ML20206T661

Incentive Regulation of Nuclear Power Plants by State Pucs, Updated Rept - Jul 1986. W/860929 Release Memo

ML20206T661
Person / Time
Issue date:	07/31/1986
From:	Peterson J NRC OFFICE OF STATE PROGRAMS (OSP)
To:
References
NUDOCS 8610070134
Download: ML20206T661 (65)

Text

- e INCENTIVE REGULATION OF NUCLEAR POWER PLANTS BY STATE PUBLIC UTILITY COMMISSIONS (PUCs)

UPDATED REPORT - JULY 1986 s

A REPORT PREPARED BY THE STAFF' .

OF THE U.S. NUCLEAR REGULATORY COMMISSION OFFICE OF STATE PROGRAMS s

Enclosures:

1. July 1986 Updated Report

2. Background Reference, January 1984 Report

3. & 4. Correspondence between NRC and a Licensee NRC Staff

Contact:

James C. Petersen, (301) 492-9883 U.S. NRC, Office of State Programs Mail Station AR-5037 Washington, DC 20555 I

jgj00ffjg4 860731 .

R6tOO70134 Pnp

cs v 6 - . a. .

ENCLOSURE 1 INCENTIVE REGULATION OF NUCLEAR POWER PLANTS BY STATE PUBLIC UTILITY COMMISSIONS July, 1986

~

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 December 31, 1985, " Incentive Regulation of Nuclear Generating Facilities by State Public Utility Commissions." The purpose of this report is to describe how specific nuclear plant performance incentives work and to provide background information for evaluation of incentives' possible safety effects. (The staff informed the Commission of this effort in SECY-85-260, July 26, 1985.) -This report does not attempt to reach conclusions about the possible safety effects of particular incentives or of performance incentives in general.

Since the December 1985 report, several incentive plans have been implemented and others have been revised by State public utility commissions (PUCs).I The newer incentives and the revisions are indicated in the summary and table of contents on pages four and five and are described in the individual plant reports beginning on page twelve.2 Material that is unchanged from the December 1985 report is repeated herein; reference to that report is no longer 1

I

! New and updated material (since the December 1985 report) in the individual plant reports herein is identified by vertical lines in the left column.

2 Additional incentive programs are in early stages of proposal in several States including Mississippi, New Jersey, and Pennsylvania. The staff is tracking these developments and will report new nuclear incentives in a

j. subsequent update of this report.

necessary. The staff's initial report on this subject, dated January 27, 1984, (Enclosure 2) provides additional background material and is

. cross-referenced from the individual plants in the current report. A summary chart of the incentives (with plants grouped by NRC Regicn) appears on pages six through eleven.

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. (Potential financial impacts are indicated where they have been calculated by the utility or the PUC.) 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 and State PUCs contacted for this survey seemed knowledgeable about performance incentives-applicable to the facilities. They indicated an awareness of potential financial impacts under the incentives.

e s . j l

l 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. Many of the utilities expressed particular sensitivity to possible penalties and a desire to avoid them and to earn rewards where possible.

It is intended that this report will be updated and distributed twice a year 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: (FTS:

492-9883); (Commercial: (301) 492-9883). Mailing address: U.S. Nuclear Regulatory Commission, Office of State Programs, Room AR-5037, Washington, DC 20555.

9 l

l

SUMMARY

AND TABLE OF CONTENTS Summary Chart of Incentive Programs by NRC Region ...... Page 6 State Facility ' Type of Incentive Status I Page Arizona ~ Palo Verde 1 Operating Same 12 Palo Verde 1, 2 & 3 Construction Revised 14' Arkansas Arkansas Nuclear 1 & 2 Operating Same 16 California Diablo Canyon 1 & 2 Operating New 18 San Onofre 2 & 3 Operating Revised 21 Colorado Fort St. Vrain Operating Revised 24 Connecticut Millstone 1, 2 & 3 Operating Revised 26 Connecticut Yankee Florida Crystal River 3 Operating Revised 28 St. Lucie 1 & 2 Turkey Point 3 & 4 St. Lucie 2 Operating Discontinued 31 I

Maryland Calvert Cliffs 1 & 2 Operating Revised 33 Massachusetts Pilgrim 1. Operating Revised 35 Michigan Fermi 2 Operating New 37 Palisades Operating New 39 Big Rock Point Operating Discontinued 42 '

Palisades New Jersey Hope Creek 1 Construction Revised 44 New Mexico Palo Verde 1 Operating Same 46 New York Nine Mile Point 2 Construction Revised 48 I

Status is indicated (a) for "New" incentive plans, i.e., those not included in the previous report of December 31, 1985; (b) for incentive plans 1 having substantially " Revised" provisions (or revised and additional l information) from the December 1985 report; and (c) for incentives that are substantially the "Same" as reported in December 1985. Two incentives have been discontinued.

w .<

~

SUMMARY

AND TABLE OF CONTENTS (Continued) l State Facility Type of Incentive Status Page North Carolina Brunswick 1 & 2 Operating Revised 50

. Robinson Oconee 1, 2 & 3 Catawba 1 McGuire 1 & 2 Surry 1 & 2 North Anna 1 & 2 Ohio Davis-Besse Operating Same 53 Oregon Trojan Operating Same 55 Virginia Surry 1 & 2 Operating Same 57 North Anna 1 & 2 Surry 1 & 2 Operating Revised 59 North Anna 1 & 2 FERC Surry 1 & 2 Operating Revised 51 North Anna 1 & 2 O

e b

e Summary of State Performance Incentive Programs (Nuclear) by NRC Region Nuclear Utility State / Status Measure of Type Recent Rewards / Comments Page No.,

Plant of Program Productivity Penalties Detail Report Region I Millstone 1, Conn. Light Conn. Capacity Penalty None to date Penalty for CF 26 2 and 3 & Power Co. Initiated , Factor less than 55%

Conn. Yankee 1979 Calvert Balto. G&E Md. Capacity Reward & N.A.-proposed PUC now reviews 33 Cliffs 1 & 2 Proposed Factor Penalty incent,ive individual plant outages Pilgrim Boston Mass. Availability & Penalty 1986-$3 million PUC closely scrutinizes 35 Edison Initiated Heat Rate penalty Pilgrim outages 1981 Hope Creek PSE8G N.J. Total Reward & See comments Penalty (est. $80-120 44 Atl. City Initiated Constr. Costs Penalty million) will accrue Elec. 1983 since costs already exceed cap Nine Mile.2 Niagara N.Y. Total Reward & See comments Penalty (est. $1.75 48 -

Mohawk, Constr. Costs Penalty et. al.

