ML20101R067
| ML20101R067 | |
| Person / Time | |
|---|---|
| Site: | 05000000 |
| Issue date: | 10/27/1984 |
| From: | Saltzman J NRC OFFICE OF STATE PROGRAMS (OSP) |
| To: | Rowsome F Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML20101R032 | List: |
| References | |
| FOIA-84-433 NUDOCS 8501180405 | |
| Download: ML20101R067 (40) | |
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f' JAN 2 7 1984 MEMORANDUM FOR: Frank H. Rowsome Assistant Director for Technology, Division of Safety Technology, NRR FROM:
Jerome Saltzman, Assistant Director for State and Licensee Relations, OSP
SUBJECT:
INCENTIVE REGULATION OF NUCLEAR GENERATION FACILITIES BY STATE PUCs Enclosed is our report on the subject of incentive regulation of generation
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facilities by State public utility conmissions. The incentive programs reported herein are those specifically applicable to nuclear facilities. Other programs apply to fossil plants.
In drawing from the three current studies on tha subject, an attempt was made to sort out from a large amount of information that material that emy be of ir.terest to reactor safety regulatdest.
.If there are questions related to this material please contact Jim Petersen of this office on 492-9883.
I Jerome Saltzman, Assistant Director State and Licensee Relations Office of State Programs i
Enclosure:
As stated Distribution:
Subject:
Incentive Regulation by State PUCs i
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l Okung A1, IWi INCENTIVE REGULATION OF GENERATION FACILITIES BY STATE PUCs Incentive plans aimed at increasing the efficiency of operation of nuclear power plants are in effect in eleven States. Two States have plans providing cost incentives related to construction of nuclear plants. This paper sumarizes the provisions of such incentive plans.
It. also sumarizes the findings pertinent to nuclear power of the three
.recent national studies on. this subject.. An attempt has been made to sort out and. highlight the studies.' findings that may be most interesting to reactor safety regulators. The recent studies have been done by the National Association of Regulatory Utility Comissioners (NARUC)AI, the S. M. St311er. Corporation (for the California PUC) U, and the Qu:drex Corporation (for EEI). 3_/
i 1/"IncentiveRegulationin'theElectricUtilityIndustry,"preparedby the NARUC Subcomittee on Electricity, September 1983.
-2/ " Standards of Performance Study, SONGS 1," S. M.. Stoller Corporation, for California PUC, under contract to Southern California Edison Co.,
3/ "ugust 1983.
A (final draft)gulation Programs in the Electric Utility Industry,"
Incentive Re
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Quadrex Corp., for EEI, July 1983.
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l Summary of Findings - NARUC Although the NARUC study is primarily a survey and description of individual State incentive plans, it does provide some overall findings and conclusions. NARUC, the national organization of State public utility commissioners and other utility regulators and their staffs (note: NRC is a member of NARUC), says that a very significant level of regulatory effort is being exerted to develop incentive regulation in the electric utility i'dustr9 n
'I "It appears to be widely recognized that. incentives may provide a means of ' assuring reliable electric service' at a more reasonable cost than a continuous, rigorous, and detailed revie.w of each utilit[y'soperations(as'hasbeenthetraditionalPUC'modeof operatior.). Limitations on the budgets of regulatory agencies, which have.always exist'ed, but h' ave.become more acute, al.so,
indicate the necessity for more effective and efficient regulatory tools. Currently, the greatest regulatory effort appears to be directed at'the efficiency of operation and utilization of generation facilities. This is particularly understandable in those States where energy costs (fuel and purchased power)
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' represent 50 percent and more of the electric, utilities,' total cost 1
ofoperation."bl bl NARUC Study, p. 1-1.
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i The NARUC study recomme ded further regulatory initiatives in the area of performance ir.centives and said that regulatory agencies should establish a high priority for such projects. NARUC recommended the following approaches in carrying this out:
o The appropriate allocation of replac.ement energy cost between ratepayers and stockholders.
o A. combination. of ' continuing regulatory ' review of detailed performance indicators with an indexing system to be applied between major operation reviews (general rate cases).
o' The application of_ decision analytic techniques to the
, meassrement of relative perf'ormance, o
Aggregate, performance as, measured by such indicators as.
average unit revenue and the growth rate of oper'ating and ma.intenance expenses.
Summary of Findings - Stoller i.j In October 1981, the Cal,.ifornia Public Utility Commissjon (CPUC) directed Southern California Edison Company (Edison) to engage a consultant to carry out a standards of performance study for the SONGS-1 nuclear unit., In November 1982, the CPUC selected the S. M. Stoller Corporation (Stoller) to perform the study.
In the' course of its study Stoller reviewed and reported on performance standards programs
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i promul, gated in other states which could impact the formulation of a program for SONGS-1. Stoller makes the fellowing observation in the background of its report:
4 "In the past several years, there has been increasing regulatory interest i.n the perfonnance of large central station generating units, both fossil and nuclear. This interest primarily :refle' cts the well-publicized increasing cost of construction, but as well the increased cost of operation, of
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such units.
Improvements -in availability and capacity factor performance of existing units can thus represent very material
' savings 'to the ratapa'yers and to the owner utility, both in.'
deferral of future system additions, ahd tilso for low incremental cost units, such as nuclear units,.in reduced overall system generating costs...
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The SONGS-1 study ordered by CPUC is consistent with the -
increasing efforts'by utility regulators across.the country in encouraging efforts to improve availab'lity by th'e i
establishment of explicit standa'ds of performance for large r
generating units. These programs. incorporate some formulistic i; '.
mechanism intended to be capable 6fisimple interpretation.,and 4
implementation, by which " good" performance of a unit on a utility system can be rewarded, or " poor" performance penalized.
Such standard programs are seen as producing two potentially desirable effects:
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They can act as a further incentive to the utility owner to seek means to improve performance.
