ML20245D050

Incentive Regulation of Nuclear Power Plants by State Pucs, Updated Rept - Sept 1987

ML20245D050
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Issue date:	09/30/1987
From:	Office of Nuclear Reactor Regulation
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ML20245D034	List: ML20245D031 ML20245D043 ML20245D050
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NUDOCS 8711040330
Download: ML20245D050 (88)

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. /, h%j. UNITED STATES y  ; NUCLEAR REGULATORY COMMISSION

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I INCENTIVE REGULATION OF NUCLEAR POWER PLANTS BY' STATE PUBLIC UTILITY COMMISSIONS UPDATED REPORT - SEPTEMBER 1987 j A REPORT PREPARED BY THE STAFF 0F THE U.S. NUCLEAR REGULATORY COWISSION 0FFICE OF NUCLEAR REACTOR REGULATION. l 1

NRC Staff

Contact:

James C. Petersen NRR (301)492-7200 871i040330 PDR DRG

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, w INCENTIVE REGULATION 0F NUCLEAR POWER PLANTS-o' BY STATE PUBLIC UTILITY COMMISSIONS UPDATED REPORT - September 1987 TABLE OF CONTENTS ..

Page I .- Introduction i

A '. Purpose '4' ,

i B. Description of Incentives 5 C. The Potential Influence of Performance Incentives on i Reactor Safety '7

0. Incentive Rewards and Penalties - 10. i E. ' Sources of Inforination 12  ;

II. Summary Chart of Incentive Programs Grouped by NRC Region 13 III. Individual Plant Reports' 20 State Facility Type of incentive Status I Page Arizona Palo Verde 1 Operating Same 20 -!

Palo Verde 1, 2 & 3 Construction Revised 22 Arkansas Arkansas Nuclear 1 & 2 Operating Same 24

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California Diablo Canyon 1 & 2 Opera ting Revised '27 1

San'Onofre 1, 2 & 3 Operating Revised 30 Palo Verde 1, 2 & 3 Colorado -Fort St. Vrain Operating Revised 35 Connecticut Millstone 1, 2 & 3 Operating Revised 37 Yankee Plants Florida Crystal River 3 Operating Revised 39 St. Lucie 1 & 2 Turkey Point 3 & 4 St. Lucie 2 Operating Same 43 I

Status is indicated (a) for "New" incentive plans, i.e., those nnt included in the previous report of' July 1986; (b) for incentive plans havingsubstantially" Revised" provisions (orrevisedandadditional information) since the July 1986 report; and (c) fcr incentives that are substantially the "Same" as reported in July 1986.

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L. ' TABLE 0F CONTENTS (Continued)

State Facility Type of Incentive Status Page Maryland Calvert Cliffs 1 & 2 Operating Revised 45 Massachusetts' Pilgrim Operating. Revised 47 Michigan Fermi 2 Operating Revised 49 Palisades Operating Revised 51 Big Rock Point Operating Same 53 Palisades Mississippi Grand Gulf 1 Operating New 55 i New Jersey . Salem 1 &'2 Operating New 57 Peach Bottom.2 & 3 Hope Creek Oyster Creek Three Mile Island 1 New Jersey Hope Creek Construction Revised 60 New Mexico Palo Verde 1 Operating .Same 63 New York Nine Mile Point 2 Construction Revised 65 Ginna .

Safety New 67 Indian Point 2 Nine Mile Point 1 & 2 North Carolina Brunswick 1 & 2 Operating Revised 70 Robinson Oconee 1, 2 & 3 Catawba 1 McGuire 1 & 2 l Surry 1 & ?  !

North Anna 1 & 2

'.0hio Davis-Besse Operating Same 73 Oregon Trojan Operating Same 75 Pennsylvania Limerick 2 Construction New 77 Limerick 2 Operating New 80

TABLE OF CONTENTS (Continued)-

State Facility. Type of Incentive Status Page Virginia Surry 1 & 2.. Operating- Same- '82 e-North Anna 1 A 2 Surry 1 & 2. Opera ting - Same' 84 North Anna 1 & 2 .

FERC', Surry 1 & 2 Operating' Same 86 North Anna .1 & 2

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4 l INCENTIVE REGULAT10N'0F NUCLEAR POWER PLANTS BY STATE PUBLIC UTILITY COMMISSIONS i

. September 1987 1 l

INTRODUCTION 4 Purpose '

This report provides-information 'on the methodology and potential financial impacts of economic performance incentives applicable to individual nuclear i power plants. It is an update of the report of the same title dated July 1986. The purpose of this report is to describe how specific nuclear plant performance incentives work and to provide background information for use in evaluating the incentives' possible safety effects. (TheNRCstaff l

' informed the Commission of its effort to track nuclear plant economic incentives in SECY-85-260, July 26, 1985.)

Since the July 1986 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 table of contents on ,

pages one through three and are described in the individual plant reports beginning on page 20. This report is comprehensive. Material that is unchanged n

.from the July 1986 report is repeated herein; reference to that report is no I

New and updated material (since the July 1986 report) in the individual plant reoorts herein (starting on page 201 is identified by vertical lines in the left margins.

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I longer necessary. A summary chart of the incentives (with plants grouped by NRC Region) appears on pages 13 through 19 Description of incentives Economic performance incentives (or." incentive plans," " efficiency incentives")

l .are mechanisms used by State PUCs' to measure a utility's efficiency level in operating or constructing generating plants and to financially reward' or penalize the utility for performance above or belcw established levels. The

l. objective of incentive plans is to encourage sustained improved performance.

Through the incentive programs, PUCs hope to achieve better plant economic performance with less regulation, by having the utilities derive financial

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l benefits from good performance and added cost burdens from poor performance. {

l Incentive plans usually set out specific formulas by which management efficiency  !

and plant performance are measured and by which the financial rewards and ,!

I penalties are calculated. Performance incentives are applicable to the j construction or. operation of about 45 nuclear power reactors owned by 30 1 utilities.in 17 States. Several additional States are considering nuclear plant incentives. There are also incentive programs applicable to non-nuclear facilities = in some States.

The performance incentive plans vary widely. A number of different criteria are used to measure performance. These include heat rate, capacity factor, l

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availability factor, fuel costs, construction costs, and various other criteria.. !

Some plans base incentives on only one measure of performance, others on more 1

than one measure. The form and ~ size of incentives also vary from plan to plan. Some plans reward good performance, others penalize poor performance, while still others do both. The incentives are sometimes large, potentially l involving many millions of dollars. Incentives may be applied to a utility on 1

a system-wide basis, or to individual plants. Most plans include an objective I predetermined formula for determining the size of the financial reward or penalty, if any, as a function of performance. Some plans kclude a null zone of performance (or "deadband"), in which neither reward nor penalty accrue. A l few plans have no predetermined formula, but depend on evaluation by the '>UC of how factors under tho utility's control contributed to the results achieved.

Some of the formula plans also include provisions for adjustments into which PUC judgment enters. Sometimes PUCs are aided by evidentiary hearings in reaching.their non-formula-determined decision. Incentive plans are of ten quite complex and often exert effects in indirect and complex ways. Sometimes such plans for non-nuclear plants can affect nucle er plants.

Most of the incentive plans provide for penalties and rewards. Currently, the NRC has no formal requirements or explicit policy concerning incentive plans. The NRC staff continues to study (on a generic basis) the possible effects that incentive plans could have on nuclear plant safety. Obviously, no matter what specific incentive plans are established, utilities must continue to operate nuclear plants safely. The way incentives are formulated, however, can affect the balance between aspects conducive to safe operations j

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and those which could undermine it. The effect of an incentive plan on plant safety ultimately hinges on a. utility management's reaction to the plant that is, the nature of the operational plans, operating instructions, and other .

measures that evolve in response to the incentive plan's provisions.

L There is considerable debate within the industry, within the National Association -

of Regulatory Utility Commissioners, between PUCs and utility. companies, and 1

among the industry, PUCs and the public and special interest groups as to the l soundness and fairness of th'e various incentive plans. It is evidently no easy task to devise incentives for a utility that faithfully model the public interest in reliability and economy. Questions have been raised about whether an imperfect incentive plan might offer an incentive for a utility to unknowingly  !

act against the public interest (i.e., public health and safety) in some situations.

The Potential influence of Performance Incentives on Reactor Safety While NRC has no detailed safety impact analysis and no specific information concerning the effects of implemented economic incentive programs, the influence of such incentive plans on reactor safety is perceived to be small.

