . _ - _ , _ . _ . ._ ._,.._.,,-_,._.m-- ,...___~ , .,
- 1. They can act as a further incentive to the utility owner to seek means to improve performance.
- 2. Such approaches may be preferable from an implementation standpoint to " reasonableness tests," or other retrospective judgments often reqeb ed for ratemaking purposes.
However, in considering such a program applied specificall.y to the SONGS-1 nuclear unit, Stoller determined that several important issues needed to be addressed are:
- 1. The potential exists that a program applied to a nuclear unit could encourage trade-offs which have adverse implications for the public health and safety.
- 2. The potential similarly exists that such a program could encourage trade-offs between actions designed to maximize the measured performance against which the financial rewards or penalties of the program are applied, at the expense of operating policies and actions which would be more cost-effective in the longer-term interest of the ratepayer.
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- 3. The SONGS-1 plant is one of the very oldest units in current operation and much of that total nuclear $ower operating experience data base is thus not properly applicable due to design differences between SONGS-1 and the later units. In addition, due to its comparatively advanced age, one must take into account the potential impact of a'ging or " wear-out" in future SONGS-1 perfonnance.
4 Most important, and as already alluded to, the very extensive plant modifications expected to result from the NRC-required SEP program can be expected to result, as a minimum, in a series of extended planned outages over the next several years. Any standards program, to be effective and practical, must account for such planned outages."EI As part of its study, Stoller specifically assessed the emphasis by Edison management on safety versus kilowatt-hour production, especially in gray areas where NRC regulations do not specifically mandate operator action. Stoller points out that it deemed the matter of potential conflict between safety and production to be important enough to be worth exploring with the NRC directly.
5/ Stoller, pp. 1-3 through I-5.
Stoller's meeting with NRR management in May 1983 is reviewed in its l report. Although the Stoller study was specifically addressed to SONGS-1, the CPUC has not placed any performance incentive requirements on that unit since it has been inactive for the past two years. Reactivation of the unit is dependent on NRC-required j upgrades including those related to seismic capability. The Stoller findings were used as background for the performance incentives imposed 'by the CPUC on SONGS-2 (see individual State sumary below) in September 1983. The CPUC staff says that it is reasonable to assume that similar perfonnance incentives will be considered for SONGS-3 which may begin operation in Spring 1984 InchubdinStoller'sfindingsandconclusionsarecertainpoints particularly relevant to NRC requirements for nuclear plants:
o "There are no indications that the other state incentive programs studied have distorted the priority relative to nuclear safety, nor any evidence of special concern by NRC for those units included in such programs."
o "It is desirable to avoid sharp thresholds in financial impacts; that is, to smooth the financial impact of a particular decision at a particular point in time. One step in that direction may be to average the performance over longer periods; programs where the measurement is made on very short intervals; e.g., six months, are prone to put undue pressure on an operating decision."
o " Broadening the base of the formula, e.g., to include the
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performance of more than one unit on the system, either other nuclear units, or some combination of nuclear and fossil, may also serve to diminish the financial
- importance; and thus, the pressure on the operator of a singular operating division. This would also help to avoid undue managewent attention to a specific unit."
o "It is probably useful to establish a " null zone" to accommodate variations in performance, for any number of random causes, which inevitably occur in the operation'of a unit from year-to-year. This concept way be 3
particularly applicable to nuclear units, for which the statistical experience base is still relatively modest, and quite nonuniform; and therefore, performance predictions are not founded on an especially valid statistical base. However, if such a tolerance band is incorporated in the formulas, it would still be preferable to smooth the financial impact as one departs the zone, rather than have major step changes."
o "The principal administrative burden is associated with accommodating events which are outside the control of -the utility, notably NRC backfit requirements. Prior to 1976, for example, the average impact on capacity factor of NRC backfit requirements was less than 1%. In the latter half of the 1970's, this increased dramatically so that by 1979 p - ,, , , , - , - , -n.- , . - - -- ----.,,n- , , _ - .
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the annual losses in capacity factor due to NRC backfit requirements on pressurized water reactor units-had reached over 16%. In the last two years it has been decreasing, again getting down to about 7% in 1981 and 1982."5/
Summary of Findings - EEI (Quadrex)
Although the EEI report is a draft, its contents are considered accurate and close to completion. The final report is expected out in early 1984. EEI says its draft is suitable for review and quotation in limited distribution reports such as this but requests that it should not receive wide distribution or quotation. The EEI study, like the NARUC study, is largely survey material but the individual State summaries are more in-depth than those reported by NARUC.
EEI reports that the most popular incentive program objectives are to reduce fuel and/or purchased power costs, and to improve power plant productivity or efficiency. Most of the programs are linked to fuel and purchased power costs. Capacity factors, availability levels, and heat rates are the most frequently used criteria to measure performance. Most of the programs rely on combinations of multiple criteria to reasure perfo-mance rather than one single
~
b/ Stoller, pp. 1-22 through I-24
9 l In measure in order to avoid distortions or unintended outcomes. ,
some cases, narrowly defined operating measures have led ter increases in the cost of service rather than greater efficiency.
