ML20147H370

Grid Performance Factors

ML20147H370
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Issue date:	03/20/1997
From:	Wegner M NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD)
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l X l \

• Grid i 'A ~

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Performance l

d Factors .

l AEOD C97-01

MARCH 20,1997 i

l l l

Mary S. Wegner 1

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j Office for Analysis and Evaluation of Operational Data i United States Nuclear Regulatory Commission l Washington, D. C. 20555-0001 NO OkG NE D R

. CONTENTS ABB REVIATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vi EXECUTIVE

SUMMARY

. . . . . . . . . . . ..........................viii t n INTp oDUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2.0 DATA SOURCES AND SEARCH STRATEGIES . . . . . . . . . . . . . . . . . . . . 2 3.0 DEFINING THE " GRID" . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 4.0 G RID CHARACTERISTICS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 4.1 Demand .......................................... 6

4. 2 G enera tion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 4.3 Capacity Margin ....................................10 4.4 Plant Age ...... ... . ...........................12 4.5 Emergency Procedures ................... ............15 5.0 OPERATIONAL EXPERIENCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 5.1 Grid Blackouts or Perturbations Which Impacted Nuclear Plants . . . . . . . 16 5.2 Weather-Related Events Which Have Perturbed the Grid . . . . . . . . . . . . 18 5.3 Other Events Which Have Perturbed the Grid ..................19 6.0 POTENTIAL PROBLEMS WITH GRID STABILITY . . . . . . . . . . . . . . . 21 6.1 Normal Contingencies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 6.2 Severe Contingencies .................................21 6.3 Potential Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 6.4 The Changing Grid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 7.0 ANALYS IS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 7.1 Regulatory Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 7.2 Globa! Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 7.3 Specific Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 8.0 FINDINGS AND CONCLUSIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 8.1 General Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 8.2 Specific Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 8.3 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 9.0 BIBLIOGRAPHY ............. ........................ . 32 iii

, r CONTENTS (cont.) ,; .

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APPENDICES  !

t A. Demand, Generation, and Capacity Margin Charts -

i B. Plant Age t

i TABLES  !

Table 3.0.1: Member Councils of the North American Electric Reliability Council ... 3 ,

Table 3.0.2: Load Reduction Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 l Table 4.4.1: Number and Capacity of Power Plants in the United States by Age . . . . 13 i Table 6.1: Normal Contingencies ........................ , . . . . . 21 .

Table 6.2: Severe Contingencies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22  ;

Grid Instabilities Discovered by Plant Analyses . . . . . . . . . . . . . . . .

Table. 6.3: 22 i

FIGURES I i

Figure 3.0.1: North American Electric Reliability Councils .................. 3 Figure 4.1.1: Temperatures vs Peak Demand on January 18, 1994 . . . . . . . . . . . . . 7 ,

Figure 4.2.1: U. S. Capacity by Prime Mover . . . . . . . . . . . . . . . . . . . . . . . .. 8  ;

Figure 4.2.2: Total Number of Plants vs Total Capacity of Plants by Prime Mover . . . . 9 l Figum 4.2.3: Average Generating Capacity of Power Plants by Prime Mover . . . . . . 10 l Figure 4.4.1 : Plant Age . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Figum 5.2.1: Grid Disturbances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18  ;

Figure 6.4.1: Kewaunee - Point Beach Trancmission T inec . . . . . . . . . . . . . . . . 26 1

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l o ABBREVIATIONS IE safety-related electrical ,

ac, AC - alternating current ANO1 Arkansas Nuclear One, Unit 1 CFR- Code of Federal Regulations CT current transformer DOE U. S. Department of Energy  ;

ECAR East Central Area Coordination Agreement  :

EDG emergency diesel generator -

l EEI Edison Electric Institute ERCOT Electric Reliability Council of Texas l ES&D Energy Supply and Demand ESF engineered safeguards features l FRCC Florida Reliability Coordinating Council GIC geomagnetically-induced currents GT/IC/JE gas turbine / internal combustion engine / jet engine  ;