This is because, without exception, all reactor licensees are required to l comply with NRC regulations whether incentive plans exist or not. These regulations, together with license conditions concerning operations and l

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' maintenance, specify an acceptable safety design and assure that nuclear power plants are operated with attention to safety.- Furthermore, NRC, through its j licensing and inspection' activities, verifies that licensees are adhering to safe practices. Nevertheless', economic regulation (incentive plans) could

. 1 influence a licensee's approach to reactor safety issues. In situations viot addressed in license conditions, which could have an indirect bearing upcn

. safety, economic incentives could have an influence. For this reason, it is believed that ecor,smic performance incentives could have both positive and negative influences upon safety. On the positive side, performance incentives reward a utility for correcting recurrent or predictable failures or degradations that could lead to plant outage or derating. This is a desired result because some of these degradations or failures which could be in safety systems, could adversely affect plant performance. For example, unanticipated shutdowns could challenge safety systems and might (low probability) trigger accidents. None-thaless, high morale and a quest for excellence in a utility's operational organ-ization, which can be encouraged by performance incentives, can be conducive to improving both safety and economic performance.

.On the negative side, the concern with incentive plans is that, in the interest of real or perceived short-term economies, utilities might hurry work 'take short cuts, or delay action in order to meet a deadline, a cost limitation, or other incentive plan factor. In other words, the potential exists that such a program could encourage, directly or indirectly, the adoption of actions designed to maximize measured performance at the expense of plant safety (public health and safety). For example, if the pursuit of increased availability leads a licensee to keep a reactor on line when it should be

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down for preventive or corrective maintenance, and shortcuts or compressed work schedules are used in order to minimize down time, the pursuit of greater availability could have an adverse inpact on safety.

Unlike economic incentive plans, whose primary emphasis is on economic performance, one state has proposed an incentive plan intended to enhance utilities' attention to nuclear power plant safety. This plan would use the NRC's performance assessment or enforcement programs as a basis for financial rewards or penalties. Plans of this type present several major concerns.

First, the Systematic Assessment of Licensee' Performance (SALP) was developed i

primarily to assist the NRC in identifying ' plants and program areas where inspection resources may best be allocated based on NRC's perception of licensee performance. The NRC staff focuses on the facts in the SALP report,.

the. issues identified, and the apparent root cause of problems. It is not the NRC's intention to focus on the numerical SALP values themselves. SALP functional areas may be added or deleted based on site specific considerations. i The prospect of financial rewards or punishments for utilities based on SALP ratings causes concern in that it may change .the focus of the SALP process from the underlying issues, where it should properly be, to the numerical

. ratings themselves. If the issues identified in a SALP report are obscured by I

concerns over the financial consequences incurred as a result of that rating, j i

an adverse-impact on safety could result. J The NRC is also concerned about the potential effects of this type of program on NRC interaction with licensee staff. NRC's effectiveness in inspecting

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plants depends, to'a significant. degree, on having an open relationship with I plant operating staff and managers at the plant. . Plant' operating staff. i frequent 1y' tell NRC inspectors of' problems that might not be revealed otherwise t '

l in the~ course of NRC's routine inspection program. NRC wants to-encourage '

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1 l this openness and is careful to see that plant staff are not punished .for.

i disclosing problems of possible . safety significance to the NRC. The prospect

-.that,. for example, .an individual's ' cash bonus might be adversely affected as a result-(at.least. indirectly).of disclosing safety significant information to the NRC.is a. concern.

Finally, NRC is concerned that the. program would specifically impose a large penalty on a' licensee for minimally satisfactory performance. In such cases the NRC may have determined that nuclear safety performance needs to be improved, but substantial economic penalties could reduce resources that might otherwise be spent to improve that performance. ,

In . light of these concerns, the NRC does not support use of SALP ratings or ,

enforcement history to arrive at financial rewards and penalties. Furthermore, performance incentive plans which focus on nuclear safety rather than economic i operation of nuclear plants may interfere with exclusive Federal regulatory authority over nuclear safety matters.

Incentive Rewards and Penalties Most of the utilities and State PUCs contacted for this survey seemed

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I knowledgeable about perfonnance incentives applicable to the facilities. They I indicated an awareness of potential financial impacts under the incentives.

They also-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.

i Apparently .the potential rewards and penalties gain significance when compared

-to individual plant budgets, to staff salaries, and when measured in terms of plant-specific decisions regarding operation or construction. Potential financial impacts for individual plants are indicated in the body of this report where they have been calculated by the utility or the PUC. In some cases the publicity following imposition of a penalty is deemed by the utility to be as undesirable as the penalty itself. It is apparently believed that ratepayers and utility stockholders view penalties as an indication of deficient I management.

Sources of Information The primary sources of information for this report are the State PUCs and the nuclear utility licensees. These sources are supplemented by a variety of .

printed sources including reports and articles issued by such organizations as the National Association of Regulatory Utility Commissioners (NARUCl, the I

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National Regulatory Research Institute, the Edison Electric Institute, reports issued by consultants to PUCs and utilities; and industry publications.

It is intended that this report will be periodically updated and distributed ) l by the Office of Nuclear Reactor Regulation. Users of the report are I requested to provide comments and suggestions for future reports. Conments  ;

i and questions should be directed to James C. Petersen, Office of Nuclear  !

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Reactor Regulation, telephone: (FTS: 492-7?00); (Conmercial: (301) 492-7200).

1 Mailing address: U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor Regulation, Room 128, Washington, DC 20555.

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ARIZONA Palo Verde 1 Operating Performance Incentive Regulatory Authority: Arizona Corporation Commission-Nuclear Plant: Palo-Verde 1 Utility: . Arizona Public Service Company 3

q Status: In effect since 1986 Measure of Productivity: Capacity factor Type of Incentive: Reward and Penalty -

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Description:

The Arizona Corporation Commission (ACC) has implemented operation and construction incentive plans for Palo Verde 1. The ACC staff has proposed in an ongoing rate proceeding that the operating incentive be extended to Palo Verde Units 2 and 3. The cc.struction incentive (applicable to units 1, 2- and 3) is covered under the next heading.

A capacity factor deadband of 60-75 percent was established which results in I 1

- no pt.nalty or reward. Capacity factors between 75 and 85 percent will result in a-reward and between ~0 and 60 percent will result in a penalty. The  ;

reward / penalty is equal u 'one-half the replacement fuel costs 1

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. avoided / incurred. Capacity. factors greater than 85 percent and below: 50 l percent (but not below 35 percent) will result in a reward / penalty equal to i

the replacement fuel costs.. The weighted average fuel costs of all Arizona 'l Public Service. Company (APS)-owned generating facilities except Palo Verde and 2

Four Corners' will be used as a proxy for " replacement costs."

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A capacity factor at Palo Verde 1 (PV-1) less than 35 percent'will trigger an i

. automatic reconsideration of APS's last rate case in order to determine l

appropriate rate base' treatment of the unit., Claims by APS for special relief from the penalty clause .due to an " extraordinary event" will trigger an automatic hearing. ,

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The operating incentive's effectiveness was phased in during.1986 as PV-1 achieved commercial operation (after operation at 95 percent of full power for

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100 consecutive hours). The incentive was fully effective after a full 12' i months' commercial operation. '

1 Potential Financial Impacts on Utility I Unit.1 operated at an average of 62 percent capacity for the first one-year ,

measurement period, and thus is in the deadband where no reward or penalty  ;

accrues. Possible penalties and rewards each range up to a total of approximately $8 million per year. This fluctuates based on the cost of replacement power.  !

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ARIZONA Palo Verde 1, 2 and 3-Construction Performance incentive -;

l Regulatory Authority: Arizona Corporation Commission I

l Nuclear Plant: Palo Verde 1, 2, and 3 i

Utility: Arizona Public Service Company l 1

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Status: Initiated November 1984 Measure of Productivity: Construction Cost Cap Type of incentive: Penalty i u

Description:

The Arizona Corporation Commission (ACC) adopted a $2.86 billion l 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 I 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 I

' 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. j l

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- APS estimates that it will cost $2.76 billion to complete its share of all L .three Palo Verde ur.its. ' As of December 1986, APS had spent $2.660 billion on '

all three units,. including $1.146 billion on PV-1 and common facilities, $803-I' million'on PV-2 and $711 million on PV-3. The cap's impact, if any, will not be felt unti_l total expenditures exceed the cap.