Just as most of the programs rely on multiple measures of perfomance, most also provide both rewards and penalties rather than a singular reward or penalty avoidance. Rewards and penalties for almost all of the programs are made through adjustments in allowable fuel and purchased power costs or to the company's return on equity.
Individual State Incentive Programs (Operating Performance)
The NARUC and EEI surveys identify eleven States that have operating performance incentives specifically aimed at nuclear plants. Each of these is individually sumarized below using infonnation drawn from Stoller, EEI and NARUC. Conclusions reported herein regarding the effectiveness of the incentives and their relationship to efficient operation and to safety are these of the three referenced studies. In addition to the programs designed for nuclear plants, twelve States have performance incentives applicable to all or most generating units. The following table identifies key elements of the operating performance incentives applicable specifically to nuclear plants. Construction incentives are reviewed separately later.
Sumary of State Operating Performance Standards Programs (Nuclear) (Notcs on following page.) ,
Nuclear Utility State / Focus Type Reward Penalty Rewards /
Plant Start of of of Range Range Penalties Program Program Target To Date Arkansas' Arkansas Arkansas Fuel CF Between CF> 72.9% (#1) CF< 72.9% '(#1) -$44 M Nuclear One Power & Light 1980 Adjustment Scheduled CF> 71.5% (#2) CF< 71.5% (#2) (3 years)
Units 1 & 2 Clause Refueling San Onofre Sou. Cal. Ed/ Calif. Fuel CF CF> 80% CF< 55% N. Avail.
NGS Unit 2 SDG&E 1983 Adjustment Clause Fort St. Vrain Pub. Serv. Colo. Rate Base / CF Between Colorado 1981 Rate of Return Scheduled None CF< 50% None Outages Millstone Conn. L&P/ Conn. Fuel CF> 70% CF< 55%
Conn. Yankee Hartford Elec. 1979 Adjustment CF (1). (1). None Clause Crystal River Fla. Power Corp. Fla. Return on FPC:-$40K St. Lucie 182 Fla. P&L 1981 Equity EA & HR (2). (2). FP&L:+$1.7M Turkey Point M 3$Y Calvert Cliffs 182 Br&E Md. Replacement 1978 Fuel Cost EA None Judgment (3).
Pilgrim Boston Edison Mass. Fuel AF, EA, CF, Yankee-Rowe Yankee Atomic 1981 Charge HR & FOR None (4). None Big Rock Point Consumers Pwr. Mich. Return on ECAR (5) (5) +$14M Palisades 1978 Equity Availability 9
Brunswick 182 Carolina P&L N. Carolina Return (6). (6). (6). (7).
McGuire Duke Power Co. 1978 on Equity Surry, N. Anna VEPC0 .
Davis Besse Toledo Edison Ohio Fuel C'ost Mce> 1 Mce 1 Not
- 1981 Cost Effectiveness (8) (8) Deteminable Surry 1&2 VEPC0 Va. Return on CF Judgment Judgment (9).
North Anna 182 1982 Equity
Abbreviations in Table:
AF = Availability Factor M = Million
- EA = Equivalent Availability K = Thousand CF - Capacity Factor ECAR = East Central Area HR = Heat Rate Reliability FOR = Forced Outage Rate Coordination Agreement Footnotes:
(1) The Connecticut Program has implicit reward and penal.ty features in addition to explicit penalty for perforvence below 55% weighted average nuclear CF. There is an interest penalty for performance between 55% and 70% and an interest reward for perforwence greater than 70%. Since weighted average nuclear CF has not been below 55%,,no penalties have been levied. Amount of interest penalties or rewards are not tracked by Connecticut Division of Public Utilities Control and affected utilities.
(2) Reward / penalty is proportional to the ratio of actual deviation from performance targets to predicted. maximum deviation.
. (3) BG&E has had 25% of replacement fuel cost and 75% of replacement fuel cost disallowed for two different Calvert Cliffs outages.
Associated dollar values of the penalties are not known.
(4) Target values of AF, EA, CF, HR, and FOR are set for each plant covered in Massachusett's program (Specified by Mass. DPU).
(5) The reward and penalty range are ECAR availability plus periodic factor greater than 89% and less than 83.01% respectively.
(6) No. Carolina has not set targets by which performance is judged.
(7) In a 1981 rate case, the No. Carolina Utilities Commission reduced VEPC0's return on equity from 15% to 10%. In a 1982 rate case, the Commission reduced CP&L's return on equity by 1%.
(8) Mce is a complex formula used to measure cost-effectiveness. It involves a number of efficiency measurements including fuel u;ilization, fuel procurement, sales pricing policy, and purchased power policy.
(9) In a 1981 rate case, VEPCO's return on equity was reduced to low end of authorized range. A i% reduction in return on equity costs VEPC0 approximately $14 million annually. In a 1979 fuel proceeding, VEPC0 was ordered to refund to its customers the net replacement energy costs ($3.3 million) associated with a Surry Unit 2 outage.