Initiated 1982 billion) will accrue since costs already exceed cap

e 4

Summary of State Performance Incentive Programs (Nuclear) by NRC Region, continued Nuclear Utility State / Status Measure of Type Recent Rewards / Comments Page No.,

Plant of Program Productivity Penalties Detail Report R:gion II Crystal Fla. Power Corp. Fla. Availability Reward & Winter '85 '86, Goal is minimize fuel 28 River 3 Initiated & Heat Rate Penalty $0.8 million and purchased power St.Lucie Fla. P&L Co. 1980 penalty to FPC costs 1&2 $2 million reward Turkey Pt. 3&4 to FPL St. Lucie 2 Fla. P&L Co. Fla. Capacity Factor Reward & '83 '84-$3.5 million Actual capacity factor 31 Discontinued Penalty reward' was 92.48 percent Brunswick. Carolina P&L N. Carolina Capacity Factor Reward'& CP&L '84-$13 million Goal is minimize fuel 50 1&2 Initiated Penalty penalty; Duke- allowed and purchased power Robinson 1982 rate of return was costs Oconee 1, 2, 3 Duke increased Catawba 1 McGuire 1 & 2 Surry 1 & 2 Vepco North Anna 1&2 Surry 1 & 2 Vepco Va. Fuel and Purchased Reward & Not quantified Last considered by PUC 57 North Anna'1 & 2 Initiated 1979 Power Costs Penalty in fall '85 6

O Sunenary of State Performance Incentive Programs (Nuclear).by NRC Region, continued Nuclear Utility State / Status Measure of Type Recent Rewards / Comments Page No.,

Plant of Program Productivity Penalties Detail Report Region II (continued)

Surry 1 & 2 Vepco Va. Capacity Factor Reward & Not quantified PUC increased allowed 59 North Anna 1 & 2 Infatiated 1979 Penalty See comments rate of return in 1986 Surry 1 & 2 Vepco FERC Capacity Factor Reward & '83- $141,000 May be discontinued 61 North Anna 1 & 2 Initiated 1983 Penalty reward e

9 e

4 S

e i

Summary of State Performance Incentive Programs (Nuclear) by NRC Region, continued Nuclear Utility State / Status Measure of Type Recent Rewards / Comments Page No.,

Plant of Program Productivity Penalties Detail Report R:gion III Fermi 2 Detroit Mich./ to be to be -

Phase-in rate 37 Edison PUC ordered determined determined order also requests proposals performance incentive proposals Palisades Consumers Mich./ to be to be -

Consumer Power proposes 39 Power Proposed determined determined several options Big Rock PT Consumers Mich./ Availability Reward & Rewards were Referendum ended 4?

Palisades Power Discontinued Penalty earned when incentive in effect Davis-Besse Toledo Edison, Ohio / Several Efficiency Reward & Not calculated - Subjective PUC 53 Cleve. Elec. Initiated Measures Penalty est. $1 million determination Illum. 1981 per year max.

l Sunwary of State Performance Incentive Programs (Nuclear) by NRC Region, continued Nuclear Utility State / Status Measure of Type Recent Rewards / Connents Page No.,

Plant of Program Productivity Penalties Detail

, Report RGgion IV Ark. Nuclear, Arkansas P&L Ark. CapacityFaclor Reward & $13 million cumulative Cumulative net 16 Units 1 & 2 Initiated 1980 Penalty '80 '85 net penalty penalty for

'80 '83 was $40 million

Fort St. Vrain Pub. Serv. Colo./ Capacity Factor Penalty $32 million potential Potential penalties 24 of Colo. Effectiveness penalty in '85 could have significant stayed by court effect on company l

h.

I 9

Sumary of State Performance Incentive Programs (Nuclear) by NRC Region, continued Nuclear Utility State / Status Heasure of Type Recent Rewards / Comments Page No.,

Plant of Program Productivity Penalties Detail Report R:gion V Diablo Canyon PG&E Calif. Capacity Factor Reward & $14 million reward Di.ablo may get 18 1 and 2 Initiated 1985 Penalty for '85 '86 -

Avoided Cost Recovery ratemaking' San Onofre Sou. Cal. Ed Calif. Capacity Factor Reward & None to date Utilities say penalties 21 2&3 SDG8E Initiated 1983 Penalty more likely than rewards Trojan Portland Oregon Fuel and Purchased Reward & '85-$15 million Penalty reduces utility 55 Gen. Elec. Initiated 1980 Power Costs Penalty Penalty earnings Palo Verde 1 Ariz. Pub. Arizona , Capacity Factor Reward & None to date Max. reward or penalty 12 Serv. Initiated 1984 Penalty is $8 million/yr.

Palo Verde Ariz. Pub. Arizona Total Constr. Penalty None to date; Expenditures may exceed 14 1,2,3 Serv. Initiated 1984 Costs see comments cap in '87 Palo Verde Pub. Serv. N.M. Excess Capacity Penalty None to date Aim to encourage off- 46 1 of N.M. Initiated 1984 system sales of excess capacity i

l

• l .

t

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 Type of Incentive: Reward and Penalty

Description:

The Arizona Corporatio,n Commission (ACC) has implemented operation and construction incentive plans for Palo 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

4 s .

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 replacement fuel costs. 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 frcm the penalty clause due to an " extraordinary event" will trigger an automatic hearing.

The operating incentive's effectiveness will be phased 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 $8 million maximum.

Possible rewards per year range from $0 minimum to $8 million maximum. No actual penalties or rewards have been given to date.

APS' 1985 total operating revenues were $1,175 million, total operating expenses were $868 million, and net income was $325 million.

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 the prudency of any excess cost will be on APS. For costs 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. -

h

APS estimates that it will cost $2.76 billion to complete its share of all -

three Palo Verde units. As of February 1986, APS had spent $2.47 billion on all three units, including $1.157 billion on PV-1 and common facilities. The cap's impact, if any, will not be felt until total expenditures exceed the cap which is not expected to occur until 1987 or later.

Potential Financial Impacts on Utility Under proposed new procedures being considered by the accounting profession, a -

$10 million imprudent plant investment in Palo Verde would be expensed immediately by the company and would therefore reduce net income by $10 million; likewise a $50 million imprudent investment in Palo Verde would reduce net income by $50 million.

However, under current accounting procedures, a disallowance would be amortized over a number of years. APS estimates that a $10 million imprudent plant investment in Palo Verde would reduce net income by'about Sl.2 million annually; likewise a $50 million imprudent investment in Palo Verde would reduce net income by about $5.9 million annually.

APS' 1985 total operating revenues were $1,175 million, total operating expenses were $868 million and net income was $325 million.

9 0

ARKANSAS Arkansas Nuclear One, Units 1 & 2 Operating Performance Incentive Regulatory Authority: Arkansas Public Service Commission O-Nuclear Plant: Arkansas Nuclear One, Units 1 and 2 Utility: Arkansas Power and Light Compar.y .

Status: Initiated June 1980 Measure of Productivity: Capacity Factor Type of Incentive: Reward and Penalty

Description:

(See Enclosure 2, pp. 13-17; additional information follows.)

The Arkansas Public Service Commission (PSC) has modified provisions of this performance 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 cumulativd outages beyond 30 days, AP&L is now penalized ten percent of replacement power costs. This is a I

favorable change to AP&L because, previously, the 90 percent penalty applied

. - . , . . - - - . _ - . , - , , . _ , . _ . _ . . , _ _ -_ _ -.-,, m --

, to the first 30 days of any new outage. As revised, the 90 percent penalty can be applied only once to the first cumulative 30 days of outage during the 78 week fuel cycle.

? Potential Financial Impacts on Utility I

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 fue..

The largest actual penalty (for both units combined) attributable to a single 4

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 1980 through 1985 was reduced to $13 million. Rewards were earned during the latter part of this period

that offset earlier penalties to an extent.