. 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.

}iowever, 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 $1.2 million annually; likewise a $50 million imprudent investment in Palo Verde would f

reduce net income by about $5.9 million annually, l

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1 ARKANSAS Arkansas Nuclear'One, Units 1 & 7 Operating Performance Incentive H Regulatory Authotity: Arkansas Pu'blic- Service Connission (APSC)

Nuclear Plant:: Arkansas Nuclear One, Units 1 and ?

Utility: Arkansas Power and Light Company (AP&L)

Status: In effect since , lune 1980 L -Measure of Productivity: Capacity Factor '

.. Type of Incentive:- Reward and Penalty

Description:

In ilune 1980 the APSC established an economic incentive to j 1

partially insulate ratepayers from replacement power costs which could result )i from unplanned outages of Arkansas Nuclear One Units 1 and 2. Major provisions of the program were set as follows: 1. when a nuclear unit is I down for refueling, all replacement power costs are passed to the consur.er;

2. when a nuclear unit is not refueling and has not been shut down for more 3 i

than 30 consecutive days, AP&L is penalized all replacement power costs attributable to the nuclear unit operating below its target capacity factor and keeps any fuel savings attributable to. operating above target. Target L_ -__ -

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capacity factors were set at 72.923% for-Unit I and 71.55% for Unit 2; and

3. For the thirty-first and any subsequent days of any continuous outage, AP&L ,

l is penalized 10% of any replacement power costs associated with that outage.

Before the program was modified (see below), AP&L incurred large penalties.

The company felt that the program was not balanced but was weighted toward penalities with little chance of earning rewards. AP&L has stated that before the modifications, that it had to carefully weigh plant operating decisions to assure that monetary pressures of the performance incentive did not obscure safety concerns.

4 The APSC has modified provisions of this performance incentive as follows:

For the first cumulative 30 days (rather than each consecutive 30 days, as 4 1

before the PSC modification) of outage (other than for refueling) during the 78 week fuel cycle, AP&L is penalized 90 percent of replacement power costs.

For cumulative outages beyond 30 days AP&L is now penalized ten percent of replacement power costs. This is a favorable change to AP&L because, previously, J the 90 percent penalty applied 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  !

1 Potential penalties and rewards both range from zero up to the actual cost of i replacement fuel. The company has not calculated the upper limits of penalties and rewards because they fluctuate with the cost of replacement l

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The largest actual penalty-(for both units combiar.d) attributable to a single

. month was $15 million in November 1980. The. cumulative net penalty (including l some. offsetting rewards) for the period June 1980 through August 1983 was $40 million for both units. It is noteworthy that during this period AP&L's net  !

income'was in the. range-of $65 million to $125 million per year.- Actual performance has improved (and the program has been modified) since that tine such that the cumulative net penalty since 1980 is'less than $20 million.

Rewards were earned during the latter part of this period that offset earlier penalties to an extent.-

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. CALIFORNIA: Diablo-Canyon 1 and 2 'i Operating Performance incentive _

Regulatory Authority: California-Public Utilities Commission (CaPUC)

Nuclear Plant: Diablo Canyon Units 1 and 2

. utility: Pacific 4s and Electric Company (PG&E)

Sta tu s: Initi6ted May 1985 for Unit 1, March 1986 for Unit 2; now discontinued.

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. Measure of-Productivity: Capacity factor i Type of. Incentive: Reward and Penalty

Description:

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A July 1986 decision by the CaPUC established the first year c f corrrnercial operation as the calculation period for the in'certive applicable to Unit 1.

At first, the CaPUC had considered using the longer, fuel cycle (including refueling)asthecalculationperiodforUnit1. Unit I achieved an 88 percent 6verage capacity factor for its first year of commercial operation ended in

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May 1986. . The longer calculation ' period would have lowered the average '

capacity factor below 80 percent for the first fuel cycle.

This-would have put it in the deadband zone (or, null zone) between 55 percent and 80 percent in which no rewards or penalties accrue. ' Average capacity factors above 80 percent would result in a reward equal to'one-half the extra fuel costs saved.

Average capacity factors below 55 percent would lead to a penalty equal to one-half the resulting cost of replacement power.

An incentive program was also applied to Unit 2 with the same range of capacity factors as Unit 1. But the timeframe for calculating the Unit 2 capacity l factor was the fuel cycle (including' refueling time). Unit'2 began commercial  ;

operation in March 1986 and completed the first fuel cycle in iluly 1987 The capacity

• factor was 66 percent for the cycle.

The details of the Diablo Canyon Units 1 and 2 program were taken from the San Onofre Units 2 and 3 program (reported herein) without significant change. The CaPUC staff recommended continuation of the economic incentive program for both Diablo Canyon units, but the PUC has not done so.

The CaPUC and PG&E are 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 go into the utility's rate base. The utility earns both a return on this investment and a return of the investment through

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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. l 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 of output.

Financial Impacts en Utility

. Unit l's first year of commercial operation (through May 1986) at 88 percent capacity factor resulted in a $14 million reward to PG&E, under the capacity factor incentive. The reward was recovered through the fuel adjustment clause in the company's rates.

Unit 2's capacity factor of 66 percent in the first fuel cycle (through iluly -

1987) was in the deadband range. Therefore, no penalty or reward resulted.

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' CALIFORNIA San Onofre 1,'2 and 3  ;

Palo Verde 1, 2 and 3 Operating Performance Incentive l

Regulatory Authority: California Public Utilities Commission:(CaPUC)-

I Nuclear Plant: San Onofre' Units 1, 2 and 3 (SONGS)

Palo Verde Units 1, 2 and 3 i

Utilities: Southern California Edison Company (SCE) (SONGS; Palo Verde)

San Diego Gas and Electric Company '(SDG&E) (SONGS) 1 Sta tus: in effect since September 1983 for-SONGS 2, April 1984 for SONGS 3 July '1986 for SONGS 1, February 1986 for Palo Verde 1 and September 1986 for Palo Verde 2; projected to be in effect for Palo Verde 3 in early 1988 when ,

unit goes into commercial. operation.

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

Description:

In a September 1983 decision, the CaPUC softened the

-reward / penalty provisions that its staff had suggested in the incentive plan proceeding. The CaPUC provided that additional fuel costs resulting from -

SONGS 2 capacity factor below 55 percent and fuel cost savings for capacity l

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factor above 80 percent would be shared equally (50/501 between the company (stockholders) and ratepayers. Performance in the null zone (or deadband) between 55 and 80 percent results in no reward or penalty. The CaPUC staff 1 had recommended that additional costs and savings above and below a 65 percent capacity factor should accrue entirely to the company. The CaPUC thought that standard was too harsh, particularly in the relatively untested area of incentives. The PVC emphasized in its order the utility's obligation to adhere to all NRC rules and regulations. The PilC 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. SONGS Unit 3 was placed under this same incentive (including a null zone of 55 percent to 80 percent capacity factor) when it entered commercial operation in 1984 A similar program was instituted for SONGS 1 in July 1986, however the null zone extends from 55 to 75 percent, meaning that rewards would be triggered above 75 percent capacity factor rather than above 80 percent as with Units 2 and 3. Consistent with CaPUC direction, to provide a more representative measure of SONGS 1 performance, the SONGS 1 capacity factor is based on a 410 MWe gross rating (to reflect operation at a reduced average temperature to inhibit steam generator corrosion). Unit 1 previously had a rating of 456 gross MWe, In the utilities' view, penalties are much more likely than rewards. According to SCE, near perfect operation of Units 2 and 3 with a relatively short refueling period would result in a theoretical maximum capacity factor of 84

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percent, only four percentage points'above the reward trigger. SCE believes d 1

that Units ? and 3 can be. realistically expected to operate below 80 percent-capacity factor on average.. Units 2 and 3 achieved capacity' factors of 57 percent and 56' percent. respectively during the second fuel cycle. The second fuel cycle ended in.May 1986 for Unit 2 -and in February 1987 for Unit 3.

In an October 1986 decision the CaPUC instituted a target capacity factor operating' performance: incentive for SCE's 15.8 percent ownership interest in

' Palo Verde 1, 2. and 3, effective on each unit's commercial operation date. The mechanism is substantially identical to the procedure in effect for SONGS 2 and 3. ,

Potentia'l Financial Impacts on Utilities i Potential financial impacts are examined for SONGS' 2 and 3, of which' SCE l owns a majority interest. SCE's minority interest in the Palo Verde units would result in smaller . potential rewards and penalties. Penalties and rewards under the SONGS 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. A long-term outage would otherwise cause incentive plan penalties.