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Arkansas Affected Nuclear Plant and Utility: Arkansas Nuclear One Units 1 & 2, Arkansas Power and Light In June 1980 the Arkansas PSC established an incentive to protect ratepayers from the replacement power costs which could result from excessive outages of Arkansas Nuclear One Units 1 and 2. The practical results of the program are as follows:
- 1. When a nuclear unit is down for refueling, all replacement power costs are passed to the consumer.
- 2. When a nuclear unit is not refueling and has not been shut down for more than 30 consecutive days, AP&L is penalized all replacement power cost attributable to the nuclear unit's operating below its target capacity factor and keeps any fuel savings attributable to operating above target. Target capacity factors are 72.923% for Unit I and 71.55% for Unit 2.
- 3. For the thirty-first and any subsequent days of any continuous outage, AP&L is penalized 10% of any replacement power costs associated with that outage.
- 4. Although not explicitly stated in any documentation, the Arkansas PSC treats any refueling outage beyo,nd a specified duration as being an outage subject to (2) and (3) above. The specified refueling outage durations are 10 weeks for Unit 1 and 8 weeks for Unit 2.
Experience with the Arkansas program is reported to be as follows:
- 1. Capacity factor targets between refueling outages and the outage duration targets were set on the basis of experience prior to the TMI accident. Average capacity factors for similar units to ANO Unit 1 and 2 in recent years have been
- worse than the Arkansas targets.
- 2. Each month's rewards and penalties are based on' average fossil fuel costs during that month. According to Stoller, since the average fossil fuel costs are lower when nuclear units ~ are not running, AP&L could end up with a net penalty even if both nuclear units ran on the average, exactly at the target capacity factors while experiencing the normally expected month-to-month variations.
- 3. If either unit refuels less frequently than implied (once every 18 months for Unit 1, and once every 12 months for Unit
- 2) that unit would have to exceed its target capacity factor between refuelings by some amount in order for AP&L to break even. Stoller provides calculations for such a situation (pp. IIC-7, 8).
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- 4. The Fuel Adjustment Clause Rider does not incorporate provisions for modifying unit performance to acc6'nt u for (a)
NRC-mandated outages or outage extensions, and (b) events occurring at other nuclear plants which require additional outage time for ANO units to perform inspections, tests and any necessary changes.
- 5. The Rider does not allow for reduced power output due to other factors beyond AP&L's control (e.g., reduced demand). In fact, there are times when it will not permit performance credit to ANO units when they are fully operational (i.e.,
when they provide part of their power output to the Middle South Utilities Power Pool because of reduced demand or availability of cheaper power for the Arkansas ratepayers).
- 6. The Rider has the potential to guide AP&L in a direction which is not necessarily in the best interests of the ratepayer.
Possible concerns include the following:
o Refueling outage could be scheduled during peak summer months so that if any extension occurs, it takes place during the fall months. Thus, penalties would be reduced and AP&L would absorb a reduced loss under the fuel adjustment calculation.
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o Extending outages rather than return to service and risk a later outage which restarts the Fonnula I* clock. (See Stoller, P. IIc-5 for details of formulas.)
o Shutdown of the units rather than coastdown to conserve fuel. .
- 7. There are no maximum limits established to protect the utility from financial jeopardy in the case of extended outages.
As a result of this Fuel Adjustment Clause Rider, AP&L has received rewards and penalties in a net penalty of about $44 million in the three years of its implementation (Note: AP&L's net income in 1982 was about
~$107million). AP&L has pointed out the impact of a number of factors such as the seven noted above to substantiate its case that the Rider is unfair, and is in fact a penalty-only provision. It was also stated that the Commission person responsible for developing the Rider did not anticipate its working this way other than that provided by reducing the penalty to 10% of the replacement power costs for nonrefueling outages which extend beyond 30 days. AP&L feels that a reasonable incentive program applied to nuclear units requires some mechanism to account for the changing NRC impact upon nuclear unit performance. The magnitude of the NRC's impact can generally be assessed prior to the outage.
Stoller reports that the Arkansas PSC is considering certain revisions to the Rider to moderate its impact on AP&L. One would be the establishment of a null zone in the capacity factor target of + 2.5% _
about the target. No rewards or penalties would be assessed for ANO performance within this zone. In addition, the target capacity factor would " float" to either end of the band so that the target would be equal to the upper end of the band if performance was better than CF plus 2.5%, and it would take on the lower end of the band (i.e., CF minus 2.5%) if performance was worse than that value. Another revision being considered would allow AP&L to keep all replacement power cost savings if a nuclear unit operated above its overall capacity factor goal. If a nuclear unit operated below its goal, penalties would normally be limited to 10% of the replacement power costs for all days by which the total of unplanned outage days and extra (beyond the 8 or 10 week target) refueling outage days exceed 30. AP&L's reward-penalty results for the past three years recalculated using the above two revisions would be a net penalty of about $4 million instead of $44 million. The maximum monthly loss of $15 million would be reduced to about $5 million.