1 1,

i APaL's 1985 total operating revenues were $1,365 million, total operating expenses were $1,148 million, and net income was $110 million.

i t

i -

. , , . . _ - _ , ,_._-,.,....,.,..m _,_ m_ - - _-_.--.,_._-,_.,-._, , -

%,_-.,,y

.._-r _y,_% ._  %,wwy.,,,-,,,..,,7 .y,.--.w,,_y,--,

CALIFOR'NIA Diablo Canyon 1 and 2 Operating Performance Incentive Regulatory Authority: California Public Utilities Commission -

Nuclear Plant: Diablo Canyon Units 1 and 2 Utility: Pacific Gas and Electric Company Status: Initiated May 1985 for Unit 1, March 1986 for Unit 2 Measure of Productivity: Capacity Factor Type of Incentive: Reward and Penalty e

Description:

A July 1986 decision by the California PVC (CaPUC) established the first year of commercial operation as the calculation period for the incentive applicable to Unit 1. A CaPUC stipulation had previously established target capacity factors for both units based on average performance over the fuel cycle including an estimated two- to three-month refueling outage. This was an interim arrangement while CaPUC hearings continued in mid-1986. A dispute had arisen between PG&E and the CaPUC staff when the staff proposed increasing the length of the calculation period from one year to the length of the fuel cycle including the refueling cutage. This would have lowered the average capacity e

. o factor for the calculation period. Unit 1 achieved an 88 percent average capacity factor for its first year of comniercial operation ended in May 1986. The longer calculation period would have lowered the average capacity factor slightly below 80 percent for the first fuel cycle. This would put it in the deadband zone between 55 percent and 80. percent in which no rewards or penalties accrue. Average capacity factors above 80 percent result in a reward equal,to one-half the extra fuel costs saved. PG&E indicates that it is unlikely that Unit 1 would exceed the 80 percent target with the refueling outage included. Average capacity factors below 55 percent

. lead to a' penalty equal to one-half the resulting cost of replacement power.

An incentive program has also been applied to Unit 2 with the same range of capacity factors as Unit 1. But the timeframe for calculating the, Unit 2 capacity factor is the fuel cycle or the first two years of commercial operation, whichever is shorter. Unit 2 began commercial operation in March 1986.

PG&E has proposed in the ongoing CaPUC proceeding that the deadband be from 55 percent to 75 percent capacity factor and that the papacity factor be averaged

' over three fuel cycles for the purpose of determining penalties and rewards.

The CaPUC and PG&E are also considering an alternative ratemaking method for Diablo Canyon called " Avoided Cost Recovery," that provides an incentive to keep a plant on line. Under traditional ratemaking, all plant capital costs found to be prudently incurred would go into the utility's rate base. The utility would earn both a return on this investment and a return of the

investment through depreciation. Under Avoided Cost Recovery, Diablo Canyon would not go into rate base. The utility would be paid (through rates) for power actually generated by the plant based on the cost of replacement power that is avoided. If the plant failed to produce power, the utility would not be paid. This is seen as a strong incentive to avoid unplanned outages and to operate at a high level.

Potential Financial Impact on Utility Unit l's first year of commercial operation at 88 percent capacity factor resulted in a $14 million reward to PG&E, under the capacity factor incentive.

Potential penalties and rewards for future periods would depend largely on the cost of replacement power at the time.

PG&E's 1985 total operating revenues were $8,431 million, total operating expenses were $7,062 million, and net inco'me was $1,031 million.

4 d

e. .

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 Prode.tivity: 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 1 will be placed under a similar incentive program, the details of which are yet to be determined.

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 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 fael 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 regarding management prudence and the reasonableness of SONGS 2 and 3 construction expenditures.

The points raised by SCE in Enclosure 3 regard CaPUC staff claims that the company delayed construction completion and startup unnecessarily. SCE's position is that the time used to perform safety-related inspections and reviews and to complete licensing was reasonab.le. Although not part of formal.

incentive plans, the pending CaPUC actions may create economic incentives that

'could influence licensee decisionmaking. Hearings have been completed and a CaPUC decision is targeted for late-October 1986.

Potential Financial Impacts on Utilities Penalties and rewards under the capacity factor incentive are calculated based on replacement fuel cost and are on a fuel cycle basis (approximately 14-18 months), not on an annual basis. For capacity factors just below 55 percent, the penalty is $1.5 million per percent to SCE ($0.6 million per percent to .

SDG&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.

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.

'SCE's 1985 total operating revenues were $5,169 million, total operating expenses were $4,196 million, and net income was $774 mfilion. SDG&E's 1985 total operating revenues were $1,739 million, total operating expenses were

$1,451 million, and net income was $203 million.

1 ,

F C0'.0RADO 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 Denver District Court; disposition of incentive plan depends on outcome of appeals to Colorado Supreme Court.

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 O

maximum refund of $3.8 mi,llion 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. Ifthatimputedcost is less than the cost of power produced at Fort St. Vrain, then the difference is refunded to the ratepayers. .

t Potential Financial Impacts on Utility Possible penalties per year range from $ minimum to $45.6 million maximum.

No actual penalties have been paid to date because of the court's stay of effectiveness noted above. The maximum $45.6 million potential annual penalty would be a substantial percentage of the company's net income. Pending the outcome of court appeals, the company is recording the potential penalty as a liability on its balance sheet and as a charge against operating revenues. In 1985, the potential penalty recorded was $32 million.

This incentive plan makes no provision for rewards. Possible penalties compare to Public Service of Colorado's 1985 total operating revenues of

$1,747 million, total operating expenses of $1,562 million, and net income of

$111 million.

CONNECTICUT Millstone 1, 2, and 3 Conn. Yankee (Haddam Neck)

Operating Performance Incentive Regulatory Authority: Connecticut Public Utilities Control Authority Nuclear Plants: Millstone 1, 2, and 3 Connecticut Yankee (Haddam Nec&)

Utilities: Connecticut Light & Power Company (subsidiary of Northeast Utilities)

Status: Initiated June 1979 Measure of Productivity: Capacity Factor Type of Incentive: Penalty

Description:

(See Enclosure 2, pp 19-20; additional information follows.) As indicated in Enclosure 2, for actual composite nuclear capacity 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 1

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 PUC 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, 1986 was 75.4 percent. The utility's projected capacity factor for the 12 months ending December 31, 1986 is 76.0 percent.

CL&P's 1985 total operating revenues were $1,756 million, total operating expenses were $1,518 million and net income was $277 million.

i 9

, , - s-

. ~

.t i FLORIDA Crystal River 3 "'"

St. Lucie 1 & 2 Turkey Point 3 & 4 Operating Performance Incentive .

• > 4 Regulatory Authority: Florida Public Service Commission ,L N

Nuclear Plants: Crystal River 3 ^

~

St. Lucie 1 & 2 Turkey Point 3 & 4 -

s t P Utilities: Florida Power Corporation ,

Florida Power and Light Company '

s 4 A Status: Initiated September 1980 - '

J

~,

Heasure of Productivity: Equivalent Availability; Heat Rate Type of Incentive: Reward and Penalty

Description:

(See Enclosure 2, pp. 21-23.)

g.

e w

I

)

l Potential Financial Impacts on Utilities Florida Power Corporation Possible penalties and possible rewards (attributable to Crystal River Unit 3) both range from zero to $0.8 million every six months.

The company incurred the following rewards and penalties for the six-month periods indicated:

October '83 - March '84 + $680,000 April '84 - Sept '84 + $540,000 October '84 - March '85 + $720,000 April '85 - Sept '85 - $400,000 October '85 - March '86 - $795,000 The utility.jndicates that penalties beginning in the summer 1985 period were caused primarily by a refueling outage.from July 9, 1985 through August 20, 1985 and limited availability subsequent to that. A forced

outage from January 1986 through June 1986 contributed to the winter

'85 '86 penalty.

Florida Progress Corporation's 1985 total operating revenues were $1,653 million, total operating expenses were $1,207 million, and net income was $161 million. (Florida Power Corporation, the utility licensee, is the primary subsidiary of Florida Progress Corporation, a holding company.)

O' 'O 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 and net rewards attributable to each nuclear unit for the six-month calculation periods

• indicated.