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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 l 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. j The first fuel cycle period for SONGS 2 and 3 resulted in capacity factors of 55.3 percent and 54.6 percent, respectively. Since the first cycle for SONGS 3  ;

resulted in slightly less than the target capacity factor, a penalty of

$566,000 was assessed. This is paid through a change to the company's fuel adjustment clause. As noted above, the second fuel cycle, the most recently completed for the two units, resulted in capacity factors of 57 percent for

' SONGS 2 and 56 percent for SONGS 3. Since these results were in the deadband range (55-80 percent), no other penalties or rewards resulted. As discussed above, the SONGS 1 incentive program began in the summer 1986 Based on operation to date and SCE projections, the end-of-fuel-cycle capacity factor for SONGS 1 is estimated to be approximately 70 percent. (The current fuel cycle (Cycle 9) is scheduled to be completed in mid-1988.) Such a result would be in the SONGS 1 deadband (between 55 and 75 percent) and thus would result in no j penalty or reward. The actual SONGS 1 capacity factor for Cycle 9 through July 1987 was 67 percent.

Note: In an October 1986 decision the CaPUC followed its staff's recommendation and disallowed $265 million of SONGS 2 and 3 capital costs on the basis that SCE (1) was responsible for licensing delays that slowed the  !

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.j overall completion of the project,'and (2) otherwise unreasonably delayed the startup' I

of.the units. : As previously reported to'the NRC staff, SCE vigorously denied ' .j

' that it caused unreasonable delays. The disallowed amount can 'neither be -

recovered through depreciation charges nor can a return be earned on it. It is noted 'that'.the CaPUC's administrative law judge who had presided ove'r the prudency proceeding recommended to the CaPUC that'there be no disa:lowance, i

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i COLORADO. Fort St. Vrain' Operating' Performance incentive Regulatory Authority: Colorado Public Utilities. Commission (CPUC)

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.i Nuclear Plant: Fort St. Vrain Utility:- Public Service Company of Colora'do (PSCO)

, Status: : Discontinued September 1986 Measure of Productivity: Capacity Factor .

l Type-of Incentive: Penalty 1

Description:

' In December 1980, the CPUC ordered that PSCO would have to refund the rate base return on common equity on Fort St. Vrain to the ratepsyers if the plant did not achieve a 50 percent capacity factor

. performance in the test year. The 50 percent capacity factor was based upon 200 MW net capacity, exclusive of scheduled downtime for maintenance anc refueling. The incentive program was developed in response to problems With the plant's helium gas-cooling system and required the refunds if the nuclear plant was'not sufficiently reliable.

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'1 The incentive program was subsequently revised to' base refunds on a rolling 12-month average capacity factor. If this average was less than 53 percent 3

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the plant remained nonoperational the monthly penalty increased as the f l

rolling average capacity factor fell, reaching a maximum refund of $3.8 l million per month when the plant was out of service for 12 months. The program made no provision for rewards.

Financial Impacts on Utility

-Fort St. Vrain did not generate electricity for most of 1984, 1985 and 1986 and for part of 1987 due to a scheduled refueling operation, engineering  !

modifications and environmental qualification activity. The maximum incentive plan penalty of $3.8 million per month was accumulating during this period. Also during this period, PSCO was involved in several administrative and legal proceedings regardf ng rates and revenues associated with the plant. l In September 1986, PSCO entered into a settlement agreement which concluded all of the proceedings. The settlement provided, among other things, that PSCO remove Fort St. Vrain from its rate base, that PSCO pay to customers

$73 million in penalties accumulated under the performance incentive plan, and that the incentive plan be discontinued. PSCO is now engaged in a corporate 4 cost containment and financial recovery program.

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-CONNECTICUT Millstone 1, 2, and 3 Yankee Plants Operating Performance Incentive. 1 1

Regulatory Authority: Connecticut Department of Publi_c Utility Control (CDPUC) i 4

Nuclear Plants: Millstone 1, 2, and 3 j Yankee Plants (four units)

' Utilities: Connecticut Light & Power Company (CL&P) >

Northeast Nuclear Energy Company (NNEC)-

Status: in effect since June 1979 Measure of Productivity: Capacity Factor Type of incentive: Penalty only (no rewards)

Description:

For actual composite nuclear capacity factors above 70 percent, the savings in replacement fuel cost- by using nuclear generation rather than oil are credited to customers. CL&P receives no reward and pays nothing extra. For actual capacity factors between 55 percent and 70 percent, l customers pay the differential between replacement fuel (normally oil) costs l

and nuclear fuel costs. The utility's only incentive (as a result of this program) is to avoid actual capacity factors below 55 percent where it must bear the differential between replacement fuel usts and nuclear fuel costs.

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' Potential Financial-Impacts on Utility .j The only potential financial impact on CL&P is that it must absorb a portion of-l replacement fuel costs when the nuclear capacity factor is below 55 percent. l Neither the utility nor the PVC have quantified'the potential penalty. It would be based on the actual differential between oil and nuclear fuel costs. j 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 - y months ended July-31,1987 was 74.2 percent. The utility's projected capacity 'l

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FLORIDA Crystal River 3 St. Lucie 1 & 2 Turkey Point'3 & 4 .

Operating Performance incentive

' Regulatory Authority: . Florida Public Service Commission (FPSC)

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Nuclear Plants: Crystal River 3 (FPC)'

St. Lucie ILa ? (FP&L)

Turkey Point 3 & 4 (FP&L)

Utilities: Florida Power Corporation (FPC)

Florida Power and Light Company (FP&L) l

' Status: In effect since September 1980

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Measure of Productivity: Equivalent Availability; Heat Rate )

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Description:

The incentive program goal is to minimize fuel and purchased power costs. The program uses complex formulas to link the rate of return l allowed on common equity to heat rate and equivalent ' availability of power  !

generating units. _ Targets are set for heat rate and equivalent availability

-based on historical performance and any improvements. Computer runs simulate fuel cost impacts over the expected range of operating results. Rewards or i

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penalties are determined by comparing actual operating values' with targets set for equivalent availability and average heat rate. Rewards and penaltie's may be up to 0.25 percent of return on common equity, j Potential Financial Impacts' on Utilitie_s,s Florida Power Corporation

. Possible net penalties and possible net rewards (attributable to Crystal River Unit 3) both range from zero to $1.0 million every six months, t

i The company incurred the 'following net rewards (+) and net penalties (-) for i the six-month periods indicated:

i, 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 April '86 - Sept '86 (not applicable - see below)

October '86 - March '87 - $975,000 l l

l The utility indicates that penalties beginning in the summer 1985 period  !

were caused primarily by a refueling outage from July through August 1985 I and. limited availability subsequent to that. A forced outage from January 1985 through June 1986 contributed to the winter '85 '86 penalty. Crystal

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- River 3 was temporarily removed from the program in the April-Sept 1986

-l period because of a six-month outage to repair a reactor coolant pump shaft. q Two forced outages related to reactor coolant pump seal failures caused the penalty for the winter '86 '87 period.

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1 Potential Financial Impacts on Utilities, continued Florida Power and Light Company 4

Possible net penalties and possible net rewards (attributable to each nuclear unit) both range form 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.

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April '85 October '85- April '86 1

Sept. 85 Ma rch '86 Sept. '86 Possible Actual Possible Actual Possible Actual Turkey Point 3 $1.3 - $0.3 $1.3 - $1.1 $1.3 - $0.4 Turkey Point 4 $1.1 + $0.6 $1.1 + $1.0 $1.1 - $0.9 St. Lucie 1 $1.2 + $1.0 $1.2 + $1.2 $1.2 St. Lucie 2 $1.2 - $0.9 $1.2 +$1.2 * $1.3 + $1.3 j

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. FLORIDA' St. Lucie 2 Operatinp Performance Incentive )

i Regulatory Authority: Florida Public Service Commission 1

Nuclear ~ Plant: St. Lucie ?

l 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 l

only applicable within a 75 to 100 percent capacity factor range. No reward  !

could exceed total fuel savings.

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Potential Financial Impacts on Utility i

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.