With reference to the Arkansas procedures, Stoller concluded that "it is extremely difficult to write a provision that automatically covers all eventualities in a fair manner, thereby precluding the need for competent PSC assessment of extenuating circumstances faced by the utility."
California Affected Nuclear Plant and Utilities: SONGS 2 - Southern California Edison, San Diego Gas & Electric In its September 7, 1983 decision, the California PUC softened the reward / penalty provisions that its staff had suggested in the proceeding. The PUC provided that additional fuel costs resulting from SONGS-2 capacity factor below 55% and fuel cost savings for capacity factor above 80% would be shared equally (50/50) between the company (stockholders) and ratepayers. The PVC staff had recommended that additional costs and savings above and below a 65% capacity factor should accrue entirely to the company. The California PUC thought that standard was too harsh, particularly in 'the relatively untested area of incentives. The Commission emphasized the utility's obligation to adhere to all NRC rules and regulations and stated that the record of its proceedings included examples of other jurisdictions that have instituted nuclear performance standards without apparent detriment to nuclear safety. The PUC agreed with its steff that a performance standard such as a target capacity factor would not compromise safe plant operation. [he PUC also recognized that nuclear plant outages may be due solely to factors outside the utility's control and that it would be flexible toward considering the causes and effects of such events on a case-by-case basis.
~l 19 Colorado Affected Nuclear Plant and Utility: Ft. St. Vrain, Public Service Company of Colorado s
In December 1980, the Colorado Public Utilities Commission ordered that Public Service Company of Colorado would have to refund the rate base return on common equity on Fort St. Vrain to the ratepayers if this plant does not achieve a 50% capacity factor performance in the test year. The 50% capacity factor is based upon 200 MW net capacity, exclusive of scheduled downtime for maintenance and refueling. This order was modified in January 1981 wherein the Commission defined the test year as the first full year after the 1981 refueling or no later than the end of the calendar year 1982. The Commission also determined the annual rate of return on Fort St. Vrain to be 10.19% of the net jurisdictional investment which is equivalent to $t107,000 per month.
Public Service Company of Colorado was ordered to escrow this amount or, a monthly basis separately from the general funds of the Company for ultimate disposition.
Connecticut Affected Nuclear Plants and Utilities: Millstone and Connecticut Yankee
- Connecticut Light & Power Co., Hartford Electric Light Co.
The Connecticut Division of Public Utility Control established the Generation Utilization Adjustment Clause (GUAC) for Millstone and
20 Connecticut Yankee. The program provides a mechanism to equitably share the risk of nuclear outages. Fuel expenses are set in base rates by applying the annual anticipated nuclear plant capacity factor (NCF).
This capacity factor is used in the computation of the GUAC fomula which considers the fuel cost differential between fossil and nuclear generation. If the actual weighted average nuclear capacity exceeds the NCF target, customers are credited with a part of the avoided replacement fossil fuel costs. If the capacity factor falls below 55 percent, replacement fuel costs will be borne by the utility. If the nuclear capacity is between the target and 55 percent, customers share in the cost of replacement fuel according to the formula. The DPUC staff has established the NCF target at 70 percent by comparing the histor'ical perfcrma'nce of nuclear units under its control with the historical performance of all nuclear units, practices of other regulatory agencies and utilities, abstract productivity models, and statistical analyses.
The major incentive for the utility is to avoid absorbing replacement fuel costs when capacity is below 55 percent. Since performance between 55 percent and the NCF target results in sharing costs between the utility and customers and superior performance results in customers being credited with avoided replacement fuel costs, the underlying incentive may be to achieve average performance.
21 Florida Affected Nuclear Plants and Utilities: Crystal River Unit 3 - Florida 3 +
Power Corp.; Turkey Point Units E &#, St. Lucie Units 1 & 2 - Florida Power and Light Co.
In September 1980, the Florida Public Service Comission incorporated an explicit incentive factor, the Generating Perfonnance Incentive Factor (GPIF), within the Fuel and Purchased Power Recovery Clause. The
- purpose of the GPIF is to provide an incentive to utilities to achieve efficient operation of base load generating units. The GPIF targets, actual performance, and incentive are detennined on a semi-annual basis.
The GPIF program is applied to a utility's largest generating plants that contribute 80% or more of the energy generated.
The incentive program goal is to minimize fuel and purchased power costs. The GPIF uses complex formulas to link the rate of return allowed on comon equity to average heat rates and equivalent availability of power generating units. Targets are set for average heat rates and equivalent availability, and fuel expenses are estimated by running several computer simulations of the utility system economic dispatch. Additio 21 computer runs provide estimates of fuel cost savings associated with operations at maximum, minimum, and target -
levels. Rewards or penalties are determined by comparing actual operating values with targets set for equivalent availability and average. heat rate. The comission staff worked with the utility companies to design the program criteria and measures. Targets are ' set
by fomula for equivalent availability and average heat rates.
Equivalent availability targets are set using the historica1 performance record for each unit adjusted to reflect maintenance improvements.