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Such approaches may be preferable from an implementation standpoint to " reasonableness tests," or other retrospective judgments of. ten required for ratemaking purposes.
However, in considering such a program applied specifically to
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the SONGS.-1 nuclear unit, Stoller determined that several impor' tant issues needed to be addressed are:
1.
The potential exists that a program applied to a nuclear unit could encourage trade-offs which have adverse implications for the public health and safety.
2.
The potential similarly exists that such a ' program could
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encourage trade-offs between actions designed to maximize the measured performance against which the financial rewards or penalties of the program are applied, at the expense of operating policies and actions which would be
. : mo'r,e c'ost-effective in the longer-term interest'of.the ratepayer.
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The SONGS-1 plant is one of the very oldest units in current operation and much of that total nuclear power operating experience data base is thus not properly applicable due to design differences between SONGS-1 and the later units.
In addition, due to its comparatively advanced age,.one must take into account the potential impact of aging or " wear-out" in future SONGS-1 performance.
4 Most important, and as already alluded to, the very extensive plant modifications expected to result from the NRC-required SED program can be expected to result, as a minimum, in'a ssries of' extende'd planned outages over the next sdy'ral years. Any stardards program, to be e
effectivi and practical, must account for such planned outages." E As part of its study, Stoller spe'cifically assessed the emphasis' by Edison management on safety versus kilowatt-hour production, especially in gray areas where NRC regulations do not specifically mandate operator action. Stoller point's out that it deemed the matter of potential conflict.between safety and production} to be
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important enough to be worth exploring with the NRC directly.
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SONGS-1, the CPUC has not placed any performance incentive requirements on that unit since it has been inactive for the past two years.- Reactivation of the unit is dependent on NRC-required upgrades including those,related to seismic capability. The. Stoller findings were used as background for the performance incent'ives imposed by the CPUC on SONGS-2 (s.ee individual St'at'e summary below).
in September 1983. The CPUC staff saysf that it is reasonable to assume tha' similar performcnce incentives will be considered for-t SONGS-3 which may begin operation in Spring 1984 InckubdinStoller'sfindingsandconclusionsarecertainpoints particularly relevant to NRC requirements for nuclear plants:
o "There are no indications'that the other. state incentive programs studied have distorted the priority relative to nuclear safety, nor any evidence of special goncern by NRC for those units included in such programs."
o "It is desirable to avoid sharp thresholds in financial-impacts;/thatiis, to smooth the financial impact of a particular_ decision at a particular point in time..One step in that direction may be to average the performance over longer periods; programs where the measurement is made on very short intervals; e.g., six months, are prone to put undue pressure on an operating decision."
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" Broadening the base of the formula, e.g., to include the performance of more than one unit on the system, either other nuclear units, or some combination of nuclear and fossil, may also serve to diminish the financial' importance; and thus, the pressure on the operator of a singular operating division. This would also help to avoid undue management attention to a specific unit."
o "It is probably useful tio establish a " null zone" to accomodate variations in performance, for any number of random causes, which inevitably occur in the operation of a unit from year-to-year. This concept may be particularly applicable to nuclear units, for which the statistical experience base is still relatively modest, and,quite nonuniform; and therefore, performance
. prediction's are nct founded on an. es.pecially valid
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statistical base. l!owever, if such a tolerance band is incorporated in the formulas, it would still be preferable to smooth the financial impact as one departs th'e zone, rather than have major-step changes."
,"The principal administrative bun, den)is ' associated with f
.o accomodating events which are outiside the contro1 ~of the.
utility, not'bly NRC backfit requirements.. Prior to 1976, a
for example, the average impact on capacity factor of NRC backfit requirements was less than 1%.
In the latter half of the 1970's, this increased dramatically so that by 1979
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t-the annual losses in capacity factor due to NRC backfit requirements on pressurized water reactor units had reached over 16%.
In the last two years it has been decreasing, again getting down to about 7% in 1981 and 1982." 6.,/
~f Summary of Findings - EEI (Quadrex)
Although the EEI report is 'a draft, its contents are considered accurate and close to completion. The final report is expected out in early 1984
'EEI says its draft is suitable for review and quotation in limited distribution reports such'as this but requests that it should not receive wide distribution or quotation. ~The EEI' study, like the NARUC study, 'is. largely survey material, leut the
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individual. State summarics are more in-depth than those reported by i
NARUC.
EEI reports that the most popular incentive program objectives are to reduce fuel and/or purchased power costs, and to improve power plant productivity or e:ficiency. Most of the programs are linked to fuel and purchased power costs.
Capacity factors, availability 1,evels, and heat rates are the most frequ.ently.used criteria te..
measure performance. Most of the programs rely on combinations of multiple criteria to measure performance rather than one single 6_/. Stoller, pp. I-22 through I-24
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measure in order to avoid distortions or unintended outcomes.
In some cases, narrowly defined operating measures have led to increases in the cost of service rather than greater efficiency.
Just as most of the programs rely on multiple measures of performance, most also provide both rewards and penalties rather than a singular. reward or penalty avoidance.
Rew rds and penalties for almost all of the programs are made through adjustments in' allowable fuel and purchased pcwer costs or to the company's return on equity.
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Individual State Incentive Programs (Operating Performance)
The NARUC and EEI surveys identify eleven States 'that have operating performance incentives. specifically aimed at nuclear plants. Each of these is individually summarized below using information drawn
,from Stoller,' EEI.a.nd NARUC. ' Conclusions.r.eported herein regarding the effectiveness of the incentives and their relationship to efficient operation and to safety are those of the three referenced s t.udies.
In addition to the programs designed for nuclear plants, twelve States have performance incentives applicable to all or most generating units. The following table identifies key elements of
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thel, operating performan.ce incentives,. applicable,specifically to nuclear plants. Construction incentives are reviewed separately later.
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~ Summary of State Operating Parformance Standards Programs (Nuclear) (Notes on following page.)
Nuclear Utility State /
Foys Type Reward Penalty Rewards'/
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Start of of of.