(dollars in millions)

October '84- April '85- October '85-March '85 Sept. '85 March '86 Possible Actual Possible Actual Possible Actual Turkey Point 3 $1.3 - $1.2 $1.3 - $0.3 $1.3 - $1.1 1 Turkey Point 4 $1.1 - $1.1 t $1.1 + $0.6 $1.1 + $1.0 St. Lucie 1 $1.1 - $1.1 $1.2 + $1.0 $1.2 + $1.2 St. Lucie 2 . $1.0 - $0.9 $1.2 - $0.9 $1.2 + $1.2 FPL Group's 1985 total operating revenues were $4,349 million, total operating expenses were $3,692 millinn, and net income was $372 million. (Florida Power and Light Company, the utility licensee, is the major subsidairy of FPL Group, a holding company.)

I e

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.

e d 6 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.

St. Lucie 2's actual capacity factor for the one year that this incentive was effective was 92.48 percent. The total reward for the year was $3.48 million.,

Florida Power and Light's 1984 total operating revenues were $3,940 million, total operating expenses were $3,347 million, and net income was $352 million.

e

m MARYLAND Calvert Cliffs 1 & 2 Operating Performance Incentive Regulatory 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 Commission 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 2, pp. 24-26; additional information follows.')

The Maryland Public Service Commission policy of conducting reviews of individual unit outages continues as described in Enclosure 2. By statute, actual electric fuel costs are recoverable so long as the Maryland PSC finds that the company demonstrates, among other things, that it has maintained the productive capacity of its generating plants at a reasonable level. The PSC and liaryland's highest appellate Court have interpreted this as permitting a l subjective evaluation of each unplanned outage at the company's generating i

' plants to determine whether or not the company has implemented all reasonable and cost effective maintenance and operating control procedures appropriate for preventing the outage. Based upon this evaluation, the PSC has in the past, and could in the future, deny the company recovery of increased costs Incurred for supplying replacement energy during individual outages.at Calvert Cliffs or other Baltimore Gas and Electric Company (BG8E) plants.

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 outside the deadband are based on replacement power cost as measured by computer simulation. The maximum reward and penalty would be capped at 1 percent of the equity investment in covered units. It is expected that a formal incentive plan will replace the case-by-case reviews. PSC hearings on this subject are continuing and a decision date is uncertain.

Potential Financial Impacts on Utility: ,

Potential financial impacts have not yet been quantified. BG&E's 1985 total operating revenues were $1,755 million, total operating expenses were $1,431 million, and net income was $247 million.

MASSACHUSETTS Pilgrim Operating Performance 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 Type 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 (DPU) 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 (that are in effect through 1986) at the eighty-fifth percentile of the sample analyzed. If a plant misses a

performance goal there is an investigation of replacement power costs.

Whatever expenses are found to be imprudent are denied. Boston Edison indicates that the prudency of every lost nuclear megawatt is examined since Pilgrim is the most efficient plant on the system.

The program applies to all utilities even if a plant is located outside the 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 except up to the full amount gf 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: the first penalty in 1984 of about $4.5 million related to downtime for pipe replacement and chemical decontamination; and the second penalty in 1986 of about $3 million related to downtime because of valve misalignment and foreign material in the standby liquid control system.

Boston Edison's 1985 total operating revenues were $1,204 million, total operating expenses were $1,037 million, and net income was $94 million.

111CHIGAN Fermi 2 Operating Performance Incentive Regulatory Authority: Michigan Public Service Commission Nuclear Plant: Fermi 2 Utility: Detroit Edison Company Status: Rate increase granted April 1986 to phase-in Fermi-2 costs over five years; PSC also ordered that proposals be submitted for operating incentive; no filings yet received.

r Measure of Productivity: to be determined Type of Incentive: to be determined

Description:

The April 1, 1986 PSC rate order allows Fermi 2 construction costs to be phased-in to rate base over five years both to prevent rate shock to customers and to more closely match payment for Fermi 2's capacity with the dates that added capacity will be needed by Detroit Edison (DE) customers.

The PSC said only 20 percent of Fermi 2's output will be required by DE customers in the plant's first year of operation. Therefore, DE will be allowed to recover only 20 percent of Fermi 2's costs during the first year.

The balance is to be added in four more annual increments.

e G

The rate order also (1) disallowed $397 million of Fermi 2 construction costs as being imprudently spent; (2) directed that the phase-in (with accompanying rate increase) not begin until after the plant operates at 90 percent power for 100 consecutive hours; and (3) directed that performance standards and an incentive program be est.ablished for Fermi 2 in a separate proceeding. The PSC said that the incentive program's purpose is to ensure that DE customers do not pay plant expenses during any period in which- the plant is found to be operating at a suboptimum level. Filings on the incentive are expected but

~

not yet received by the PSC.

Potential Financial Impacts on the Utility:

The rate order reduces DE's allowed rate of return on common equity from 14.5 percent to 14.0 percent and provides for an annual rate increase of $404 million to be phased in over five years. DE had requested a rate increase of

$556 million.

The PSC also stated that DE's management can and should take severe cost-cut' ting measures and increase employee efficiency in order to bring its costs closer to,the average of other Michigan utilities and to earn its

authorized rate of return.

Potential financial impacts of the operating incentive can be estimated after

details of the incentive are known.

DE's 1985 total operating revenues were $2,788 million, total operating expenses were $2,174 million, and net income was $438 million.

t

a - --_ma-A a s. +4 ; ,

MICHIGAN Pa'lisades Operating Performance Incentive Regulatory Authority: Michigan Public Service Commission

! Nuclear Plant: Palisades Utility: Consumers Power Company i .

Status: Michigan PSC ordered that performance standards be established; utility,-PSC staff, and intervenors are preparing proposals Measure of Productivity: Multiple Parameters (one proposal)

Type of Incentive

Reward and Penalty (one proposal) '

Description:

The PSC ordered Consumers Power Company (CPC) to file a proposal for Palisades performance standards. This followed. substantial downtime in

. 1983 through 1984 and again in early 1985. CPC filed a proposal (discussed below) in March 1986. PSC staff and intervenors have not yet filed their proposals. Hearings are anticipated in the fall 1986.

l CPC's proposal contains four options. Option 1 (CPC's preference) expresses CPC's opinion that performance incentive regulation is not necessary because PSC regulation is already adequate for measuring management prudence.

4

' Option 2wouldapplystandardstothew%oleCPCsystem, including 14baseload units. If performance standards are to be instituted, CPC prefers Option 2 because performance would be averaged over a number of units. Performance problems at Palisades or another unit would be mitigated in the averaging process by system-wide performance. Option 3 provides for penalties and rewards to be determined by a composite, weighted average of a number of different Palisades performance parameters. These include measures of unit availability, safety system availability, unplanned safety system actuation, unplanned automatic reactor cs' rams, radiation protection reports of overexposure and excess release (10 CFR Part 20, Sec. 405), lost workday incident rate, fuel reliability, and ratio of corrective to preventive maintenance. Deviations of the weighted average from historical averages would result in rewards or penalties to CPC. Option 4 is based on one performance parameter, unit evailability, and is applicable to Palisades only.

CPC argues that Option 4 is not a good measure'of the complexities of operating a nuclear plant or of management prudence.

Each of the four options is symmetric; i.e., it provides for both penalties and rewards. Options 3 and 4 have "deadband" ranges of performance which would result in no penalty or reward.

Potential Financial Impacts on Utility Potential financial impacts have not yet been calculated due to the early stage of consideration of the standards.

l 41-t-

CPC's 1985 total %perating revenues were $3,298 mi111on, total operating expenses were $2,809 million, and net loss was $270 million. Although the company generated net income of $221 million in 1984, 1985's net loss was caused primarily by the write-off of certain Midland nuclear project costs totalling $488 million.