HVDC high voltage direct current j Hz Hertz IE-411 DOE report IPP independent power producers kV kilovolt LER licensee event report LOOP loss of offsite power l

MAAC Mid-Atlan'ic Area Council  ;

MAAC PJM Pennsylvania, New Jersey, and Maryland subregion of MAAC MAIN Mid-America Interconnected Network MAIN EMO Eastern Miswuri subregion of MAIN MAIN NIL Northern Illinois subregion of MAIN ,

MAIN SCI South Central Ill nois subregion of MAIN MAIN WUM Wisconsin, Upper Michigan subregion of MAIN MAPP Mid-Continent Area Power Pool l MW megawatt v

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-.. . - . . - . - ~ - - - . - . . . . . - . _ - . - . - - . . . - . . . . . . ._

MWe megawatt, electric I NERC North American Electric Reliability Council .!

NPCC Northeast Power Coordinating Council j NPCC NE New England subregion of NPCC i

NPCC NY New York subregion of NPCC NUDOCS Nuclear Document System i

NUREG NRC technical repon designation OR operating reserve PECO Philadelphia Electric Company PT potential transformer PURPA Public Utilities Regulatory Policies Act SCSS Sequence Coding and Search System SERC Southeastern Electric Reliability Council  ;

SERC FLA Florida subregion of SERC SERC SOU Southern subregion of SERC SERC TVA Tennessee Valley Authority subregion of SERC l

SERC VAC Virginia-Carolinas subregion of SERC >

SLOD severe line outage detector SPP Southwest Power Pool l SPP NOR Northern subregion of SPP i

SPP SE Southeastern subregion of SPP

, SPP WCN West Central subregion of SPP 4

SPS special protective system TS Technical Specifications I

USI unresolved safety issue WNP2 Washington Nuclear Plant, Unit 2 WSCC Western Systems Coordinating Council WSCC ANM Arizona-New Mexico subregion of WSCC WSCC CSN California-Southern Nevada subregion of WSCC WSCC RM Rocky Mountain subregion of WSCC

. WSCC NW Northwest subregion of WSCC vi  !

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. EXECUTIVE

SUMMARY

The reliability of offsite power is important to nuclear safety. Accident sequences initiated 8

2 by the loss of offsite power are important contributors to risk for most nuclear plants . In 1979, the Nuclear. Regulatory Commission identified the loss of all AC electrical power to the nuclear plant, called station blackout, as an unresolved safety issue. Station blackout was shown to be an important contributor to the total risk from nuclear power plant accidents. A task action plan A-44 was issued in July 1980. The final report on Unresolved Safety Issue A-44 was contained in NUREG-1032, " Evaluation of Station Blackout Accidents at Nuclear .

Power Plants," June 1988. In NUREG-1032, the grid was assumed to be stable and reliable.

This study was initiated to collect operating experience on grid disturbances which may have impe'ad nuclear power plant operation and the availability of offsite power for the period of 1985 to the present. In order to communicate the findings of the study, it became necessary to inquire into the nature of the gr:d and its operation. The grid is defined and some of its basic characteristics are addressed.

An event in 1989 at the Virgil Summer Nuclear Plant caused a severe perturbation of the Eastern Grid which resulted in a loss of offsite power to Virgil Summer. The los Angeles earthquake of January of 1994 resulted in a severe perturbation of the Western Grid. In December of 1994, the Western Grid experienced another severe perturbation that resulted in the scramming of both Diablo Canyon units.

In 1995, a series of equipment failures at a nearby substation caused the two Limerick units to scram. The resultant perturbation was seen throughout the Eastern Grid.

In 1996, the Western Grid experienced two major disruptions, one on July 2 and the second on August 10. The August 10 event lead to the scramming of both Diablo Canyon units and Palo Verde 1 and 3. Diablo Canyon declared their 500 kV offsite power system inoperable.

Four reports of potential problems related to grid stability were found in which licensees reviewed stability analyses and instabilities were discovered. The reviews were done for a variety of reasons, including as a followup of an information notice, in response to a question raised during an electrical distribution functional inspection, and following actual events.