Range Range Penalties
' Plant Program
. Program Target To Date Arkansas Arkansas Arkansas Fuel CF Between
- CF> 72.9% (#1.) CF< 72.9% (#1) -$44 M Nuclear One Power & Light 1980 Adjustment Scheduled CF> 71.5% (#2) CF< 71.5% (#2)
(3 years)
Units 1 & 2 Clause Refueling San Onofre Sou. Cal, Ed/
Calif.
Fuel CF CF> 80%
CF< 55%
N. Avail.
NGS Unit 2 SDG&E 1983 Adjustment Clause Fcrt St. Vrain Pub. Serv.
Colo.
Rate Base /
CF Between Colorado 1 1981 Rate of Return Scheduled None CF< 50%
None Outages Millstone Conn. L&P/
Conn.
Fuel CF> 70%
CF< 55%
Conn. Yankee Hartford Elec.
1979 Adjustment CF' (1).
(1).
None Clause Crystal River Fla. Power Corp. Fla.
Return on FPC:-$40K St. Lucie 1&2~
Fla. P&L-1981 Equity EA & HR (2).
(2).
FP&L:+$1.7M Turkey Point 1&2 Calvart Cliffs 1&2 BG&E Md.
Replacement -
1978 Fuel Cost EA None Judgment (3).
Pilgrim Boston Edison Mass.
Fuel AF, EA, CF, Yankee-Rowe Yankee' Atomic 1981 Charge llR.& FOR None (4).
None Big Rock Point Consumers Pwr.'
Mich.
Return on ECAR.
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(5)
+$14M-Palisades 1978 Equity Availability Brunswick 182 Carolina P&L N.. Carolina Retu'rn (6).
(6).
(6).
(7).
McGuire Duke Power Co.
.1978 on Equity -
Surry, N. Anna VEPC0 t
Davis Besse' Toledo Edison Ohio Fuel Cost Mce> 1 Mces 1 Not 1981 Cost Effectiveness (8)
(8)
Determinable Surry 1&2 VEPC0 Va.
Return on CF Judgment Judgment (9).
North Anna 1&2 1982 Equity I
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AF = Availability Factor M = Million EA = Equivalent Availability K = Thousand CF - Capacity Factor ECAR = East Central Area HR = Heat Rate Reliability FOR = Forced Outage Rate Coordination Agreement Footnotes:
(1) The Connecticut Program has implicit reward and penal.ty features in addition to explicit penalty for performance below 55% weighted average nuclear CF. There is an interest penalty for perfomance between 55% and 70% and an interest reward for performance greater than 70%. Since weighted average nuclear CF has not been below
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55%,,no penalties have,been levied. Amount of interest penalties or rewards are not tracked by Connecticut Division of Public Utilities Control and affected utilities.
(2) Reward / penalty is proportional to the ratio of actual deviation from performance targets to predicted. maximum deviation.
(3) 'BG&E has had 25% of. replacement fuel cost and 75% of replacement fuel cost disallowed for two different Calvert Cliffs outages.
Associrted dollar values of the penalties are not known.'
(4) Target values of AF, EA, CF, HR, and FbR are' set for each p1' ant covered in Massachusett's program (Specified by Mass. DPU).
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(5) The rewa,rd and penalty range are ECAR.availabili.ty plus periodic factor greater than 89% 'and less than 83.01% respectively.
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(6) No. Carolina has not set targets by which performance is judged.
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In a 1981 rate case, the No. Carolina Utilities Comission reduced VEPCO's return on equity from 15% to 10%.
In a 1982 rate case, the.
Commission reduced CP&L's return on equity by 1%.
(8) Mce is a complex fomula used to measure cost-effectiveness.
It involves a number of efficiency measurements including fuel utilization, fuel procurement, sales pricing policy, and purchased power, policy., ;.,
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(9)
In a 1981 rate case, VEPCO's return on equity was reduced to low end of authorized range. A 1% reduction in return on equity costs VEPC0 approximately $14 million annually.
In a 1979 fuel proceeding, VEPC0 was ordered to refund to its customers the net replacement energy costs ($3.3 million) associated with a Surry Unit 2 outage.
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l Arkansas Affected Nuclear Plant and Utility: Arkansas Nuclear One Units 1 & 2, Arkansas Power and Light In June 1980 the Arkansas PSC established an incentive to protect ratepayers from the replacement power costs which could result from excessive outages of Arkansas Nuclear One Units -1 and 2.
The. practical results of the program are as follows:
1.
When a nuclear unit is down for refueling, all replacement power costs are passed'to the consumer.
2.
When a nuclear unit is not. refueling.and has not been shut down for more than 30 consecutive days, AP&L is penalized all replacement power cost attributable to the nuclear unit's operating below its target capacity factor and keeps any fuel savings attributable to operating above target. Target capacity factors are 72.923% for Unit 1 and 71.55% for Unit 2.
For the thirtyNirst'and any' subsequent days of any centinuous 3.
outage, AP&L is penal.ized 10% of any replacement power costs,
7 associated with that outage.
4 Although not explicitly stated in any documentation, the Arkansas PSC treats any refueling outage beyond a specified duration as being an outage subjact to (2) and (3) above. The specified refueling outage durations are 10 weeks for Unit 1 and 8 weeks for Unit 2.
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s Experience with the Arkansas program is reported to be as follows:
1.
Capacity factor targets between refueling outages and the outage duration targets were set on the basis of experience pri.or to the TMI accident. Average capacity factors for similar. units to ANO Unit 1 and 2 in recent years.have been worse than the Arkansas targets.
2.'
Each month's rewards.and penalties are based on average fossil fuel costs during'.that month. According to Stoller, since the average fossil fuel costs are lower when nuclear units are net running,' AP&L could end'up with a net penalty even if both nuclear units ran on.the average, exactly at the tar'get a
capacity fac' tors while, experiencing the normally expected month-to-month variations.