1 f 4

I 4

e

,-._m- - - - - - , - , , . .- , , g _ _ -

MICHIGAN Eig Rock Point Palisades Operating Performance Incentive Regulatory Authority: Michigan Public Service Commission Nuclear Plants: Big Rock Point Palisades Utility: Consumers Power Company Status: Discontinued Measure of Productivity: Availability e

Type of Incentive: Reward and Penalty

Description:

(See Enclosure 2, pp. 28-31.) This discontinued incentive (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. The public objected to a provision of the program that allowed automatic pass-through of costs to ratepayers (without PSC review) if availability goals were met.

1 l

Potential Financial Impacts on Utility Financial impacts have not been calculated because this-incentive has been discontinued. .

4 i

i I

r l

l l

NEW JERSEY Hope Creek 1 Construction Performance Incentive Regulatory Authority: New Jersey Board of Public Utilities 1

Nuclear Plant: Hope Creek 1 Utilities: Public Service Electric and Gas Company Atlantic City Electric Company Status: Initiated July 1983 Measure of Productivity: Total construction costs Type of Incentive: Reward and Penalty

Description:

(See Enclosure 2, pp. 37-38)

Potential Financial Impacts on Utility

^

Public Service Electric and Gas Company (PSE&G) (95 percent owner) and Atlantic City Electric Company (5 percent owner) have spent approximately

$3.9 billion on Hope Creek through April 1986. They expect that the total cost will be in the range of $4.15 billion to $4.3 billion, depending on the commercial operation date, now projected for late 1986.

i e

i

.. o 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.

1

! The potential disallowances discussed above are based on PSE&G's current cost estiinate 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 1985 total operating revenues were $4,409 million, total operating

, expenses were $3,781 million, and net income was $545 million.

i .

i l

l .

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 Type of Incentive: Penalty e

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 th'e 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.

l e

e

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 progran affects how load is dispatched. It applies only to retail sales. Thus PSNM would attempt to avoid FERC-regulated sales (wholesale) from inventoried plants. 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 Tiave been given due to the newness of inventoried plants. The coal plant was inventoried in 1985 and Palo Verde 1 in 1986. It is difficult to estimate a maximum impact because of offsetting program features.

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 uncertain how this sale and leaseback will affect the incentive program; however, it can reasonably be expected to be minor.

PSNM's 1985 total operating revenues were $749 million, total operating expenses were $562 million, and net income was $146 million.

NEW YORK Nine Mile Point 2 Construction Performance Incentive Regulatory Authority: New York Public Service Commission 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 Commission e

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.)

A 1984 New York Public Service Commission (N.Y. PSC) decision increased the Nine Mile 2 construction cost cap from $4.6 billion (reported in Enclosure 2,

p. 38) to $5.4 billion. Inis cap is technically in effect now, while the following settlement agreement is considered by the N.Y. PSC. In July 1985, 3

5 -

the N.Y. PSC initiated an investigation into the prudence of Nine Mile 2 construction costs. This lead to a joint settlement agreement 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 replace provisions of the previous incentive plans and would substitute a $4.16 billion total construction cost cap on the facility. A PSC decision is expected in August 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. In extraordinary circumstances, the PSC would consider exceptions to cost overruns that are due to unforeseen events and that are shown to be beyond management's control. The standard for granting exceptions is stringent. The utilities now estimate their total cost to complete construction at $5.70 billion (including CWIP benefits), creating a $1.75 billion disallowance (adjusted for the inclusion of construction work in progress in rate base in the amount of $209 million).

Potential Financial Impacts on Utilities i

Under the terms of the proposed settlement agreement, Niagara Mohawk would bear approximately $890 million of the projected $1.75 billion disallowance.

Niagara Mohawk owns 41 percent of the unit but would bear a somewhat higher percentage of the disa'llowance because of an agreement with the other four co-owners. Assuming a 40-year plant life, Niagara Mohawk would be penalized approximately $97 million in earnings available for common stock on a levelized basis per year for ;ae life of the facility. Niagara Mohawk's 1985 total operating revenues were $2,695 million, total operating expenses were

$2,284 million, and net income was $411 million.

i 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 (VEPCO)

Oconee 1, 2 & 3 (Duke) North Anna 1 & 2 (VEPC0)

Catawba 1 (Duke)

Utilities: Carolina Power and Light Company Duke Power Company i

Virginia Electric and Power Company

' Status: Initiated June 1982  :

Measure of Productivity: Capacity Factor Type of Incentive: Reward and Penalty T

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. A decision is not expected before late 1986. 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.

l l

l

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 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 revenue 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. No other penalties or rewards have been received. CP&L's 1985 total operating revenues were $1,935 million, total operating expenses were

$1,552 million, and net income was $331 million.

Duke Power Company. Until the court case noted above is decided, the financial impact will not be known. The Utilities Commission indicated in its most recent decision that Duke's excellent performance and management were factors in determining the company's allowed rate of return. Duke's 1985 total operating revenues were $2,899 million, total operating expenses were

$2,371 million, and net income was $438 million.

I

o o

]

OHIO Davis-Besse Operating Performance Incentive Regulatory Authority: Ohio Public Utilities Commission Nuclear Plant: Davis-Besse Utilities: Toledo Edison Company Cleveland Electric Illuminating Company Status: Initiated 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-recoyery.

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 Fin'ancial Impacts on Utility The program doos not have the potential for having a major impact on the company. There is a cap on over-recovery but not on under-recovery. flo real effort has been made to isolate the actual impact of the program on revenues.

The maximum p?nalty is estimated to be between $500,000 and $1 million within a six month test period.

Toledo Edison's 1985 total operating revenues were $595 million, total operating expenses were $455 million, and net income was $173 million.

Cleveland Electric's 1985 total operating revenues were $1,254 million, total operating expenses were $995 million, and net income was $311 million.

8

- ,. - - - . - - - , - , - - , . , - - - , . __ , er-

OREGON Trojan .

Operating Performance Incentive Regulatory Authority: Oregon Public Utility Ccmmission 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 Portland General Electric Company (PGE) to retain 20 percent of any savings from keeping fuel and purchased power costs under the target level and to absorb 80 percent of any excess fuel and purchased power costs.

]

%~

~

s m .

e 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.

PGE is a wholly-owned subsidiary of Portland General Corporation, a holding company. Portland General Corporation's 1985 total operating revenues were

$827 million, total operating expenses were $623 million, and net income was

$135 million.

l 4

-g , , .- _

VIRGINIA Surry 1 & 2 North Anna 1 & 2 Operating Performance Incentive Regulatory Authority: Virginia State Corporation Commission (VSCC)

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 Enclosure 2, pp. 36-37.)

Potential Financial Impacts on Utility There is no specific set of rewards and penalties as they are included as a subjective decision factor in the fuel cost recovery allowance. Potential penalties and rewards therefore can not be quantified, although they are a real factor in VEPC0 rates. They are f.actored into rates during the annual

VSCC fuel recovery clause proceeding. This was most recently considered in the fall 1985.

VEPC0 is the major subsidiary of Dominion Resources, Inc., a utility holding company. Dominion's 1985 total operating revenues were $2,712 million, total operating expenses were $2,118 million, and net income was $320 million.

e 4

~

VIRGINIA Surry 1 & 2. .

North Anna 1 & 2 Operating Performance-Incentive 4

Regulatory Authority: Virginia State Corporation Commission (VSCC)

Nuclear Plants: Surry 1 and 2 .

North Anna 1 and 2 Utility: Virginia Electric and Power Company Status: Initiated January 1979 Measure of Productivity: Capacity fac, tor; equivalent availability ~

-Type of Incentive: Reward and Fenalty

Description:

(See Enclosure 2, pp. 36-37; additional information follows.)

The Virginia State Corporation Commission (VSCC) provides incentives based on improved generating unit performance. 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 VSCC recommends a specific return for the company based on the units' performance during the test period and over time.