I offsiec power is

• electric power from the transaussion network to the onsite distribution system . . supplied by two physically andependent circuits (not necessarily on separate rights of way) designed and located so as to nununue to the extent practical the likelihood of their sunuhaneous failure underoperating and postulated accident and environmentalconditions. A switchyard common to these synaems is acceptable.* 10 CFR 50. Appendis A. Critenon 17 *Electnc Power systems' 2

In this study, the term

• plant

• is used according to usage more common to the NRC. A

• plant

• is a single generating unit when differentiation between

• unit

• and " station

• has relevance, or the entire station where the differentiation is not relevant. NERC usage of the term is more strict. in that plant usually means all generating units at a generating station.

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The condition of the grid is dynamic: capacity changes; demand changes; transmission

~

patterns change; equipment ages; new equipment is brought on line; and equipment is retired. Two relatively new factors are emerging: independent power producers and restructuring of the electric industry.

l The North American Electric Reliability Council has adopted programs and procedures to deal with forecasting, normal operations, emergency conditions, and recovery from system collapse. The programs and procedures appear to give a basis for assurance of orderly operation.  !

l The " grid," the bulk power supply, as managed by the North American Electric Reliability .

Council member utilities, has adequate resoun:es to give reasonable assurance that the I reliability of the system will be maintained under normal conditions. On the whole, the grid is stable and reliable; however, problems described in the Regional assessments as stated in Section 4, as well as uncertainties introduced by restructuring of the electric industry indicate the need to monitor grid conditions on a regular basis.

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1.0 INTRODUCTION

Station blackout is the complete loss of alternating current (AC) electrical power in a nuclear power plant. This includes all normal and alternate AC power from offsite sources', loss of all onsite AC power produced by the nuclear unit, and loss of all onsite emergency AC power (produced by emergency diesel generators, usually). Because many of the systems which are required for removing reactor core' decay heat and containment heat depend upon AC power, the consequences of a station blackout could be severe. Station blackout and other accident sequences involving loss of offsite power are known to be important contributors to the total risk from nuclear power plant accidents. As operating experience accumulated, the concern arose that both the onsite and offsite emergency AC power systems might be less reliable than originally anticipated. The Nuclear Regulatory Commission designated station blackout as an unresolved safety issue (USI); a task action plan (A-44) was issued in July 1980, and work was begun to determine whether additional safety requirements were needed. The final report on USI A-44, NUREG-1032, " Evaluation of Station Blackout Accidents at Nuclear Power Plants," was issued in June 1988 (1). In NUREG-1032, the grid was assumed to be stable and reliable.

This study was initiated to collect operating experience on grid disturbances which may have impacted nuclear power plant operation and the availability of offsite power for the period of 1985 to the present. In order to communicate the findings of the study, it became necessary to inquire into the nature of the grid and its operation. In the following sections, the grid is defined and some of its basic characteristics are addressed. Then operational experiences and potential problems are discussed.

I offsite power is

• electric power from the transmission network to the onsite distribution system . . supplied by two physically independent circuits (not necessarily on separate rights of way) designed and located so as to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. A switchyard common to these systems is acceptable." 10 CFR 50, Appendix A. Criterion 17.

• Electric Power systems

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2.0 DATA SOURCES AND SEARCH STRATEGIES Information used in this study was obtained from the North American Electric Reliability {

Council (NERC), the individual Reliability Councils, the Department of Energy (DOE),

j NRC documents, Sequence Coding and Search System (SCSS) searches, the Nuclear i Documents System (NUDOCS) searches,10 CFR 50.72 reports, and reports from a variety l j of other sources. j h SCSS searches were conducted for licensee event reports (LERs) dated from January 1, 1985, to the present for high- or medium voltage AC system problems related to all scrams.

l NUDOCS search strategies used key phrases and keywords such as GRID

! FLUCTUATIONS, GRID PERTURBATIONS, and GRID DISTURBANCES, and DEGRADED near GRID.

d Individual Reliability Councils were contacted to obtain a copy of their IE-411, yearly status

, reports to DOE [2]-[10]. The information on demand, generation, capacity margin, i

emergency procedures, and regional operating philosophy for assuring the grid function was

] contained in these documents.