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1 MARYLAND Calvert Cliffs 1-& 2 ll 2 Operating Performance incentive -

Regulatory Authority: Maryland.Public Service Commission (MPSC)

. Nuclear Plant: Calvert Cliffs 1 and 2 j I I

litility: Baltimore Gas and Electric' Company'(BG&E)

' Status:- Pending; case-by-case reviews of individual. unit outages continue

'while MPSC considers various' proposals for a formularized incentive plan, f

Measure'of' Productivity: Capacity factor (one proposed plan)

Type of Incentive: . Rewards and Penalties (one. proposed plan)

Description:

I The' MPSC policy of conducting reviews of individual unit outages continues.

By statute, actual electric fuel costs are recoverable so long as the MPSC 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 Maryland's highest appellate Court have interpreted this as permitting i

a' subjective evaluation of each unplanned outage at the company's generating a

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4 plants. This is 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 MPSC 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 BG&E plants.

BG&E and other Maryland utilities have filed proposals for a formularized 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. The MPSC is also considering various other proposals and a decision date is uncertain.

Potential Financial Impacts on Utility:

Potential financial impacts have not yet been quantified.

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MASSACHUSETTS Pilgrim

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Operatino Performance Incentive Regulatory Authority: Massachusetts Department of Public Utilities (MDPU)

Nuclear Plant: Pilgrim Utility: Boston Edison Company (BEC0)

Status: In effect since August 1981; revised in 1983 and 1985 Measure of Productivity: Availability; Heat Rate Type of Incentive: Penalty

Description:

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.

BECO's plant performance is compared with the plant performances of a selected group of companies (using separate analyses for fossil and nuclear units). The MDPU selects the sample to analyze. The MDPU sets optimal equivalent availability targets 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.

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l l There is no cap on the amount of. penalty except up' to the full amount of the l-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 l l penalties: .the first penalty in 1984 of about>$4.5 million related to downtime

' for pipe replacement and chemical decontamina. tion; 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. Pilgrim experienced a significant outage in 1987. At report time the MDPU had not acted on the financial effect of the outage and had not assessed a penalty under this incentive.

The MDPU is expected to hold bearings on this issue after the plant is restarted.

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I MICHIGAN Fermi 2 i

Operating Performance Incentive- l l

l Regulatory Authority: Michigan Public Service Commission (MPSC)

Nuclear Plant: Fenni 2 i

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Utility:- Detroit Edison Company (DE)

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Status:. Incentive proposal has been submitted to MPSC administrative law l judge; MPSC decision expected by year-end 1987.

Measure of Productivity: Capacity factor I 1

Type of Incentive: Penalty only (no rewards)

Description:

The MPSC staff's proposal is now being considered by the administrative law judge. The judge will send a recommendation to the MPSC.

The proposal states that the average annual capacity factor'for the unit should be at least 60 percent. Actual capacity factors below that would result in disallowed replacement power costs. The lower the capacity factor, the higher the percentage of costs disallowed. The disallowed costs could not be passed on to customers though rates. The staff's proposal includes a $15 million annual cap on penalties that could be levied under the performance incentive. Industrial customer interveners have recommended that there be no

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1 penalty cap.-

-There is.no provision for incentive rewards.

Potential Financial Impacts on Utility  !

The annual cap on penalties, if included in the final version ~ of this incentive,

.would limit the company's exposure. Extensive outages or very low capacity factors could result in penalties up to the $15 million cap. Potential j penalties .without a cap could be much larger.

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i MICHIGAN Palisades  !

Operating Performance incentive 1

Regulatory Authority: Michigan Public Service Commission (MPSC)

Nuclear Plant: Palisades Utility: Consumers Power Company (CPC)

Status: Administrative law judge submitted incentive proposal to MPSC in May 1987; decision expected by year-end 1987.

Measure of Productivity: Capacity factor Type of Incentive: Penalty only (no rewards)

Description:

The proposal now being considered by the MPSC was formulated by l l

the MPSC staff. The MPSC administrative law judge, however, made a significant j

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modification to the staff's proposal: The $5 million annual cap on possible penalties to CPC is removed. The incentive proposal as it now stands could result in many millions of dollars in penalties annually, if the average l l

capacity factor is very low. Industrial customer interveners had recommended {

l removal of the penalty cap.

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j The proposed incentive states that the average annual capacity factor for the '

uilit should be at least 60 percent. Actual c.apacity factors below that would j l

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, result in disallowed replacement power ' costs. The lower the capacity factor, j the higher the percentage of costs-disallowed.. The disallowed costs could not be passed on to customers through rates.

There is no provision for incentive rewards.

i-Potential Financial Impacts on Utility CPC indicates that replacement power for Palisades costs roughly $200,000 per day. The unit experienced an outage from May 1986 to April 1987 and also had substantial downtime in 1983, 1984 and 1985. Although the performance incentive was not in effect at that time, such outages would result in very significant penalties under the provisions of the proposed, capless incentive.

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MICHIGAN Big Rock Point U Palisades Operating Performance Incentive Regulatory Authoritq, . Michigan Public Service Commission

-l Nuclear-Plants: Big Rock Point Palisades l

Utility: Consumers Power Company Status: Discontinued-  !

Measure of Productivity: Availability Type of Incentive: Reward and Penalty

Description:

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 j 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 I availability goals were met.

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i Potential Financial Impacts on Utility Financial impacts have not been calculated because this incentive has been  !

discontinued..

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i MISSISSIPPI' Grand Gulf 1 i

Operating 1%r[eymanceIncentive '

i Regulatory Authority: Mississippi Public Service Commission (MPSC)-

Nuclear Plant: Grand Gulf 1 Utility: Mississippi Power and Light Company (MP&L)

Status: MPSC implemented (in mid-86) an incentive for Mississippi Power Company, a non-nuclear subsidiary of the Southern Company. After a'36-month trial' period, the MPSC will consider a modified incentive for MP&L's Grand Gulf-1.

Measure of Productivity: Multiple Performance Parameters Type of Incentive: Allowed revenues (rates) are determined by formula which weights the performance parameters

Description:

During the current trial period, this performance incentive is applicable only to Mississippi Power Co. (MPC) which has only fossil generation.

Performance parameters in the incentive formula include: (1) a construction performance cost cap with penalties for cost overruns; (2) contribution to load factor; (3) results of a customer satisfaction survey; (4) residential service cost; (5) equivalent availability; and (6) service reliability (factorofunplannedoutages). Another factor in this incentive is a comparison of MPC earnings to those of utilities with the same credit rating.

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The parameters are applied'to a performance formula each calendar quarter in

, order to calculate the rate base .and revenue requirements.

The MPSC staff indicates 1that the current program applicable to MPC is a " test case." Substantial modification could be made to the program before considera-tion is. given to performance-based programs for other utilities, such as MPAL.

Potential Financial-Irpacts on Utilities The potential impact of a performance-based rate-setting plan is quite significant in that the revenues (rates) of a company are determined directly  !

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NEW JERSEY -Salem 1 and 2-Peach Bottom 2 and.3 Hope Creek Oyster Creek Three Mile Island 1 Operating Performance Incentive Regulatory Authority: New Jersey Board of Public Utilities (NJBPU) j l

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. Nuclear Plant: Salem 1 and 2 (PSE&G and ACE)

Peach Bottom ? and 3 (PSE&G and ACE)

Hope Creek'(PSE&G and ACE)

OysterCreek(JCP&L)

TM11(JCP&L) i utilities: Public Service Electric and Gas Company (PSE&G)

Atlantic City Electric Company (ACE)

Jersey Central Power and Light Company (JCP&L)

I Status: In effect since February 1987 for Salem, Peach Bottom and Hope Creek; I September 1987 for Oyster Creek and THI-1.

Measure of Productivity: Capacity Factor 1

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-Type'of-Incentive: Reward and Penalty .i i

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Description:

' Vsing PSE8G as the-example, .the performance measurement, or standard, by which  !

plant performance is evaluated, is the PSE&G combined annual average capacity factor for Hope Creek, Peach 8ottom 2 and 3 and Salem 1 and ?. The capacity factor. is :the ' ratio of the ' amount -of electricity actually generated by a plant

'during a given period to the' total amount of electricity that is-theoretically

j capable of.being produced during that period.

Under the provisions of the new New Jersey performance incentive,' a target capacity factor of:70 percent is established. A "deadband" of plus or minus a

'10 percent around the target, or between 60 and 80 percent, is also established in which no reward or penalty accrues. If the average capacity factor for all five units is between 60 percent and 80 percent, the utility will recover fuel costs as usual. If the five units' overall operating average is between 80 percent and 90 percent of capacity, the company will be '

able to keep 20 percent of the replacement power savings as figured from the 70 percent benchmark. If the performance average is better than 90 percent, the utility will be permitted to keep 25 percent of the savings.