, ., - . . , - - - - - - s-.- ~ , ,, -my m.-_ s--,- .----,----.--,-v____x,w_.. --v_, ,,,_,c..,-.,m y-,,- , ,... ,m_.

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. In the last rate case decision where the incentive was applicable (May, 1986), the VSCC recognized VEPC0 for improved generating unit performance, both nuclear and fossil. It said that the allowed return on equity (14.5 percent) was based in part on the improved performance. The range of returns considered had been 14-15 percent.

VEPC0 is the major subsidiary of Dominion Resources, Inc., a utility holding company. Dominion's 1985 total operating revenues were $2,712 million, total operating expenses were $2,118 million, and net income was $320 million.

9

- - - - . - - - - . - - . -, _ - - , - , - . , . - - - - . - - - ---r ------m.

. ~

i l

FERC Surry 1 & 2 North Anna 1 & 2 Operating Performance Incentive Regulatory Authority: Federal Energy Regulatory Commission Nuclear Plant: Surry 1 and 2 .

North Anna 1 and 2- -

Utility: Virginia Electric and Power Company

' Status: Initiated January, 1983 (three-year trial basis Ended December, 1985)

Measure of Productivity: Capacity Factor Type of Incentive: Reward and Penalty

Description:

The rate of return on equity (R0E) allowed by the Federal Energy Regulatory Commission will vary up to one percent depending on,how closely company fuel expense (based on actual composite performance of 12 coal and four nuclear units) matches. predicted fuel expense. Equivalent availability and heat rate are the standards for the coal units and cenacity factor is the

' standard for nuclear units. The capacity factor standard for nuclear units is

~

based on capacity factors of similar nuclear units, adjusted for such factors as a steam generator replacement.

,7e. --,.,m, . .

,=-..,v,--.s , - . . . . - . - - , . - - , - . , . -

os ,

)

1 The company's fuel expenses must underrun fuel expenses based on the composite coal and nuclear performance standard by at least five percent to trigger a reward. Likewise, the company's fuel expenses must exceed fuel expenses based 2

on the performance standard by at least five percent to trigger a penalty.

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 ROE.

It is unknown at this time whether this three-year trial basis incentive will be continued beyond 1985.

Potential Financial Impacts on Utility The magnitude of potential penalties and rewards fluctuates with the amount of the current rate base and the allowed ROE. Since inception of this performance incentive, VEPC0 received a $141,000 reward in 1983, and no penalties or rewards in 1984 and 1985.

VEPC0 is the major subsidiary of Dominion Resources, Inc., a utility holding company. Dominion's 1985 total operating revenues were $2,712 million, total operating expenses were $2,118 million, and net income was $320 million.

9 6

c -

f* "'%tg UNITED STATES

y. -t NUCLEAR REGULATORY COMMisslON

j.  ; ,g WASHINGTON, D. C. 20555 N...../

SEP 2 S 193 MEMORANDUM FOR: Document Control Desk Office of Administration Mail Station 016 FROM: James C. Petersen Senior Licensee Relations Analyst Licensee Relations Section Office of State Programs

SUBJECT:

PUBLIC RELEASE OF 0FFICE OF STATE PROGRAMS REPORT,

" INCENTIVE REGULATION OF NUCLEAR POWER PLANTS BY STATE PUBLIC UTILITY COMMISSIONS, UPDATED REPORT - JULY 1986"

-The NRC staff has released the subject enclosed report to the public.

Accordingly, please process this report through the DCS system and make it available in the H Street PDR and Reg. files. Thank you.

d. M -

James C. Petersen Senior Licensee Relations Analyst Licensee Relations Section Office of State Programs

Enclosure:

As stated cc: w/ enc 1.

Marsha Ward, PDR - H. St. (advance copy)

/

[ 4r o

UNITED STATES NUCLEAR REGULATORY COMMISSION

{ . ,I wAsHmoTow o.c. zones

%..... January 27, 1984 IEMORANDUM FOR: Frank H. Rowsome, Assistant Director for Technology, Division of Safety Technology NRR FROM: Jerome.Saltzman, Assistant Director for State and Licensee Relations. OSP StBJECT: INCENTIVE REGULATION 0F IRJCLEAR GENERATION FACILITIES BY STATE PUCs Enclosed is our report on the subject of incentive regulation of generation facilities by State public utility commiissions. 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 from 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.

l

/s2 ERCFJ K'iiU!*.V ,

Jerome Saltzman, Assistant Director State and Licensee Relations Office of State Programs

Enclosure:

As stated O t~ d 12d 4 0 % 'bp 'A v '+v s ut' r ' ' " If

. - _ - - , , . . . -. . . -. - -- _.12:1. :: ? .~- - _ _ . _ _

January 27, 1984 ENCLOSURE 2 3

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 sumarizes the findings pertinent to nuclear power of the three recent national studies on this subject. An attempt has been made to sort out'and highlight the studies' findings that may be most interesting to reactor safety regulators. 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) 2I ,

and the Quadrex Corporation (for EEI). 3_/

II"IncentiveRegulationintheElectricUtilityIndustry,"preparedby 2/ "he t NARUC Subcomittee on Electricity, September 1983.

Standards of Performance Study, SONGS 1," S. M. Stoller Corporation, for California PUC, under contract to Southern California Edison Co.,

A l 3/ "ugust 1983.

I -

Incentive Re

'(final draft)gulation Programs

, Quadrex Corp., forinEEI, the July Electric 1983.Utility Industry,"

l l

f. ..

Summary of Findings - NARUC Although the NARUC study is primarily a survey and description 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 to be widely recognized that incentives may provide a means of assuring reliable 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 regulatory agencies, which have always existed, but have become more acute, also indicate the necessity for more effective and efficient regulatory tools. Currently, the g'reatest 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 costs (fuel and purchased power) represent 50 percent and more of the electric utilities' total cost ofoperation."bl l

SI NARUC Study, p. 1-1.

3 -- - - -- _ _ _ . . . _ _ . _ _ _ . _ .

.. l

y. ,

\

The NARUC study recomenh,ed further regulatory initiatives in the area .

of perfonnance incentives and said that regulatory agencies should  !

l 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 performance 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 performance.

o Aggregate perfonnance as measured by such indicators as average unit revenue and the growth rate of operating and maintenance expenses.

Summary of Findinos - Stoller I

In October 1981, the California Public Utility Comission (CPUC) l f directed Southern California Edison Company (Edison) to engage a consultant to carry out a standards of performance study for the SONGS-1 nuclear unit. In November 1982, the CPUC selected the S. M. Stoller Corporation (Stoller) to perform the study. In the course of its study Stoller reviewed and reported on performance standards programs I

l p.

-4 promulgated in other states which could impact the fomulation of a program for SONGS-1. Stollermakesthefollowingobservationinthe background of its report:

"In the past several years, there has been increasing regulatory interest in the perfonnance of large central station generating units, both fossil and nuclear. This interest primarily 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 utility 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 intended to be capable of simple interpretation and implementation, by which " good" performance of a unit on a utility system can be rewarded, or " poor" perfomance penalized. Such standard programs are seen as producing two potentially desirable effects:

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 required for ratemaking purposes.

However, in considering such a program applied specificall,y to the 50NGS-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 4

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.

3. The SONGS-1 plant is one of the very oldest units in current operation and much of that total nuclear power 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 performance.

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."E/

F f

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 l mandate operator action. Stoller points out that it deemed the l

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.