1 The NERC Energy Supply and Demand (ES&D)* database [11] provided the mean -'.o  ;

update the data. Additional documents received from NERC include the "NERC Operating 1 Manual," [12] the "1995 Annual Report," [13] " Reliability Assessment 1996-2005,"

3 [14] and several other documents.

! DOE information included DOE /EIA-0095, " Inventory of Power Plants in the United States 1994," [15] data from a database which contained information on major grid disturbances, and other reports. Mr. Norton Savage of DOE supplied data and provided.

! assistance vital in locating these documents.

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- 3.0 DEFINING THE " GRID" On November 9,1%5, the northeastern U.S. experienced a pe">er failure which directly affected 30 million people in the U.S. and Canada. [16] On Jun C,1977, New York City experienced a blackout, following lightning strikes in the Ind.u Point 3 switchyard causing it to scram and lose offsite power. [17] No Federal regulation of the reliability of the bulk power supply was provided by the Federal Power Act of 1935 and none was subsequently approved following either the 1%5 or the 1977 incidents. The promotion of the reliability of the bulk power supply is the mission of the North American Electric Reliability Council through its member Reliability Councils. Although the current Reliability Councils can trace their history back further than 1%5, these two events had major impacts on the development of their structure, functions, programs, procedures, and operation.

These Councils were made up of members representing the electric power utilities which engage in bulk power generation and transmission in the United States, Canada, and parts of Mexico.

Information in this report is generally limited to the 48 contiguous states of the United States.

The goal of the reliability councils was to foster reliable operation of the grid through coordinated operation and planning of generation and grid facilities.2 [12] Table 3.0.1 names the member councils and gives the abbreviation by which each is usually called.

Figure 3.0.1 shows the geographic location of the mensber councils throughout the United States.

Table 3.0.1: Member Councils of the North American Electric Reliability qp Council [14], [18]

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• cc ECAR East Central Area Reliability ( ]_

Coordination Agreement r auw Florida Reliability Coordinating Council auAc FRCC ,-

i eca, wecc MAAC Mid-Atlantic Area Council L

MAIN Mid-Amenca Interconnected Network MAPP Mid-Continent Area Power Pool I

• sane NPCC Northeast Power Coordinating Council SERC Southeastern Electric Reliability Cc=cil T sacor mec SPP Southwest Power Pool ERCOT ~ Electric Reliability Council of Texas Figure 3.0.1: North American Electric WSCC Western Systems Coordinating Council Reliability Councils {18]

2 specific Regionalinformanon is sometimes given as representauve of all Regions. While it may be representanve, there may be differences in Criteria from Region to Region. Information on the same subject for Regionr. Other than the one named should be obtained from the Criteria of that Region.

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" Interconnections" (the term the electric power industry uses instead of grid) are a for providing power from the plants via an interconnected transmission network to the ,

entities that resell it to the consumer via a distribution network. The Western Interconnection is composed of one Reliability Council, WSCC. The Eastern Interconnection comprises ECAR, FRCC, MAAC, MAIN, MAPP, NPCC, SERC, and SPP. The Texas Interconnection is also composed of one Reliability Council, ERCOT.

" Continuity of service to load is the primary objective of the minimum Operating Reliability Criteria. Preservation of interconnections during disturbances is a secondary objective exce; when preservation of the interconnections will minimize the magnitude of load intermption or will expedite restoration of service to load" are the objectives of WSCC. [10] SERC states that their regional criterion is "to assure that ... cascading outages will not result from any foreseeable contingencies." [8] MAAC states that "The bulk electric supply system shall be planned and constructed in such manner that it can be operated so the more probable '

contingencies can be sustained with no loss of load." [4]

The objectives for each Reliability Council vary but, whether explicitly stated or implied in context, the Reliability Councils' operating philosophy is to prevent cascading failure 3,

[19] provide reliable power supplies, and maintain the integrity of the system. Long-term and short-term procedures are in place nationwide to project demand, to provide for reserves to meet peak demand, and to provide for both likely and unlikely contingencies when demand exceeds capacity and other emergencies. These procedures include a load reduction program which calls for manual steps to stabilize the grid and a series of automatic actuations to prevent collapse of the grid. The load reduction procedures for MAAC are shown in Table 3.0.2.