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.If either unit refuels less frequently than implied (once 3
e'very 18 months f'or Unit 1, and once every 12 months for Unit 2)'that unit would have to exceed it's target capacity factor between refuelings by some amount in order for AP&L to break Stoller provides calculations for such' a' situation even.
(pp.I.IC-7,8).
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The Fuel Adjustment Clause Rider does not incorporate provisions for modifying unit performance to account for (a)
NRC-mandated outages or outage extensions, and (b) events occurring at other nuclear plants which require additional outage time for ANO units to perform inspections, tests and any necessary changes.
5.
The Rider does not allow for reduced power output due to other factors beyond AP&L's control (e.g., reduced-demand).
In fact, there are times when it will not permit performance credit to ANO units when they are fully operational (i.e.,
when they provide part of their power output to the Middle
' South Utilities Power Pool because of reduced de' mand' or -
availability of cheaper power for the Arkansas ratepayers).
6.
The Rider has the potential to guide AP&L in a direction which is not necessarily in the best interests of the ratepayer.
.Possible concerns include the following:
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Refueling' outage could be scheduled during peak suceer months so that if any extension occurs, it takes place Thus, penalti e,s,would be reduced,
i duri,ng t the fal,1 months.
and AP&L would absorb a reduced 'oss under the fuel l
adjustment calculation.
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o Extending outages rather than return to service and risk
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a later outage which restarts the Formula I clock.
(See Stoller, P. IIc-5 for details of formulas.)
o Shutdown of the units rather than coastdown to conserve fuel.
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Thsre are no maximum limits established to protect the utility from financial jeopardy in the case of extended outages.
As a result of this Fuel Adjustment Clause Rider, AP&L has received rewards and penalties in a ' net penalty of about $44 million in the three
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years of its implementatio'n (Note: AP&L's net income in 1982 was about 5107million). AP&L has pointed out the impact of a number of factors such as the seven noted above to substantiate its case that the Rider is unfair, and is in fact a penalty-only provision.
It was also stated that the Commission person r'esponsible for developing the Rider did not anticipate its working this way other than that provided by reducing the 9
penalty to 10% of' the replacement power costs for nonrefueling outages which. extend beyond 30 days. AP&L feels that a reasonable incentive.
program applied to nuclear units requires some mechanism to account for
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the changing,NRC impact upon nuclear, unit. performance..The magni.tude of.
the NRC's impact can generally be assessed prior to the outage.
Stoller reports that the Arkansas PSC is considering certain revisions to the Rider to moderate its impact on AP&L. One would be the establishment of a null zone in the capacity factor target of + 2.5%
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. s about the target. No rewards or penalties would be assessed for ANO performance within this zone. In addition, the target capacity factor would " float" to either end of the band so that the target would 'be equal to the upper end of the band if performance was better than CF plus 2.5%, and it would take on the lower end of the band (i.e., CF minus 2.5%) if performance was worse than that value. Anottier revision being considere'd would allow AP&L to keep all replacement power cost
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savings if a nuclear unit operated above its.overall capacity factor goal.
If a nuclear unit operated below its goal, penalties' would normally be limited to 10% of the replacement power costs for all days by which the total of unplanned outage days and extra (beyond the 8 or 1.0 week target) refueling outage days exceed.30..AP&L's reward-penalty results for the past three years recalculated using the above two revisions.would be a net penalty of about $4 million instead of $44 million. The maximum monthly loss of $15 million would be reduced to
. abo'ut $5 million.
With reference to the Arkansas procedures, Stoller concluded that "it is extremely difficult to write a provision 'that automatically covers all eventualities in a fair manner, thereby precluding the need for
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competent PSC' assessment of extenuating circumstances faced by the utility."
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California Affected Nuclear Plant and Utilities: SONGS 2 - Southern California Edison, San Diego Gas & Electric In its September 7, 1983 decision, the California PUC softened the reward / penalty provisions that its staff had suggested in the-proceeding. The PUC provided that additional fuel costs resulting from SONGS-2 capacity factor below 55% and ' fuel cost savings-for capacity factor above 80% would be shared equally (50/50) between the company (stockholders) ano ratepayers.
Th'e PUC staff had recommended that additional costs and savings above and below a 65% capacity factor should accrue entirely to the company The California PUC thought that standard was too harsh, particularly in 'the rel'atively untested area.of incentives. The Comission etaphasized the utility's' obli.gation to adhere to all NRC rules and regulations and stated.that the record of its proceedings included examples of other jurisdictions that have instituted. nuclear parformance standards without apparent detriment to nuclear safety. The PUC agreed with its staff that a performance standard such as a target capacity factor would not compromise safe plant operation. The PUC also recognized that nuclear plant out' ages may t
' be due. solely to factors outside the utility's control and that it wo0ld,
be flexible toward considering the causes and effects of such events on a case-by-case basis.
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Affected Nuclear Plant and Utility:
Ft. St. Vrain, Public Service Company of Colorado In December 1980, the Colorado Public Utilities Commission ordered that Public Service Company of Colorad.o would have to refund the rate base return'on common equity on Fort St. Vra.in'to the ratepayers if this plant does not achieve a 50% capacity factor performance in the test year. The 50% capacity factor is based upon 200 MW net capacity, exclusive of scheduled downtime for~ maintenance and refueling. This order was modified in January 1981 wherein the Commission ~ defined the test year as the-first full year after the 1981 refueling or no later than the end of the calendar year 1982. The Commission also determined the annual' rate of return on Fort St. Vrain to be 10.19% of the net jurisd1ctional investment which is equivalent to $807,000 per month.
Public Service Company of Colorado was ordered to escrow this amount on a monthly basis separately from the general funds of the Company.for ultimate disposition.
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,7 Affected Nuclear Plants and Utilities: Millstone and Connecticut Yankee
- Connecticut Light & Power Co., Hartford Electric Light Co.