For capacity factors between 50 percent and 60 percent, the company may charge customers for only 80 percent of replacement power costs. Thus, the penalty for capacity factors in this range is 20 percent of replacement power costs.

The penalty for capacity factors below 50 percent and at or above 40 percent is a disallowance of 25 percent of replacement power costs. For capacity

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factors below 40 percent, any penalty will be based on a special review of i the circumstances by the:NJBPU including the company's explanation of causes,

q. Financial Impacts on Utilities The'NJBpu'found (in its February 1987 decision) that penalties under the incentive program would be significant, but not disastrous to the utilities.

For example, if PSE8G achieved an aggregate 60 percent capacity factor from all '

its nuclear units, there would be no penalty. A 59 percent aggregate

- capacity factor would result in a $7.7 million penalty; a 50 percent' aggregate capacity factor would result in a $17.5 million penalty; and a.30  !

i percent aggregate capacity factor would result in a $46 million penalty.

The NJBPU also discussed unwanted side effects that might theoretically result. i l

from the performance-incentive program. These possible, unwanted effects are.

J excessive operation, maintenance and capital expenditures designed to increase ,

capacity factor but that are not necessary for safe and efficient plant i

- ope ration. The New Jersey program addresses these concerns by providing that the NJBPU will monitor the cost effectiveness of such expenditures. The utilities will file reports periodically with the NJBPU on nuclear plant expenditures to aid in the monitoring. (The concern about excessive l expenditures to increase capacity factor has been raised by other PUCs that I use performance incentives. Such expenditures would presumably be passed on  !

to ratepayers unless disallowed by the PUCs.)

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NEW JERSEY Hope Creek i Construction Performance Incentive

~ Regulatory Authority: .New Jersey Board of Public Utilities (NJBPU)

Nuclear Plant: Hope Creek l

Utilities: 'Public Service Electric and Gas Company i Atlantic City Electric Company  !

1 Status: NJBPU decision on prudency and cost allowances issued in February 1987. (Program first initiated in July 1983.)  !

Measure-of Productivity: Total construction costs-Type of Incentive: Reward and Penalty l 9

Description:

The Hope Creek program, now concluded by a February 1987 NJBPU order, provided for both penalties and rewards. Its objective was to. control construction costs. Through negotiation between NJBPU and Public Service Electric & Gas Co. (PSE&G) the target construction cost was set as $3.76 billion. The basic incentive formula provided that PSE&G would recover from customers only 80  !

percent of costs that exceeded the $3.76 billion target by up to 10 percent.

Had costs exceeded this target by more than 10 percent, the company would

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l recover only 70 percent of costs above the 10 percent threshold. If the plant cost was between $3.5 billion and $3.76 billion, all actual costs would be recovered. If the total cost had been below $3.5 billion, the reward provision becomes operative and the company would recover actual costs plus 20 J percent of the difference between $3.5 billion and the actual costs. Thus, the program's incentive was to complete construction at a cost below $3.5 billion to recoup the 20 percent reward, and to avoid penalties resulting from cost overruns.

Financial Impacts on Utilities Hope Creek was completed in 1986 at a total cost to the two utilities of

$4.475 billion (includir.g $4.25 billion attributable to PSE&G's 95 percent j ownership interest in the plant). In its February 1987 decision the NJBPU )

I disallowed $516 million ($489 million PSE8G) of the total, leaving $3.96 l l

billion ($3.76 billion PSE&G) to go into rate base. The disallowed amount cannot be recovered through depreciation over the plant's useful life nor can it earn a return by inclusion in the companies' rate bases. In effect, the NJBPU allowed $200 million above the $3.76 billion cost cap for reasons both of the cost cap formula and the NJBPU's construction prudency investigation.

The greatest impact of the capital cost writeoff on PSE&G was a reduction of 1

its 1986 earnings in the amount of $251 million, or $1.86 per share. PSE&G l l

15 a wholly-owned subsidiary of Public Service Enterprise Group, Inc.

(Enterprise). Enterprise's 1986 consolidated net income and earnings per share (af ter the reduction) were $378 million and $2.84, respectively.

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design and construction deficiencies documented in System Deviation Reports j prepared during the start-up testing phase. The deficiencies were shown to I have resulted from a. prior unreasonable activity, which, if it had been ,

l performed reasonably at the time, would have ruled out the deficiency. The l NJBPU disallowed $8.6 million of contract costs of a firm that went bankrupt during the project and failed to complete its work on the radiation monitoring system. Findings of poor productivity by some contractors on the project resulted in a $132 million disallowance. Construction delays cited by the NJBPU resulted in an $86 million disallowance. The above disallowances were j all based on findings that the cost of the disallowed work was unreasonable, i

and should not be borne by customers.

It is noted that the NJRPU also approved depreciation expenses for the Hope Creek plant at the rate of 3.11 percent per year, reflecting the 39.25-year j l

time period remaining in the term of the company's 40-year operating license. I I

The company had sought a 4 percent depreciation expense rate, based on an anticipated average nuclear plant life of 30 years.

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NEW MEXICO Palo Verde 1 l Operating Performance Incentive Regulatory Authority: New Mexico Public Service Commission (NMPSC) j Nuclear Plant: -Palo Verde 1 j I

Utility: Public Service Company of New Mexico (PSCoNM) i l

Status: In effect since January 1984 Measure of Productivity: ' Excess Generation Capacity l

Type of Incentive: Penal ty i

Description:

When a coal-fired unit 'and the Palo Verde plant came on line, i

'the NMPSC ruled that PSCoNM had generation plant in excess of its requirements.

The NMPSC ' stipulated that plant will be allowed in rate base only to the level i- of the system. peak plus 20 percent reserve margin. The remaining plant will be inventoried. The inventoried plant will be the newer plants and will earn interest on construction costs (AFUDC), which will be amortized over the 1

remaining life of the plant once it comes out of inventory. PSCoNM must file a, report by October 1 of each year to the NMPSC. After opportunity for public hearing, the NMPSC determines the amount that must be inventoried for the

-following year.

., w 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 bettennents (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 4 on AFUDC. The.. program affects how load is dispatched. It applies only to retail' sales. Thus PSCoNM would attempt to avoid FERC-regulated sales (wholesale)  ;

from inventoried plants. The aims of this economic incentive are to shield i

the ratepayers from the t' ate shock associated with large additions to rate base, provide some' protection for shareholders and give PSCoNM an incentive to make off-system sales from the excess capacity.

Potential Financial Impacts on Utility 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, PSCoNM 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 PSCoNM to the NMPSC with regard to ratemaking. It is uncertain how this sale and leaseback will affect the incentive program; I however, it can reasonably be expected to be minor. .

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1 NEW YORK Nine Mile Point 2 Construction Performance Incentive (Construction cost. disallowance settlement) l I

Regulatory Authority: New York Public Service Commission Nuclear Plant: Nine Mile Point ?

' Utilities: Niagara Mohawk Power Corporation (lead licensee)

Central Hudson Gas and Electric' Corporation Long Island Lighting Company New York State Electric and Gas Corporation J Rochester Gas and Electric Corporation i

Status: Initiated February 1982; construction cost disallowance settlement approved by New York Public Service Commission on October 3, 1986.

Measure of Productivity: Total construction costs Type of Incentive: Construction cost disallowance settlement

Description:

A 1984 New York Public Service Commission (N.Y. PSC) decision increased a construction cost cap on Nine Mile 2 from $4.6 billion to $5.4 billion. The cap was designed to control power plant construction costs. It was instituted because of escalating construction costs and uncertainty of completion dates.

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4 In July:1985, the N.Y. PSC initiated an investigation into the prudence of-1 Nine Mile 2 construction costs. This led to a joint settlement agreement offer agreed to by the five utility co-owners and the N.Y. PSC staff. The offer, approved by the N.Y. PSC in October 1986, replaces provisions of the previous incentive plans and substitutes a $4.16 billion total construction l cost cap on the facility. The settlement includes no admission of imprudence.

l Under the settlement agreement, costs up to the new cap will be recovered from ratepayers; all excess costs will be borne by the utilities and their stockholders. In extraordinary circumstances, the PSC will 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 $5.87 billion (including CWIP benefits), creating a $1.991

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billion disallowance (adjusted for the inclusion of construction work in progress in rate base in the amount of $273 million).