Average heat rate targets are set by using monthly data weighted according to economic dispatch with adjustments made for unit modifications, fuel changes, and environmental regulations.
Above average perfomance for both equivalent availability and average heat rate results in a reward, and below average perfomance results in a penalty. Rewards and penalties may be as much as 0.25 percent of return on common equity. The singular objective of lowering fuel costs as a function of performance targets may result in the company neglecting other areas of utility crerations. At issue is whether the program minimizes the overall cost of operation. Finally, the reporting, administrative and technical analysis activities for the annual hearingc involve substantial costs and commitment of manpower.
Florida PSC personnel report that the GPIF was meeting its objectives:
increased efficient operation of base load plants. The following decreases in system overall heat rates since implementation of the GPIF were noted: approximately 130 BTU /Kwh at both Florida Power & Light and Gulf. Power, and 160 BTU /Kwh at Tampa Electric. A decline in planned outage durations also was noted but no figures were given.
The two utilities with nuclear units, FP&L and FPC, have received both rewards and penalties during the first 4 perfomance periods under GPIF.
i FP&L has received 3 rewards totaling $1.9 million and 1 penalty of $180 I
thousand for a net reward of $1.72 million. FPC has received 2 rewards ,
totaling $650 thousand and 2 penalties totaling $690 thousand for a net penalty of $40 thousand. The PSC staff noted that Crystal River 3 (an 800 MW PWR) accounted for approximately 50% of FPC's rewards and penal ties . The PSC staff reported one problem with the GPIF; there is some disagreement between the PSC staff and utilities regarding targets, reasonably attainable performance ranges, and adjustments when judgment has been applied in determining these parameters. The PSC staff has required changes in approximately 50% of the performance values it has reviewed.
The response from FP&L and FPC to the GPIF were nearly identical. Both utilities reported that they always strive for high performance and implementation of the GPIF did not always result in any increased emphasis on their efforts. FP&L mentioned that they had a performance improvement program in place when the GPIF went into effect. FP&L and FPC both reported that possible safety impacts were not an issue during hearings on development of the GPIF. Further, they said there has been no-NRC interest in the GPIF either during its development phase or the implementation phase. Both utilities reported that the GPIF has not impacted (i.e., neither facilitated nor complicated) the rate hearing and fuel charge hearing processes. FPC reports that the GPIF has increaed the workload of the Plant Performance Group due to data tracking, collection and reporting requirements.
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{
_24 Maryland Affected Nuclear Plant and Utility: Calvert Cliffs Units 1 and 2, Baltimore Gas and Electric Under a 1978 Marylan,i law, fuel cost adjustment and determinations were removed from base rat'e hearings and a separate fuel rate adjustment mechanism was established. The intent of the law was to eliminate electric bills which fluctuated wildly from month to month due to the automatic fuel cost pass through. When a utility's monthly cost of fuel exceeds or falls below the cost fixed in the last fuel rate adjustment hearing by more than 5%, the utility notifies the Maryland Public Service Commission which must hold a new fuel rate adjustment hearing.
By law, the PSC must determine if the generating units performed at reasonable levels when evaluating the fuel rate adjustment (Note: Other factors such as fuel purchases and generation mix are also evaluated).
In addition, if any party brings evidence that power plant outages were caused by " improper actions: or " imprudent management," the PSC must evaluate the outage. If the PSC determines that one or more generating units did not perform at reasonable levels and/or an outage was caused by improper actions or imprudent management, then the PSC can reduce the utility's proposed fuel rate adjustment. Originally, there were no guidelines or standards for defining terms such as reasonable level of performance, improper actions and imprudent management.
The PSC has set guidelines for evaluating the performance of generating plants. A generating unit is considered to have performed at a
reasonable level if its equivalent availability far. tor (EAF) for the most recent 12-month period exceeds the higher of: 1) its average EAF over the last 3 years, or 2) the 10-year NERC average EAF for plants of the same class. No guidelines or standard have been set to assist in
.. defining improper actions or imprudent management related to outages.
The Public Service Commission and the affected utilities are dissatisfied with the Maryland program. Both parties realize that the program is penalty oriented; there are no rewards for above average or superior performance. In particular, investigations of plant outages and resultant penalties show the major weakness of the program. Some examples are discussed below.
In a 1982 fuel rate adjustment case, Baltimore Gas & Electric applied for an increase in fuel costs. With regard to the Calvert Cliffs nuclear plant, the PSC determined that this plant operated at a reasonable level. In fact, the EAF for the plant in the preceding 12 months was higher than for the previous 3 years and it was higher than the NERC 10-year average for the same class of plant. However, the Office of the People's Council (a state government organization) intervened in the hearings. The Council maintained that a 17-day outage starting in late 1980 was the result of improper utility action.
Evidently, a nut from the turbine hoisting equipment had gotten loose, fell into the turbine during maintenance and had caused damage during turbine operation. lne hearing examiner recommended that BG&E be disallowed 50% of the replacement fuel cost for the outage. The PSC in its Order disallowed 25% of the replacement fuel cost.