The Connecticut Division of Public Utility Control established the
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Generation Utilization Adjustment Clause (GUAC) for Millstone and
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Connecticut Yankee. The program provides a mechanism to equitably share the risk of nuclear outages. Fuel expenses are set in base rates by applying the annual anticipated nuclear plant capacity factor (NCF).
This capacity factor is used in the computation of the GUAC formula which considers the fuel cost differential between fossil and nuclear generation.
If the actual weighted average nuclear capacity exceeds the NCF target, customers are credited with a part'of the avoiced replacement fossil fuel costs.
If the ' capacity factor fall.s below 55 percent, replacement fuel costs will be borne by.the utility.
If 'the nuclear capacity is between the target and 55 ~ percent, customers share in the cost of replacement fuel according to the formula. The OPUC staff has established the NCF target at 70 percent by comparing the historical perfo'hnance of nuclear units under its control with tae historical perfo'rmance of all nuclear units, practices of other regu,latory agencies and utilities, abstract productivity models, and
, statistical ' analyses.,
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.The major incentive for the utility is to avoid absorbing replacement '
fuel costs,when capacity is below 55 percent. Since performance between 55 percent and the NCF target results in sharing costs betwe'en the
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utility and customers and superior performance results in customers 1
being credited with avoided replacement' fuel costs, the underlying incentive may be to achieve average performance.
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f Florida Affected Nuclear Plants and Utilities: Crystal River Unit 3 - F1'orida
- Power Corp.; Turkey Point Units 1-& 2, St. Lucie Units' 1 & 2 - Florida Power and Light Co.
In September 1980, the Florida Public Service Commiss_ ion incorporated an explicit incentive factor, the Generating Performance Incentive Factor (GP[F),withintheFuelandPurchasedPowerRecoveryClause.
The-purpose of the GPIF is to provide an incentive to utilities to achieve efficient operation of base load generating units..The GPIF targets, actual performance, and incentive are. determined on a semi-annual basis.
iheGPIFprogram.isappliedtoautility'slargestgeneratingplants that contribute 80% or inore of the energy generated.
,. The incentive program goal is to min.imize fuel and purchased power costs. The GPIF uses complex formulas to lin.k the. rate of retiurn allowed on common equity to average heat rates and equivalent, availability, of power generating units. Targets are' set for average l
heat rates and equivalent availability, and fuel expenses are estimated by running several computer simulations of the utility sys' tem economic dispatch. Additional computer runs, provide estimates of fuel cost t
.t savings associated with operations at maximum, minimum, and target levels. Rewards or penalties are determined by comparing actual operating values with targets set for equivalent availability and
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average. heat rate. The commission staff worked with the utility companies to design the program criteria and measures. Targets are ' set 7
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by formula for equivalent availability and average heat rates.
Equivalent availability targets are set using the historical performance record for each unit adjusted to reflect maintenance improvements.
Average heat rate targets are set by using monthly data weighted according to economic dispatch with adjustments made for unit modifications, fuel, changes, and environmental regulations.
Above average performance for both equivalent availability and average
- heat rate results in a reward, and below average.perfonnance results in
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a penalty. Rewards ana penalties may be as much as 0.25 percent of return on comon equity. The singular objective of lowering fuel costs as a function.of performance targets may result in the' company neglecting other areas 'of utility operations. At issue'is whether the program minimizes the overal.1 cost of operation.
Finally, the
. reporting, administrative and technical analysis activities for the annual' hearings involve substantial costs.and comitment of manpower.
Florida PSC personnel report that the GPIF was meeting its objectives:
increased ~ efficient operation of base load plants. The following decreases in system overall heat rates since implementation of the GPIF were noted: approximately 130 BTU /Kwh at both Florida Power & Light and Gulf. Power.and;160 BTU /KwhatTampaElectric. A decline;in planned outage durations also was noted but no figures were given.
The two util.ities with nuclear units, FP&L and FPC, have received both rewards and penalties during the first 4 performance periods under GPIF.
FP&L has received 3 rewards totaling $1.9 million and 1 penalty of $180
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thousand for a net reward of $1.72 million. FPC has received 2 rewards totaling $650 thousand and 2 penalties totaling $690 thousand for a net
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penalty of $40 thousand. The PSC staff noted that Crystal River 3 (an 800 MW PWR) accounted for approximately 50% of FPC's rewards and penal ties. The PSC staff reported one problem with the GPIF; there is som.e disagreement between the PSC staff and utilities regarding targets, reasonably attainable perfonnance ranges, and adjustments when judgment has been applied in. determining.these parameters. The PSC staff has required changes in approximately 50% of the performance values it has reviewed.
The response from FP&L and FPC to the GPIF were nearly identical. Both
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' utilities reported that they always strive for high performance and implementation of the GPIF did not, always result i'n any-increased emphasis on their efforts. FP&L mentioned.that they had a performance l
I improvement' program in place when the GPIF went into,effect.' FP&L a,nd FPC both reported that possible safety impacts were not an issue during hearings on development of the GPIF.. Further, they said there has i;een
'no.NRC interest in the GPIF either during.its development phase or the implementation phase. Both utilities reported that the GPIF has not impacted (i.e., neither facilitated nor complicated)'the rate hearing and. fuel charge ' hearing proce.sses.
FPC reports that the GPIF has i
increased the workload of the Plant Performance Group due to data tracking, collection and reporting requirements.
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Maryland Affected Nuclear Plant and Utility:
Calves c Cliffs :Inits 1 and 2, Baltimore Gas and Electric Under a 1978 Maryland law, fuel cost adjustment and determinations were removed from base rate hearings and a ' separate fuel rate adjustment mechanism was established. The intent of the law was to eliminate
' electric bills which fluctuated wildly from month to month due to the automatic fuel cost pass through.- When a utility's monthly cost of fuel exceeds or falls below the cost fixed in the last fuel rate adjustment
' hearing by more than 5", the utility notifies the Maryland Public Service Commission which must hold a new fuel rate adjustment hearing.