Potential Financial Impacts on Utilities Under the terms of the settlement agreement, Niagara Mohawk will bear approximately $1.001 billion of the projected $1.991 billion disallowance.

Niagara Mohawk owns 41 percent of the unit but will bear a somewhat higher percentage of the disallowance because of an agreement with the other four co-owne rs . Assuming a 40-year plant life, Niagara Mohawk will be penalized approximately $109 million in earnings available for common stock on a levelized basis per year for the life of the facility.

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NEW YORK Ginna Indian Point 2 Nine Mile Point 1 and 2 Safety Performance Incentive Regulatory Authority: New York Public Service Commission (NYPSC)

Nuclear Plants: Ginna (RG&E)

Indian Point 2 (Con Ed)

Nine Mile Point I and 2 (NMPC)

Utilities: Rochester Gas and Electric Corporation (RG&E)

Consolidated Edisen Company (Con Ed)

Niagara Mohawk Power Corporation (NMPC) i i

Status: NYPSC proposal released February 20, 1997 for public comment.

NYPSC now reviewing proposal in light of public comments.

Measure of Safety Performance: NRC Systematic Assessment of Licensee Performance (SALP) ratings; NRC civil penalties (fines)

Type of Incentive: Rewards and penalties to utilities; salary bonuses for )

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.If implemented, this proposal would be the first nuclear safety performance

. incentive with monetary. penalties and rewards established by a State public utility commission'(PUC). It would also be the first PUC-established performance. incentive to use NRC ratings such as SALP ratings and civil penalties (fines) as the basis for determining rewards and penalties to utilities and salary bonuses for nuclear plant workers. The proposal incorporates a rating plan, linked to the SALP scoring, for determining whether, and to what extent, a utility operating a nuclear plant would be entitled to a reward (in which the nuclear plant workers would share) or be subject to a penalty. The rewards and penalties would be recovered (paid) through the utility's fuel adjustment clause. An integral- factor in the proposal is a mechanism for providing cash bonuses directly to employees of a nuclear plant < that qualified for a safety-related incentive payment. No penalty, however, would be assessed against the employees of a- plant. The SALP rating and trends in the rating would be the primary determinant of rewards to utilities and workers and of penalties to utilities. Further, the NRC system of fines for violation of safety rules would be used to determine if a utility should be denied a safety-related award for which it might otherwise qualify.

Potential Financial Impacts on Utilities The maximum reward or penalty for a utility in any year would be linked by the proposal to the allowed return on common equity used in the utility's previous 1

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rate case. The amounts would be about $1.4 million for RG&E (Ginna plant),

$5.0 million for NMPC (Nine Mile Point I plant), and $8.0 million for Con Ed i

(Indian Point 2 plant). For a utility with more than one nuclear plant, such I as NMPC, each plant would be subject to the same maximum reward or penalty allowance under the proposal.

NpC Comments on Proposed incentive: In response to the NYPSC's request for public comment on the proposal, the NRC provided detailed comments by letter dated May 26, 1987. NRC expressed concerns about several aspects of the proposal. These included a concern that the prospect of financial rewards for utilities, based on SALP ratings, might change the focus of the SALP process  ;

to the ratings themselves rather than on the underlying issues that give rise i

to the rating. NRC indicated that it does not support use of SALP numbers or enforcement history to arrive at financial rewards and penalties. NRC said it was also concerned about the potential effect of the proposal on the openness of communication between nuclear plant staff and NRC personnel. An example of 4

such concern would be the prospect that an individual's cash bonus might be adversely affected as a result of disclosing safety significant information to the NRC. In addition, NRC expressed concern that the proposed program would impose a large penalty on a licensee for minimally satisfactory performance.

In such cases the NRC may have determined that nuclear safety perfonnance needs to be improved, but substantial economic penalties could reduce resources that might otherwise be spent to improve weak performance areas. NRC also said that the NYPSC proposal may be understood to focus on nuclear safety rather than economic operation of nuclear plants, and thus may interfere improperly with exclusive Federal regulatory authority over nuclear safety matters.

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. . NORTH CAROLINA- Brunswick 1 & 2 Robinson Oconee 1, 2 & 3 Catawba 1 McGuire 1 & 2 Surry 1 & 2-North Anna 1 & ?

Operating Performance Incentive Regulatory Authority: North. Carolina Utilities Commission (NCUC)  !

Nuclear Plants: Brunswick 1 and 2 (CP&L) McGuire 1 & 2 (Duke)- ,

i Robinson (CP&L) Surry 1 & 2 (VPC)

Oconee 1, 2 & 3 (Duke) NorthAnna1&2'(VPC)

Catawba 1 (Duke)

Utilities: Carolina Power and Light Company Duke Power Company i Virginia Power Company i

Status: In effect since June 1982 Measure of Productivity: Capacity Factor Type of Incentive: Reward and Penalty I. ..

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Description:

The North Carolina Utilities Commission (NCUC) allows' electric  !

utilities.to include a fuel charge adjustment'as a rider to their rates. For j 1

each utility engaged in the' generation and production of electric power by .[

fossil or nuclear fuels, the NCUC holds a full evidentiary hearing to determine

- whether an increment or decrement rider is in order. This total fuel factor amount can be reset only 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 NCUC is to use lifetime average capacity factor by unit.

The NCUC 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 NCUC has adopted a limitation on the 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. These provisions were invalidated in a 1987 State supreme court action, but the legislature subsequently passed (in July 1987) new enabling legislation for the incentive program. The legislation specifies a two-year trial period through July '1989 at which time the legislature may address the issue again. The program keys l

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 ]

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' Another incentive program relates to the utility's allowed rate of return.

The NCUC'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 Virginia Power since the majority of its service area is not in North Carolina.

Carolina Power and Licht. 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 113 million," according to the company, but no evaluation has been done as to the exact amount. No other penalties or rewards have been received since passage of the 1987 state law that validated the program.

Duke Power Company. The NCUC indicated in a decision that Duke's excellent performance and management were factors in determining the company's allowed rate of return. No dollar figure was attached to this " reward." No other penalties or rewards have been received since passage of the 1987 state law that validated the program.

OHIO Davis-Besse Operating Performance Incentive Regulatory Authority: Ohio Public Utilities Commission (0PUC)

Nuclear Plant: Davis-Besse l

Utilities: Toledo Edison Company (TE) 1 Cleveland Electric Illuminating Company (CEI) i Sta tus: In effect since February 1981 Measure of Productivity: Combination of operating efficiency measures Type of Incentive: Reward and Penalty

Description:

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 objective of the program is to minimize the cost of electric service to customers by providing incentives to the utility to minimize its costs.

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L 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 los's adjustment. ,

' At each six-month ~ test period- there. is always an under-recovery or -

.over-recovery of fuel costs ;because the expected fuel costs-and actual fuel costs for the period are different. If the utility's efficiency. measures are

.. above'an acceptable level, the utility does not have to absorb all of the fuel cost under-recovery, nor do they have to refund all of the over-recovery.

In practice, the program works more as a positive reward than as a penalty.

However, in the long run, customers are not expected to pay more than they would without the program.

Potential Financial Impacts on Utility

.There is a cap on over-recovery but not on under-recovery. No real effort has been made to isolate'the actual impact of the program on revenues. .

l The maximum ' penalty or reward is estimated to be between $500,000 and $1 million .)

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OREGON Trojan Operating Performance Incentive Regulatory Authority: Oregon Public Utility Commission (OPUC)

Nuclear Plant: Trojan  ;

I Utility: Portland General Electric Company (PGE)

Status: In effect since 1980 Measure of Productivity: Fuel and Purchased Power Costs Type of Incentive: Reward and Penalty l

Description:

The Power Cost Adjustment Program sets targets for fuel and .

purchased power costs, estimated quarterly, as part of regular rate case l proceedings. At the beginning of the quarter variable operating costs are q estimated based on expected use of thermal and hydro plants. At the end of  ;

i the quarter a comparison is made with actual costs. The reward / penalty '

incentive associated with this program enables 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.

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This is a company-wide program and is greatly impacted by how much the hydro

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capacity is used. If. Trojan operates well this improves company-wide cost  !

I 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 ef fect is to reduce utility earnings.- - The base rates were set i 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.