In another fuel rate adjustment case, the PSC again determined that BG&E had operated the Calvert Cl.iffs station at reasonable perfo*rmance levels. Once more the Office of the People's Council intervened and claimed that a July 1981 outage was due to improper utility actions. In this case, Unit 1 experience salt water intrusion into the coolant during startup. The PSC disallowed 75% of the replacement fuel cost for this outage.
The PSC reports that at practically every fuel rate adjustment hearing, even those where actual fuel costs are more than 5% below the current level, the Office of the People's Council intervenes and claims that one or more outages are the result of improper utility actions' or imprudent management. As a result of the two Orders for the BG&E fuel adjustment rate cases, BG&E has gone to court in an attempt to have the outage evaluation nullified. Independent of the BG&E legal action, the PSC is considering modifications to the standard that would have the following features: (1) definite standards by which plant performance could be judged, 2) a reward system as well as penalties, and 3) a decreased emphasis on, plant outages in determining fuel rate adjustments.
Massachusetts Affected Nuclear Plants and Utilities: Pilgrim, Boston Edison; Yankee-Rowe, Yankee Atomic In August 1981 the Massachusetts legislature decided to include evaluation of power plant performance in the fuel charge procedurt The
amendment provided for establishment and operation of a fuel charge monitoring bureau to administer and enforce the fuel charge procedure.
At least once a year, affected utilities file a proposed performance program with the Department of Public Utilities (i.e., the Fuel Charge Bureau,MassachusettsDPU). The utility performance program requires evaluation of the following parameters as a minimum, on a unit-by-unit basis: availability; equivalent availability; capacity factor; forced outage rate; and heat rate.
The affected utilities have to file performance statistics on a monthly basis. Any monthly variance has to be explained at the next fuel charge hearing and may become the basis for a determination of " unreasonable or imprudent performance." In fuel charge hearings, if the Department determines that a utility has been unreasonable or imprudent with regard to fuel use, the Department can deduct from the fuel charge proposed for the next period an amount that the Department deems proper as reflective of the fuel costs directly attributable to the " unreasonable or imprudent performance." The statute does not contain any provision for rewards if performance exceeds the targets.
The utilities affected by the performance program are not enthusiastic about it. First, the program has provisions for penalties and none for rewards. The program requires a large data collection, assessment, and reporting effort. In addition, the required heat rate audits are supposed to involve ASME Power Code Testing, which is time consuming and 1
costly, and their value in meeting the acts of 1981 is being challenged by the utilities. .
Michigan -
Affected Nuclear Plants and Utility: Big Rock Point, Palisades -
Consumers Power In 1978, the Michigan Public Service Comission instituted the Availability Incentive Provision for the Detroit Edison Company and Consumers Power Company. The Availability Incentive Provision was ordered'to encourage the two utilities to improve the availability of their generating plants. Both utilities had experienced declining system availability, and reached an all time low of approximately 72% in the mid-1970's.
The performance standard incorporated in the original orders was system average availability using the East Central Area Reliability Coordination Agreement (ECAR) definition. ECAR availability for a f single generating unit is defined as unit operating hours plus unit i
hours available but not operated divided by total hours in the period.
The system average is determined by suming individual unit ECAR -
availabilities weighted by the units' capacity ratings. The performance standard was modified by the PSC in August 1980. The new standard incorporates the following changes: 1) a periodic factor was identified to account for periodic, scheduled maintenance, 2) the neutral or null f
zone was reduced from 10% to 6%, and 3) the system availability scales l
i i
k
were " fine-tuned" and 11 ranges were created jnstead of the original 3 ranges: variation over the period of the periodic factor 9' percentage points (or .09) for Consumers Power accounts for scheduled outages and was established based on an analysis of a 10-year history and a 10-year forward projection of scheduled outages for the utility.
Utility performance, as measured by system average availability plus periodic factor is tied to incentives by a scale which equates perfonnance to an adjustment of return on equity. The target of availability plus periodic factor is equivalent to a target on unplanned outage factor (i.e., random outage factor) since the sum of availability plus planned outage factor plus unphnned outage factor equals one. The current scale for Consumers hwer is shown in the following table. Note that there is a null zone in which no penalty or reward is levied. The maximum reward is a 1/2% increase in return on equity and the maximum penalty is a 1/4% decrease.
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.. s N ' .-
CONSUMERS POWER COMPANY AVAILABILITY INCENTIVE PROVISION I 4 System Availability (ECAR) EquityR$ turn, Plus Periodic5 Factor Incntive
. s 100% -
9,4.01% +.50% ,
94.00% -
92.'6% 7 '+.40%
92.75% -
91.51% i +.30%
.91.50% -
90.26% +.20%
90.25% -
89.01% +.10%
89.00% -
83.01% -
83.00% -
82.01% .05%
82.00% - 81.01% .10%
81.00% -
80.01% .15%
80.00% -
79.01% .20%
79.00% - .25%
The PSC staff and Consumers Power have expressed their satisfaction with the Availability Incentive Provision. Consumers Power had impressive rewards under the Provision. It has received two rewards in four years for a gain of approximately $14 million. This performance improvement also meant considerable savings to their ratepayers.