By law, the PSC must' determine if the generating units. performed at reasonable levels when evaluating the fuel rate adjustment-(Note: Other factors such,as fuel purchases and, generation mix are,also evaluated).
In addition, if any pa.rty brings evidence that power plant outages were caused by " improper actions: or " imprudent management," the PSC must evaluate'the outage.
If the PSC determines that one or more generating units did not perform at reasonable levels and/or an outage was caused by improper actions or imprudent management, then the PSC can reduce the i,, utility's proposed fuel rate adjustment. Originally,. there we're no guidelines or standards for defining ~ terms such as reasonable level of performance, improper actions and imprudent management.
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reasonable level if its equivalent availability factor (EAF) for the most recent 12-month period exceeds the higher of: 1) its average EAF over the last 3 years, or 2) the 10-year NERC average EAF for plants of the same class. No guidelines or standard have been set to assist in defining improper actions or imprudent management related to outages.
The Public Service Commission and the affected utilities are dissatisfied with the Maryland program. Both, parties realize that the program is penalty oriented; there are no. rewards for above average or 4'
superior performance.
In particular, investigations of plant outages b
and resultant penalties show the major weakness of the program.
Some j
, examples are discussed below. ~
L In a '1982 fuel rate adjustment case, Bal'timore Gas & Electric applied 4
for an increase in fuel costs.' With regard to the Calvert Cliffs f,
nuclear pl.an.t. the PSC determindd that this plant operated at,a reasonable level.
In fact, the EAF for the plant in the preceding.12 1
months was higher than for the previous'3 years and it was higher than the NERC 10-year average for the same class of plant. However, the Office of the People's Council.(a state government organization) intervened in the hearings. The Council maintained that a 17-day outage l-
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starting in laje 1980 was the result of improper, utility action.
c Evidently, a nut from the turbine hoisting equipment had.gotten loose, fell into the turbine during maintenance and had caused damage during turbine operation. The hearing examiner recommended that BG&E be
__ i disallowed 50% of the replacement fuel cost for the outage. The PSC'in its Order disallowed 25% of the replacement fuel cost.
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1 In another fuel rate adjustment case, the PSC again determined that BG&E had operated the Calvert C1.iffs station at reasonable performance levels. Once more the Office of the People's Council intervened and claimed that a July 1981 outage was due to improper utility actions.
In this case, Unit 1 experienced salt water intrusion into the coolant during startup. The PSC disallowed 75% of the replacement fuel cost for this outage.
The PSC reports that at practically every fuel rate adjustment hearing, even those where actual fuel costs are more than 5% below the current level, the Office of the People's Council intervenes and. claims that one or more outages a're the result of improper utility actions or imprudent management. As a result of the two Orders for the BG&E fuel adjustment rate cases, BG&E has gone to court in an, attempt to have the outage evaluation nullified.
Independent of the BG&E legal action, the PSC is l
,1 considering modifications to the standard that,would have.the following,
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features: (1) definite standards by which plant performance could be judged, 2)'a reward system as well as penalties,.and 3) a decreased emphasis on, plant outages in det.ermining fuel' rate adjustments. '
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Affected Nuclear Plants and Utilities: Pilgrim, Boston Edison; Yankee-Rowe, Yankee Atomic In August 1981 the Massachusetts legislature decided to include evaluation of power plant performance in the fuei charge procedure. The
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amendment provided for establishment and operation of a fuel charge monitoring bureau to administer and enforce the fuel charge procedure.
At least once a year, affected utilities file a proposed performance program with the Department of Public Utilities (i.e., the Fuel Charge Bureau, Massachusetts DPU). The utility performance program requires evaluation of the following parameters as a minimum, on a unit-by-unit basis: availability; equivalent availability; capacity factor; forced' outage rate; and heat rate.
4 The affected utilities have to file performance statistics on a monthly.
-basis. Any monthly variance has to b'e explained at the.next' fuel charge hearing and may become the basis for a determination of " unreasonable or imprudent performance."
In fuel charge hearings, if trie Department '
determines that a utility has been unreasonable or imprudent with regard 1
,to. fuel use, the Department can deduct from.the fuel charge proposed for the next period an amount that the Department deems proper as reflective of the fuel costs directly attributable to the " unreasonable or imprudent performance." The statute does not contain any provision for rewards if performance exceeds the targets, iThe~utilitiesjaffected by the pjrformance program;are not enthusiastic about it.
First,'the program has provisions for penalties and none for rewards. The program requires a large data collection, assessment, and reporting effort.
In addition,.the required heat rate audits are supposed to involve ASME Power Code Testing, which is time consuming and
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costly, and their value in meeting the acts of 1981 is being challenged by the utilities.
Michigan Affected Nuclear Plants and Utility: Big Rock Point, Palisades -
Consumers Power In 1978, the Michigan Public Service Commission instituted'the Availability Incentive Provision for the Detroit Edison Company and Consumers Power Company. The Availability Incentive Provision was ordered *to encourage the two utilitiies to improv'e the availabilit'y of their generating plants.' Both utilities.had experienced declining system av'ailability, and reached an all ' time low of approximately 72% in the mid-1970's.
l The performance standard incorporated in the original orders was system average availability using the East Central Area Reliability.
CoordinationAgreement(ECAR) definition.
ECAR availability for a single generating unit is defined as unit operating hours plus unit hours available but not operated divided by total hours in the period.
- The. system average is: determined by sunning indiv,idual unit ECAR.
availabilities weighted by the units' capacity ratings. The performance standard was modified by the PSC in August 1980. The new standard incorporates the following changes: 1) a periodic factor was identified to account for periodic, scheduled maintenance, 2) the neutral or null zone was reduced from 10% to 6%, and 3) the system availability scales
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were " fine-tuned" and 11 ranges were created nstead of the original 3 ranges: variation over the period of,the periodic factor, 9 percentage points (or.09) for Consumers Power accounts for scheduled outages and was established based on an analysis of a 10-year history and 'a 10-year forward projection of scheduled outages for the utility.