O e

. . l Stoller's meeting with NRR management in May 1983 is reviewed in its report. Although the Stoller study was specifically addressed to SONGS-1, the CPUC has not placed any perfonnance incentive 3

requirements on that unit since it has been inactive for the past two years. Reactivation of the unit is dependent on NRC-required upgrades including those related to seismic capability. The Stoller findings were used as background for the perfonnance incentives imposedb' y 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 InchudedinStoller'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 i

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."

l 1

o " Broadening the base of the formula, e.g., to include the

• ~

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 management attention to a specific unit."

o "It is probably useful to establish a " null zone" to accomodate variations in performance, for any number of random causes, which inevitably occur in the operation of a unit from year-to-year. This concept inay be particularly applicable to nuclear units, for which the statistical experience base is still relatively modest, and quite nonunifonn; 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 tverage 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

~.

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."1/

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 rreasure performance rather than one single

~

SI Stoller, pp. I-22 through I-24

measure in order to avoid distortions or unintended outcomes. In ,

some cases, narrowly defined operating measures have led to increases in the cost of service rather than greater efficiency.

Just as most of the programs rely on multiple measures of performance, 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.

i 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 summarized below using information drawn from Stoller, EE1 and NARUC. Conclusions reported herein regarding the effectiveness of the incentives and their relationship to efficient operation and to safety are those 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.

Sunenary of State Operating Performance Standards Programs (Nuclear) (Notes 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 i

San Onofre Sou. Cal. Ed/ Calif. Fuel CF CF> 80% CF< 55% N. Avail.

! NGS Unit 2 SDG8E 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 Ste Lucie 1&2 Fla. P&L 1981 Equity EA & HR (2). (2). FP&L:+$1.7M Turkey Point 482' 34+

l Calvert Cliffs 1&2 BG&E Md. Replacement i 1978 Fuel Cost EA None Judgment (3).

j Pilgrim Boston Edison Mass. Fuel AF, EA, CF, Yankee-Rowe Yankee Atomic 1981 Charge HR & FOR None (4). None l Big Rock Point Consumers Pwr. Mich. Return on ECAR (5) (5) +$14M

! Palisades 1978 Equity Availability

, Brunswick 1&2 Carolina P&L N. Carolina Return (6). (6). (6). (7).

McGuire Duke Power Co. 1978 on Equity Surry, H. Anna VEPC0 ,

Davis Besse Toledo Edison Ohio Fuel C'ost Mce> 1 Mces 1 Not 1981 Cost Effectiveness (8) (8) Determinable i

Surry 1&2 VEPC0 Va. Return on CF Judgment Judgment (9).

North Anna 1&2 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 perfomance below 55% weighted average nuclear CF. There is an interest penalty for performance between 55% and 70% and an interest reward for performance 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 ho. Carolina Utilities Comission reduced VEPCO'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 utilization, 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 1% 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.

Arkansas Affected Nuclear Plant and Utility: Ark'ansas Nuclear One Units 1 & 2, Arkansas Power and Light b

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.

l l

l 4 Although not explicitly stated in any documentation, the

' Arkansas PSC treats any refueling outage beyond 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 net 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).

l l

4 The Fuel Adjustment Clause Rider does not incorporate provisions for modifying unit performance to acc6unt 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 perfonnance 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 sumer months so that if any extension occurs, it takes place 1

during the fall months. Thus, penalties would be reduced and AP&L would absorb a reduced ' loss under the fuel adjustment calculation.

(

l l

\

o Extending outages ra.ther than return to service and risk a later outage which restarts the Formula 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

$107 million). 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 l

to the Rider to moderate its impact on AP&L. One would be the f 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 pe'rfonnance 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 perfonnance was worse than that value. Another revision being considered would allow AP&L to keep all replacement power co,st 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 factorabove80%wouldbesharedequally(50/50)betweenthecompany (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 PVC thought that standard was too harsh, particularly in 'the relatively untested area of incentives. The Comission 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 staff that a performance standard such as a target capacity factor would not compromise safe plant operation. The 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.

_19 Colorado Affected Nuclear Plant and Utility: Ft. St. Vrain, Public Service Company of Colorado D

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 perforrance 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 $807,000 per month.

Public Service Company of Colorado was ordered to escrow this amount on a monthly basis separately from the general funds of the Company for ultimate disposition. ,

Connecticut l

Affected Nuclear Plants and Utilities: Millstone and Connecticut Yankee l - Connecticut Light & Power Co., Hartford Electric Light Co.

l l

The Connecticut Division of Public Utility Control established the Generation Utilization Adjustnant Clause (GUAC) for Millstone and

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 historlcal performa'nce of nuclear units under its control with the historical perfomance 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 I

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.

i

Florida Affected Nuclear Plants and Utilities: Crystal River Unit 3 - Florida S 4 Power Corp'.; Turkey Point Units X &#, 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. Additional 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 l companies to design the program criteria and measures. Targets are ' set l

l

by formula 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 i

according to economic dispatch with adjustments made for unit i

modifications, fuel changes, and environmental regulations. ,

i Above average performance 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 returs on comon equity. The singular objective of lowering fuel costs as a function of performance targets may result in the company neglecting other creas of utility operations. At issue is whether the program minimizes the overall cost of operation. Finally, the reporting, administrative and technical analysis activities for the annual hearings involve substantial costs and commitment of manpower.

1 i

) Florida PSC personnel report that the GPIF was meeting its objectives: '

increased efficient operation of base load plants. The following j

decreases in system overall heat rates since implementation of the GPIF were noted: approximately 130 STU/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 performance periods under GPIF.

FP&L has received 3 rewards totaling $1.9 million and 1 penalty of $180

--.,n.. , . - - ..-....---,.,.------n.-... , . . . - , - - w . . . , - - - - , . . , ~ - - - - - -

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 penalties. The PSC staff reported one problem with the GPIF; there is som.e 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 re,'orted 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 increased the workload of the PlLnt Performance Group due to data tracking, collection and reporting requirements.

Maryland Affected Nuclear Plant and Utility: Calvert Cliffs Units 1 and 2, Baltimore Gas and Electric Under a 1978 Maryland law, fuel cost adjustment and determinations were removed from base rate 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 perforned 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 factor (EAF) for the most recent 12-month period exceeds the higher of: 1)itsaverageEAF 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 3 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.

4 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.

l Evidently, a nut from the turbine hoisting equipment had gotten loose, fell into the turbine during maintenance and had caused damage during l.

I turbine operation. The 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 Cliffs 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 experienced 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 mom 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 procedure. The

~

e amendment provided for establishment and operation of a fuel charge monitoring bureau to administer and enforce the fuel charge procedure.

I

• 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 Departnent 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

/

0 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 single generating unit is defined as unit operating hours plus unit 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 zone was reduced from 10% to 6%, and 3) the system availability scales

_e - _ _ . - , _ . -

t

\

were" fine-tuned"and11rangeswerecreatedknsteadoftheoriginal3 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 performance 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 unplanned outage factor equals one. The current scale for Consumers Power 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.

CONSUMERS POWER COMPANY AVAILABILITY INCENTIVE PROVISION System Availability (ECAR) Equity Return Plus Periodic Factor Incentive 100% -

94.01% +.50%

94.00% -

92.76% +.40%

92.75% - 91.51% +.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 Consurers 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 performance before the Availability Incentive Provision 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

- 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.

North 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 Connission 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 Commission 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 performance in general rate case hearings and has levied penalties for poor plant performance. When a utility files an application for a general rate increase, the Public Staff, acting as a consumer advocate, reviews the performance 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 performance, the Staff can recommend to the Commission 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 Commission then makes a judgment as to the utility rate af return.

There are no defined standards by which power plant performance is judged.

The Commission adopted a new general rate case procedure in June 1982.

The utility fuel cost chargeable to ratepayers is included in the

,tility 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 femal standards of perfomance 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 perfomance" and in allocating penalties.