Cognizant utility personnel stated that Consumers Power was aware of the performance problems (e.g., high random outage factor, low availability) occurring in the 1974-1976 time frame, and that steps were being taken to correct problems and improve perfonnance before the Availability Incentive Provisfon was implemented. However, the utility felt that the
provision provided additional focus on availability within ,the company,-
'provided the funding necessary to obtain improvements (e.g., production maintenance expenses, base rate), and may have accelerated s implementation of some improvement actions.
Consumers Power reported that there was no overt interest by the NRC in the Availability Incentive Provision and no additional NRC interaction as a result of the Provision. The issue of possible safety impacts did not arise. Consumers Power emphasized: 1) the need for pre-established ground rules for allocating NRC-mandated outages to the periodic factor category rather than the random factor category, and 2) the need for a competent PSC staff, such as in Michigan, to make informed judgments about NRC-required actions and other factors impacting upon those items which should be included as planned outages. This mechanism can accommodate factors beyond the utility's control.
Ncrth Carolina Affected Nuclear Plants and Utilities: Brunswick 1 & 2 - Carolina Power and Light; McGuire 1 and 2 - Duke Power Co.; Surry 1 and 2, North Anna 1 & 2 - VEPC0 North Carolina currently does not have a formal performance standard program based upon a North Carolina Utilities Commission Order or a legislative act. However, the Commission does periodically review the performance of utility power plants in both fuel adjustment hearings and
general rate case proceedings and, in the past, has levied penalties based on its assessment of poor performance.
Since 1978, the North Carolina Utilities Connissicn has required electric utilities to file detailed performance data on nuclear and baseload fossil-fired plants on a monthly basis. The performance reports include' the following information: outage data, including cause, duration and corrective actions taken; actual generation by each unit; and lost generation by type of outage (i.e., full, partial, scheduled, orforced).
The Commission considers power plant perfomance in general rate case hearings and has levied penalties for poor plant perfomance. When a utility files an application for a general rate increase, the Public Staff, acting as a consumer advocate, reviews the perfomance of the utility's power plants. This review can include a detailed investigation of engineering, operations, maintenance, and management performance. If the Public Staff finds that fuel costs were excessive due to poor plant perfomance, the Staff can recomend to the Comission that the utility's return on equity be reduced. The utility has the opportunity to defend its plant performance in the rate case hearings.
The Comission then makes a judgment as to the utility rate of return.
There are no defined standards by which power plant perfomance is judged.
The Comission adopted a new general rate case procedure in June 1982.
The utility fuel cost chargeat.le to ratepayers is included in the
utility base rate. The fuel cost is based, in part, on various classes of power plants achieving specified perfomance levels. The capacity factor used to detemine allowable fuel costs for Duke Power's nuclear plants is 60%, and the capacity factor for Carolina Power and Light's nuclear plants is 52%. Within a year of a general rate case, the utility must have a fuel cost hearing. The Comission can disallow fuel costs, if in its judgment, plant performance has been substandard or poor due to utility imprudence. Again, no fomal standards of performance related to fuel cost hearings are in effect, and performance standards and incentive fomulas are being considered. ,
The affected utilities, which are all investor owned, are not satisfied with the current North Carolina system. The main reasons for their dissatisfaction are: 1) there are penalties only and 2) judgment plays a central role in a detemination of " poor performance" and in allocating penalties.
For exariple, in a 1981 decision on a VEPC0 general rate case, the Commission reduced VEPCO's authorized return on equity from the 15.5% to 10%. In December 1980, VEPC0 filed for a general rate increase. The Public Staff hired consultants to evaluate the following areas:
- 1) management practices in plant 0&M, 2) outages, reductions in power, and O&M practices and procedures, and 3) predicted fuel costs at higher power plant performance levels. The Public Staff's consultants presented testimony that showed poor plant performance due to various VEPC0 deficiencies. VEPC0 presented extensive testimony to rebut the consultants' testimony. However, the Commission sided with the Public
9
.. O Staff and held that VEPC0's fuel expenses were excessive due to poor plant performance. The return on equity was reduced as notcd above.
In a 1982 CP&L rate case, the Comission reduced the return on equity by 1%. The commission ruled that an outage at the Brunswick nuclear plant, caused by a turbine bearing failure, was the fault of CP&L.
Ohio A~ffected Nuclear Plant and Utility: Davis Besse - Toledo Edison The Ohio program is embodied in the 1981 Tariff M e , and 1982 Tariff Mce'*
Automatic fuel cost adjustments were eliminated in Ohio with Amended Substitute House Bill 21 which became effective July 2, 1980. This statute contains the Ohio PUC's purchased power cost policies which were originally promulgated in the now defunct 1976 fuel cost adjustment rules. The objective of these policies is to minimize the cost of electric service to customers by providing incentives to investor-owned utilities for minimizing fuel costs'.