Utility performance, as measured by system average availability plus periodic factor is tied to incentives by a scale which equates performance to an adjustment of return on equity. The target of availability plus periodic factor is equivalent to a target on unplanned outage factor (i.e., random outage factor) since the sum of availability plus planned outage factor plus unplanned outage factor equals one. The current scale for Consumers Power is shown in the following table.. Note that there is a null zone in which no penalty or reward is leviedi'The maximum reward is a 1/2% increase in return on equity and the maximum
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CONSUMERS POWER COMPANY AVAILABILITY INCENTIVE PROVISION System Availability (ECAR)
Equity Return Plus Periodic Factor Incentive 94.01%
+.50%
100%
92.76%
+.40%
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94.00%
91.51%
+.30%
92.75%
91.50%' - 90.26%
+.20%
89.01%
+.10%
90.25%
83.01%
89.00%
82.01%
.05%
83.00%
81.01%
.10%
82.00%
80.01%'
.15%
81.00%
7,9.01%
.20%
80.00%
.25%
79.00%
The PSC staff and Consumers Power have expressed their satisfaction with the Availability. Incentive Provi'sion. Consumers Power had impressive rewards under the Provision.
It has received two rewards in four years for a gain of approximately.$14 million. This performance improvement also meant considerable savings to their ratepayers.
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s, Cognizant utility personnel stated'that Consumers Power was aware of the performance problems (e.g., high random outage factor, low availability) occurring in the 1974-1976 time frame, and that steps were being taken to correct problems and improve performance before the Availability Incentive Provision was implemented. However, the utility felt that the
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. provision provided additional focus on availability within the company,-
'provided the funding necessary to obtain improvements (e.g., production maintenance expenses, base rate), and may have accelerated implementation of some improvement actions.
Consumers Power reported that there was.no overt interest by the NRC in e
the Availability Incentive Provision and no additional NRC interaction
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s'a result of the Provision. The issue of possible safety' impacts did not arise. Consumers Power emphasized: 1) the need for pre-established
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ground rules for allocating NRC-mandated outages to the periodic factor category rat,her than the random factor category, and 2) the need for a competent PSC staff, such as in Michigan, to make informed judgments ab'out NRC-required actions and other factors impacting upo'n those~ items which should be included as planned outages'.,This mechanism can accommodate factors beyond the utility's control.
North Carolina Affected Nuclear Plants and Utilities: Brunswi'c'k 1 & 2 - Carolina Power and Light; McGuire 1 and 2 - Duke Power Co.; Surry 1 and 2, North Anna
- i 1 & 2 - VEPC0 i
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North Carolina currently does not have a formal performance standard program based upon a North Carolina 'Jtilities Commission Order or a legislative act. However, the Commission does periodically review the performance of utility power plants in both fuel adjustment hearings and p
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gendral rate case proceedings and, in the past, has levied penalties based on its assessment of poor performance.
Since 1978, the North Carolina Utilities Comission has required electric util_ities to file detailed performance data on nuclear and baseload fossil-fired plants on a monthly basis.,The performance reports include' the following information: outage data, including cause, duration and corrective. actions taken; actual generation by each unit; and lost generation by type of outage (i.e., full, partial, scheduled, orforced).
The Comission considers power plan't performance in general rate case hearings and has levied penalties for poor plant performance. When a utility files.an application for a general ~ r. ate increase, the Public Staff, acting as a consumer advocate, reviews' the performance of the utility's power plants. This review can include a detailed investigation of engineering, operations, maintenance, and management performance.
If the Public Staff finds that fuel costs were excessive due to poor plant performance,'the Staff. can recomend. to the Comission that the utility's return on equity be reduced. The utility has the opportunity' to defend its plant performance in the rate case hearings.
The.Comission then;makes asju'dgment aslto the utility rat.e of return'.
4 There are no defined standards by which power plant performance is judged.
The Comission adopted a new general rate case procedure in June 1982.
The utility fuel cost chargeable to ratepayers is included in the
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utility base rate. The fuel cost is based, in part, on various classes of power plants achieving specified performance levels. The capacity factor used to determine allowable fuel costs for Duke Power's nuclear plants is 60%, and the capacity factor for Carolina Power and Light's nuclear plants is 52%. Within a year of a general rate case, the utility must'have a fuel cost hearing. The Comission can disallow' fuel costs, if in its judgment, plant performance has been substandard or poor due 'to utility imprudence. Again, no. formal standards of performance related to fuel cost hearings are in effect, and performance standards and incentive'f'ormulas are being considered.
The affected utilities, which are all investor owned, are not satisfied f
with the current North Carolina system. The main reasons for their dissatisfaction are: 1) the're are ' penalties only and 2)' judgment plays a central role in a determination of " poor performance" and in allocating I
penalties.
For example, in a.1981 decision on a VEPC0 general. rate' case, the Comission reduced VEPCO's authorized return on equity from the 15.5% to 10%.
In December 1980, VEPC0 filed for a general rate. increase. The Public Staff hired consultants to evaluate the following areas:
- 1) management practicespin plant O&M, 2) outages, reductions in power, ;
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and 0&M practices and procedures', and 3) predicted fuel costs at high'er power plant performance levels. The Public Staff's consultants presented testimony that showed poor plant performance due to various VEPCO deficiencies. VEPCO presented extensive testimony to rebut the consultants' testimony. However, the Commission sided with the Public
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Staff and held that VEPCO's fuel expenses were excessive due to poor plant performance. The return on equity was reduced as noted above.
In a 1982 CP&L rate case, the Comission reduced the return on equity by 1%. The commission ruled that an outage at the Brunswick nuclear plant, caused by a turbine bearing failure, was the fault of CP&L.