For example, in a 1981 decision on a VEPCO 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)managementpracticesinplant0&M,2) outages,reductionsinpower, and 0&M practices and procedures, and 3) predicted fuel costs at higher j 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 l

e 9 Staff and held that VEPC0's fuel expenses were excessive due to poor plant perfonnance. The return on equity was reduced as noted above.

~

In a 1982 CP&L rate case, the Comission reduced the return on equity by 1 *. . The comission 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 ce 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 j electric service to customers by providing incentives to investor-owned l utilities for minimizing fuel costs'.

l i

The specific provisions of the statute were implemented in February 1981 and placed in the Ohio Administrative Code on September 1981. The i

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 fonnula used to measure ce l 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 nat had any impact on power plant operations or engineering. 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, ca.pacity factor, and availability.

Davis-Besse performance has been hurt by TMI and generic problems (e.g.,

pump seals). Any external pressure to improve Davis-Besse performance has come from the Ohio PUC during base rate hearings. For example, the Ohio PVC has suggested that Davis-Besse might be removed from the rate l

base if performance did not improve. Toledo Edison reports thSt there has been no discernible concern on the part of the NRC with regard to the Ohio performance standards program.

l

\ Virginia g

Affected Nuclear Plants and Utility: Surry 1 & 2, North Anna 1 & 2 - l VEPC0 1

A VEPC0 rate application settlement establishes a perfortnance 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 improvements 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. Second, 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 reascrableness of the utility's projected and actual fuel expenses.

While there is no specific set of rewards or penalties, 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 detennined to be the result of poor pt.rformance because of factors within management's control, complete recovery may not be allowed. If actual perfonnance 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 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

4

• * ~

percent. Should costs exceed this target by more than 10 percent,'the company may recover only 70 percent of costs above the 10 gercent threshold. If the plant cost is between $3.5 billion and 53.7 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 Commission; 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 community 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.

R 0

l l

1

ENCLOSURE 3 Southem Califomia Edison Company P.O. Box 800 2344 WALNUT GROVE AVENUE .

MOwAmp P. ALLEN NOS EME AD. CALWORNIA SI770 Cha*sesase OF TME SOaac Am0 ftttpueng c .cr : : cut v Orr.cca ' ' * " " "

September 9, 1985 Mr . William J. Dircks Executive Director for Operations U.S. Nuclear Regulatory Commission Washington, D.C. 20555

Dear Mr. Dircks:

As you probably know, the Southern California Edison company is involved in~a proceeding before the California Public Utilities Commission (CPUC) on the reasonableness of the construction expenditures for San onofre Units 2 and 3.

In the course of this proceeding, the line between economic regulation by the CPUC and safety regulation by the NRC has become blurred in a way that is deeply troubling to me not only because of the possible impact for our own plants but also because of the broader implications for the safety of all commercial nuclear plants. While implementing safety require-ments in design, construction, and operation during the course of building nuclear plants is the utility's primary responsi-l bility, the adequate discharge of that responsibility is chal-l lenged, examined, and verified at every stage of the licensing l review process by the Nuclear Regulatory Commission Staff.

! Ironically, we find ourselves defending against charges that we have been too forthcoming in our relations with the NRC.

For example, the CPUC Staff has recommended a capital disallowance because we delayed startup for several days to perform an NRC-mandated inspection when we thought it was necessary rather than at the next refueling which would have been allowed by the NRC Bulletin. The amount of money involved in this instance is not overly large, but the implications are enormous.

In another instance, our initiative to perform an indepen-dent seismic design review in the wake of the discovery of the mirror-image error at Diablo Canyon has been questioned by the CPUC Staff on the grounds that we went beyond NRC require-ments. . Finally, the time to license Units 2 and 3 has been 63 C (ph  ?

l Mr. William J. Dircks Page 2 <

September 9, 1985 deemed excessive because it is supposed to be obvious that the

~

NRC supplies an operating license whenever a plant is com-pleted, no matter what. These notions are as repugnant to us as they must be to you, and we hope they will be rejected by the California Commission. However, at this point we cannot be sure.

No matter how well intended, the effect of this line of argument by the CPUC Staff, if upheld by- the California Com-mission, will be to establish economic disincentives for full and wholehearted compliance with the requirements of safety regulation. This will not alter our commitment to safety. I am, however, concerned that this will make it more difficult for us to discharge our health and safety responsibilities.

This issue is not limited to California in view of the importance of the California commission among the public utility commissions around the country. The implications for the relationship between the NRC and the utilities around the country are obvious.

1 We have no intention of drawing the NRC into our rate proceeding. We feel we have an excellent record both in terms .

of cost and schedule for the construction of San Onofre Units 2 and 3. We are very proud of our achievement and we expect to e put on a very powerful case. We hope for a favorable ruling from the California Commission, and we also hope it will reject the Staff arguments I have described.

At the same time, the implications of an extension of economic regulation into the safety arena are significant for the reasons noted. I would appreciate any comments you may wish to provide.

Sincerely,

^

4.q -- t, a ~ __.-.

s 6

-, yy _yy - - , . , . _ _ - - - - ,_,,,,--,,,,,v.- .,-,,.# -y,,_.___,_.,_,,--.._._,y,,

• "8 49 ENCLOSURE 4 y

, k p UNITED STATES NUCLEAR REGULATORY COMMISSION t; wasmwoTom, p. c.zosss i

\, ..... /[ '

September 17, 1985 Mr. Howard P. Allen Chaiman of the Board and Chief Executive Officer Southern California Edison Company P.O. Box 800 2244 Walnut Grove Avenue Rosemead, California 91770

Dear Mr. Allen:

This is in response to your recent letter expressing concern about a pro-ceeding in which Southern California Edison is involved before the California Public Utilities Comission (CPUC). As you know the Nuclear Regulatory Comission does not become involved in proceedings before state public utility commissions. I have not seen or reviewed any of the recomendations by the staff of the CPUC. Thus, I can only respond to the generic concerns raised by the issues identified in your letter.

First, I would hope no one so misapprehends the NRC's efforts that they believe we issue a license whenever an applicant declares a project complete. We do make every effort to coordinate our reviews with the licensee's projected schedule for fuel load so that when the utility is ready, we should be in a position to make a licensing decision. However, a license is issued only after the NRC is satisfied that the facility is ready to operate.

Our regulatory scheme is based upon a set of minimum requirements deemed sufficient to provide reasonable assurance that the public health and safety will be protected. However, we continually urge utilities to strive for excellence; that is, to take actions beyond our requirements which will enhance the public health and safety. In particular, we expect licensees to be alert to the experiences of other utilities and to apply any lessons learned without the need for explicit orders from the NRC. The Comission has strongly supported INPO efforts to that end and has deferred to industry in situations where it appears they are taking sufficient initiative. We have taken considerable steps in recent years to increase reliance on utility initiatives where possible, because such action recognizes and emphasizes that primary responsibility for the safe operation of a nuclear facility lies with the utility. I view with concern any indication from the state regulatory sector that a utility initiative to enhance the safe operation of its facility, if not undertaken at the direct behest of the NRC, is not in the long-term interest of the ratepayer and the public health and safety.

S hD h [5r$ ,

• . s 2-Economic incentives need not have negative effects on safe reactor construction and operation. We trust that the CPUC will resolve th4 issues before it in a manner consistent with reactor safety. Nonetheless, we shall remain alert to indications cf adverse influences on safety.

Sincerely, Signe0 William J.Dircks.

William J. Dircks

. Executive Director for Operations l

l l

l l

_ _ _ _ . . - _ _ . _ _ _ _ . .. . . - - - . _ _ - . _ - - - - - - - _ - __