The specific provisions of the statute were implemented in February 1981 and placed in the Ohio Administrative Code on September 1981. The original cost-effectiveness measure, known as 1981 Tariff Mce, measures the efficiency of fuel procurement and utilization practices of an electric utility and then converts the cost-effectiveness measure, Mce' into a fuel recovery factor. M is a complex formula used to measure ce .
cost-effectiveness. It involves a number of efficiency measurements
including fuel utilization, fuel procurement, sales pricing policy, and purchased power policy.
Toledo Edison reports that it has recovered somewhat less than $1 million in fuel costs under the cost-effectiveness measure system that otherwise would not have been collected under the old fuel cost adjustment clause. The cost-effectiveness measure and incentive program has not had any impact on power plant operations or enginee-ing. The Rate Department of Toledo Edison is almost solely involved with the program. There is practically no involvement by the Engineering and Operations Departments.
However, Toledo Edison stated that its 4 large coal units are in the top 20 units with respect to heat rate, capacity factor, and availability.
Davis-Besse performance has been hurt by TMI and generic problems (e.g.,
pumpseals). Any external pressure to improve Davis-Besse performance has come from the Ohio pVC during base rate hearings. For example, the Ohio PUC has suggested that Davis-Besse might be removed from the rate base if performance did not improve. Toledo Edison reports that there has been no discernible concern on the part of the NRC with regard to the Ohio performance standards program.
\
\
Virginia Affected Nuclear Plants and Utility: Surry 1 & 2, North Anna 1 & 2 -
VEPC0 A VEPC0 rate application settlement establishes a performance incentive program by which rate of return (and therefore, rates) would be tied to generating unit performance based on indices such as equivalent availability and heat rates. Targets for Surry and North Anna units are derived from the two-year average capacity factors of all nuclear units built by the same manufacturer. Adjustments to the two-year averages are made to compensate for improvenents in reliability resulting from major overhauls of the nuclear units.
The fuel recovery clause is based on a fuel price index and generating performance criteria measured by equivalent availability and unit heat rates. First, the 13-month average procured fuel price is checked against a fuel price index. The index compares the cost per BTU for various fuel types with costs for the mid-Atlantic and south-Atlantic regions of the country. Secor.d target ranges are set for equivalent availability and unit heat rates using a computer simulation of the economic dispatch of the utility's system. This enables the staff to derive an estimate of the fuel expense for a given value of equivalent availability. The resulting estimate is used to test the reasonableness of the utility's projected and actual fuel expenses.
- g. .
While there is no specific set of rewards or peqalties, the performance criteria affect regulatory decisions on fuel costs. At the annual fuel recovery clause hearing, the utility's fuel account for the previous 12 months is settled. If cost underrecovery is determined to be the result s
of poor performance because of factors within management's control, complete recovery may not be allowed. If actual performance is on target, the time lag for recovery is reduced.
Construction Performance Incentives EEI and NARUC identify two States that have construction performance incentives specifically applicable to nuclear plants. (Stoller concentrated on operating performance incentives.) They aim at controlling construction costs and/or expediting construction completion.
New Jersey Affected Nuclear Plant and Utility: Hope Creek 1 - Public Service Electric & Gas Co.
The Hope Creek program (which provides both penalties and rewards) objective is to control construction costs. Through negotiation between T
the New Jersey Board of Public Utilities and Public Service Electric &
Gas Co. (PSE&G) the target construction cost was set at $3.7 billion.
- The incentive program provides that PSE&G may recover from customers only 80 percent of costs that exceed the $3.7 billion target by up to 10
. percent. Should costs exceed this target by more than 10 percent,'the company may recover only 70 percent of costs above the 10 gercer.t threshold. If the plant cost is between $3.5 billion and $3.7 billion, all actual costs will be recoverd. If the cost is below $3.5 billion, the reward provision becomes operative and the company will recover actual costs plus 20 percent of the difference between $3.5 billion and the actual costs. Thus, the program's incentive is to complete construction at a cost below $3.5 billion to recoup the 20 percent reward, and to avoid penalties.resulting from cost overruns.
New York Affected Nuclear Plant and Utility: Nine Mile Point 2 - Niagara Mohawk Power Corp.
The Nine Mile Point 2 program is designed to control the power plant construction costs. It was instituted because of escalating construction costs and uncertainty of completion dates. The program keys on sharing revenue requirements growing out of cost overruns and underruns . A target cost of $4.6 billion was negotiated and set for the project by Niagara Mohawk and the New York Public Service Conmission; the utility will be rewarded for reducing that cost and penalized for exceeding it. The company will receive 20 percent of the savings if the final cost is under target and must absorb 20 percent of cost overruns.
Thus, the program's incentive is to share in the benefits by bringing the project in under the targeted amount, and to avoid absorbing 20 percent of cost overruns.
EEI reports that the Nine Mile Point 2 program was instituted well after construction began at a time when it was difficult to obtain accurate and unbiased construction cost estimates. The investment comunity has not been enthusiastic about the program because it is felt that the PSC may have given up authority to assure a reasonable return on invested capital.
,