Ohio A'ffected Nuclear Plant and Utility: Davis Besse - Toledo Edison The Ohio program is embodied in the 1981 Tariff M and 1982 Tariff M ce ce*
Automatic fuel cost adjustments were' eliminated in Ohio with Amended Substitute Ho~use Bill 21 which became effective July i,,1980. This statute contains the Ohio'PUC's purchased power cost policies which were l-originally promulgated in the now defunct 1976 fuel cost adjustment.
rules. The objective of these policies is to minimize the cost of electric service to customers by providing incentives to: investor-owned utilities for minimizing fuel costs'.
The specific provisions of the statute were implemented in February 1981 and placed in the Ohio Administrativ.e Code on September 1981. The original cost-effectiveness measure, known as 1981 Tariff Mce, meas m s
,the efficiency of fuel procurement and utilization practices of an electric utility and then converts the cost-effectiveness measure, Mce' into a fuel recovery factor. M,is.a-complex formula used to measure e
cost-effectiveness.
It involves a number of efficiency measurements
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including fuel utilization, fuel procurement, sales pricing policy, and purchased power policy.
Toledo Edison reports that it has recovered somewhat less than $1 million in fuel costs under the cost-effectiveness measure system that otherwise would not have been collected under the old -fuel cost adjustment clause. The cost-effectiveness measure and incentive program has not had any impact on power plant operations or engineering. The Rate Department of Toledo Edison'is almost solely involved with the
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program. There is practically no involvement by the Engineering and Operations Departments.
However, Toledo Edison stated that its 4 large coal units are in the top 20 units with respect to heat rate, capacity factor, and' availability.
Davis-Besse performance has been hurt by TMI and generic problems -(e.g.,
.pumpseals). Any external pressure:to improve Davis-Besse performanc'e has come from the Ohio PUC during base rate hearings. For example, the Ohio PUC has suggested that Davis-Besse might be removed from the rate base if performance'did not, improve. Toledo Edison reports that there has been no discernible concern on the part of the NRC with' regard to the Ohio. performance standa'rds program.
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Virginia Affected Nuclear Plants and Utility: Surry 1 & 2, North Anna 1 & 2 -
VEPC0 A VEPC0 rate application settlement establishes a performance incentive program by which rate of return,(and therefore, rates) would be tied to generating unit performance b'a' sed on indices such as equivalent
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' availability and heat rates. Targets for Surry and North Anna units are derived frcm the two-year average capacity factors of all nuclear units built by the,same manufacturer. Adjustments to the two-year averages are made to compensate for improvenents in reliability resulting from major overhauls of the nuclear units.
The fuel recovery clause is based on.a fuel price index and generating
' performance. criteria measured by equivalent availabili.ty and, unit heat.
rates. First, the 13-month average procured fuel price is checked
,against a fuel price index. The index compares the cost per BTU for various fuel types with costs for the mid-Atlantic and south-Atlantic regions of the country. Second, target ranges are set for equivalent availability and unit' heat rates using a computer simulation of the economic dispatch of,the utility's' system. This enables,the staff toi.
derive an estimate of the fuel expense for a given v'alue of equivalent availability. The resulting estimate is used to test the reasonableness of the utility's projected and actual fuel expenses.
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While there is no spec 1fic set of rewards or penalties, the performance criteria affect regulatory decisions on fuel costs. At the annual fuel recovery clause hearing, the utility's fuel account for the previous 12 months is settled.
If cost underrecovery is determined to be the result of poor performance because of factors within management's control, complete recovery may not.be allowed.
If actual performance is on target, the time lag for recovery is reduced.
' Construction Performance Incentives EEI and NARUC identify two States that have construction performance incentives specifically applicable to nuclear plants.
(Stoller concentrated on operating p,erformance incentives.') They aim at controlling construction costs and/or expediting' construction completion.
i-New Jersey Affected Nuclear Plant and Utility: Hope Creek 1 - Public Service Electric & Gas Co.
The Hope Cree.k program (which provides.bo,th penalt,ies and rewards)'
objective is to control construction costs. Through negotiation between the New Jersey Board of Public Utilities and Public Service Electric &
Gas Co. (PSE&G) the target construction cost.was set at $3.7 billion.
The incentive program provides that PSE&G may recover from customers only 80 percent of costs that exceed the $3.7 billion target by up to 10
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percent. Should costs exceed this target by more than 10 percent,'the company may recover only 70 percent of costs above the 10 percent threshold.
If the plant cost is bet. deen $3.5 billion and $3.7 billion, all actual costs wil'. be recoverd.
If the cost is below $3.5 billion, the reward provision becomes operative and the company will recover actual costs plus 20 percent of the difference between $3.5 billion and the actual costs. Thus, the program's incentive is to complete
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c'enstruction at a cost below $3.5 billion to recoup.the 20 percent reward, and to avoid penalties. resulting from cost overruns.
New York Affected Nuclear Plant and Utility: Nine Mile Point 2 - Niagara Mohawk Power Corp.
The Nine Mile Point 2 program is designed.to control the power plant construction costs.
It was instituted because of escalating construction costs and uncertainty of completion dates. The program keys on s' haring revenue requirements growing out of cost overruns and underruns. A target cost'of $4.6 billion was negotiated and set for the project by Niagara Mohawk and the New York Public Service Commission; the utility will. be rewarded :for reduc.ing that, cost and. penalized for exceeding it. The company will receive 20 percent of the savings if the final cost is under target and must absorb 20 percent of cost overruns.
Thus, the program's incentive is to share in the benefits by bringing the project in under the targeted amount, and to avoid absorbing 20 percent of cost overruns.
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p kg EEI reports that the dine Mile Point 2 program was instituted well after construction began at a time when it was difficult to obtain accurate
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and unbiased construction cost estimates. The investment community has not been enthusiastic about the program because it is felt that the PSC i
may have given up authority to assure a reasonable return on invested capital.
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