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PENNSYLVANIA Limerick 2 l Construction Performance Incentive ,

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Regulatory Authority: Pennsylvania Public Utility Commission (PaPUC)

Nuclear Plant: Limerick 2 Utility: Philadelphia Electric Company (PECO)  !

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Sta tus: In effect since December 1985 i

Measure of Productivity: Total Construction Costs (Cost Containment) l

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Description:

The PaPUC, in an order dated August 7,1984, ordered an

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investigation as to whether the completion of Limerick Unit No. 2 would be in j l

the public interest. On December 5,1985, the PUC issued an order concluding j that PECO could complete the construction of Unit 2 conditioned upon the l acceptance by the company of the cost containment and operational incentive plans set forth in the order. The cost containment plan specifies that (1) the maximum net rate base allowance for Unit 2 (exclusive of common plant) shall never exceed a prudent investment of $3.197 billion; (2) any of the investment (including subsequent capital additions) excluded by reason of the $3.197 billion limitation shall not be. recovered from ratepayers through ,

depreciation expense or otherwise amortized; (3) any of the initial investment (excluding capital additions as referenced in (4) below) excluded by reason of

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[ .l the $3.197 billion limitation shall not thereafter receive rate base recognition, in whole or in part, by reason of the reduction of net investment through i depreciation accruals; and (4) any capital investment which occurs subsequent-l to conrnercial operation shall receive rate base recognition, only to the extent that the total net investment for ratemaking purposes does not exceed l

$3.197 billion. If a cost lower than $3.197 billion is determined by the PUC to be;the prudent investment, that lower cost would be the initial rate base allowance, and subsequent rate base allowance.s would be limited to a net rate  ;

base allowance not to exceed $3.197 billion. In addition, the PUC refused to permit any adjustment to the cost limitation for inflation or regulatory scope  ;

changes.

The operational incentive plan for Limerick 2 is discussed under a separate heading in this report.

In a related matter, the Commonwealth of Pennsylvania adopted (on July 6, 1984) a law providing that, when an electric utility requests a rate increase l

based in whole or in part on the cost of construction of on electric generating facility, the PVC must compare the actual cost of construction, as indicated by the rate request, with the estimate submitted at the commencement of construction. The law provides that, if the actual cost exceeds the estimated cost, the PVC must exclude the excess from the utility's rate base unless the utility can show that some or all of the excess was necessary .and ,

proper. (The principle of allowing recovery of only those costs deemed to be prudently incurred is followed by all PUCs we are aware of.)

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Potential Financial Impacts on Utility  ;

As of July 1987, PECO has spent approximately $1.6 billion on Limerick 2, exclusive of common plant. (As noted above, the construction cost cap does not apply to common facilities.) PEC0's current estimate of the final cost of the unit is $3.197 billion assuming that it is placed in commercial i

operation in late 1990. The magnitude of a potential penalty would depend on the amount of the cost overrun, if any. The penalty would be in terms of (1) lost depreciation expense on any investment above the cap, and (2) exclusion of any excess cost from the rate base upon which the company l earns a return. Neither of these items could be recovered through rates charged.to customers over the useful life of the facility, i

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-PENNSYLVANIA Limerick 2 Operating Performance Incentive i i

' Regulatory Authority: Pennsylvania Public Utility Commission (PaPUC) i Nuclear Plant: Limerick 2 Utility: Philadelphia Electric Company (PECO) i Status: Will take effect when unit is operational (est. late 1990) i Measure of Productivity: Capacity Factor l Type of Incentive: Reward and Penalty i

Description:

The PaPUC, in an order dated August 7,1984, ordered an investigation as to whether the completion of Limerick Unit No. 2 would be in the public interest. On December 5,1985, the PVC issued an order concluding i

that PECO could complete the construction of Unit 2 conditioned upon acceptance by the company of the construction cost containment and operational incentive plans set forth in the order.

The ' operational incentive plan specifies that (1) the established annual' i capacity factor that Unit 2 is expected to attain is 65 percent; (2) the targeted capacity factor will be increased in those years when Unit 2 is not scheduled for refueling and decreased in those years when refueling is 4

scheduled, with the appropriate amount of the increase or decrease to be

l de'termined during general rate increase proceedings applicable to Unit 2; (3) operations within a range of 5 percentage points of the targeted capacity factor will not result in either an incentive or penalty; (4) the energy cost savings resulting from operating more than 5 percentage points above the targeted capacity factor shall accrue to the stockholders 'and will not be  !

reflected in the ratemaking process, in an amount not to exceed 5 percent of the common equity investment in Unit 2; (5) the additional energy costs incurred as a result of operating more than 5 percentage points below the

. j targeted. capacity factor shall not be recovered by the Company, except to the )

extent.that the additional expense shall exceed 10 percent of the common equity investment in Unit ?, and (6) the collar amount of the incentive / penalty l will be established for the life of the plant in the initial Unit 2 l general rate proceeding. In addition, the order directs the PaPUC staff to develop a program, utilizing data from other nuclear plants, for monitoring operation and maintenance expenses associated wth Unit 2. I i

A construction cost containment incentive plan for Limerick 2 is discussed l under a separate heading in this report.

Potential- Financial Impacts on Utility As noted above, the dollar value of rewards and penalties under this performance incentive will be established by the PaPUC in the initial general rate proceeding when Unit 2 becomes operational.

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

Nuclear Plants: Surry l' and 2 North Anna 1 and 2 Utility: Virginia Power Company (VPC)

Status: In effect since January 1979 Measure of Productivity: Fuel and Purchased Power Cost Type of Incentive: Reward and Penalty

Description:

The fuel recovery clause is based on a fuel price .index and generating performance criteria measured by equivalent availability and unit heat rates. First, VPC's procured fuel price is checked against a fuel price index. The index compares VPC's 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 j l

computer simulation of the economic dispatch of the utility's system. l l

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l' i This enables -the staff to derive an estimate of the fuel expense for a given

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- value of equivalent availability. The resulting estimate is used to' test the L ,. reasonableness of the utility's projected and actual fuel expenses.

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 l

penalties and' rewards therefore can not be quantified, although they are a real factor in VPC: rates. They are factored into rates during the annual VSCC fuel recovery clause proceeding.

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VIRGINIA Surry 1 &-2 North Anna 1 & 2 Operating Performance incentive Reculatory Authority: Virginia State Corporation Commission (VSCC) i Nuclear Plants: Surry 1 and 2 North Anna 1 and 2 l Utility: Virginia Power Company (VPC) t Status: In effect since January 1979 l

l Measure of Productivity: Capacity factor; equivalent availability l l

I Type of Incentive: Reward and Penalty

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Description:

The VSCC provides incentives based on improved generating unit )

l pe rformance. During general rate cases, the composite test-year performance {

l 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.

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1 Potential Financial' impacts on Utility Potential rewards and penalties are based or subjective judgment presented in individual rate case testimony. In principle, this incentive provides that t the better the plant performance, the higher should be the allowed return on equity.- Because of its subjective. nature, VPC has not attempted..to quantify the possible financial effects of this incentive. In the last rate case decision where the incentive was' applicable, the VSCC recognized-VPC 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 ,

i performance. The range of returns considered had been 14 'to 15 percent.

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FERC Surry 1 & 2 North Anna 1 & 2 4

Operating Performance Incentive l

J Regulatory Authority: . Federal Energy Regulatory Commission (FERC)

Nuclear Plant: Surry 1 and 2 North Anna 1 and 2 i Util'ty: Virginia Power Company (VPC) i l

Status: Discontinued (three-year trial basis ended December,1985) i Measure nf Productivity: Capacity Factor Type of Incentive: Reward and Penalty i

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Description:

The rate of return on equity (R0E) allowed by the FERC varied up to one percent depending on how closely company fuel expense (based on actual composite performance of 12 coal and four nuclear units) matched l predicted fuel expense. Equivalent availability and heat ratr were the standards for the coal units and capacity factor was the standard for nu'elear units. The capacity factor standard for nuclear units was based on capacity factors of similar nuclear units, adjusted for such factors as a steam generator replacement. .

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.I Also,.the company's fuel expenses had to underrun a target based on a-composite coal and nuclear performance standard by at least five percent to trigger a reward. Likewise, the company'.s fuel expenses had to exceed the performance standard by at least five percent to trigger a penalty. This amounted to a deadband of plus or minus five percent around the performance standard. Any rewards or penalties were limited to 100 basis points (one percent)oftheallowedR0E.

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- This incentive was discontinued on the basis that it had achieved its purpose.

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

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