Table 3.0.2: Loati Reduction Procedures [4]

1. Cunailment of nonessential power company station light and power (power plants)

2. Reduction of controllable interruptible/ reducible loads

3. Voltage reductions (brownouts)

4.  ; Reduction of nonessential load in power company buildings (other than power plants)

5. Voluntary customer load reduction .

6. Radio and television load reduction appeal

7. Manual load shedding (rotating blackouts)

8. Automatic actuation of underfrequency relays which shed 10 percent ofload at 59.3 Hz, an additional 10 penent at 58.9 Hz, and an additional 10 percent at 58.5 Hz 3

'the term *cascadmg failure

• refers to the uncontrolled successive loss of system elements in which the loss of each successive element is contingent upon prior losses of elements. In plain words: a power plant inps offline and the nearby plants cannot cope with the additionalloads so they trip offline. That places an even larger load on the nearby plants and these plants tnp offline etc..

until the entire electnc grid shuts down.

4

.- . Generators operate at 60 Hz (cycles per second). If generation is not exactly equal to load, frequency will vary. In fact, minor variations in frequency exist over time and are routinely corrected. Higher-than-expected loads, loss of generation, and faults can produce frequency transients. If the situation warrants, the utility may reduce voltage by up to 5 percent to bring frequency back to 60 Hz. Operating at higher or lower frequencies or voltages can damage generating equipment and damage or cause malfunction of equipment loaded to the grid.

Other procedures allow disconnecting from the grid (islanding) areas which have generating  :

units that are capable of supplying local loads, but that would be tripped if connected to a degrading grid.

1 When specific facilities frequently experience disturbances which unduly burden other systems, the owners of the facilities are required by their Council to take measures to reduce the frequency of the disturbances, and cooperate with other uti lities in taking measures to reduce the effects of such disturbances.

The emergency procedures also provide for the safe shutdown of the system and for the  ;

restart. Because many plants cannot be restarted without external power, "blackstart" units are available at various locations as determined by the utility. The blackstan units are capable of starting up without any electricity being supplied to them from the grid, including self-excitation; therefore, they restart and produce power to restart other units. The typical blackstart capability is described as follows: "These [blackstart] units comprise diesel and combustion turbine units, conventional hydro, and pumped storage hydro units. Normal - i operating procedures for pumped storage hydro plants require maintaining sufficient water in the upper reservoir at all times to provide for system startup power. Satisfactory tests have been conducted to prove the capability of black start of conventional hydro, pumped storage hydro, and some steam and combustion turbine units to provide system startup power." [8]

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1 4.0 GRID CHARACTERISTICS '

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This section addresses demand, generation, capacity margin, age of power plants, and

, emergency procedures.

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4.1 Denuand -

1 Demand' is the rate at which electricity is delivered to a customer. Demand varies with the

'. hour of the day, day of the week, month of the year, temperature, humidity, and other factors. When demand is greatest, it is said to " peak." Peak seasonal demand occurs in the summer in all areas except Florida (FRCC) and the Pacific Northwest (WSCC NW), which

have winter peaks. [11]  !

5 To meet expected demand, utilities establish a baseload capacity , the amount of electricity d l they need to produce continuously, and an operating reserve6 for msponding to increased 7 i demand. This operating reserve is called spinning or non-spinning 8and can be loaded up to its limits in ten minutes. Spinning reserve is already synchronized to the grid, while non- -

spinning reserve is capable of being started and loaded within ten minutes. Some areas also have a thirty minute reserve requirement. Nuclear plants are generally base load units as are most steam plants.

Peak demand is expected peaks estimated by combining such factors as previous use, the  ;

number of new customers, weather forecasts, and other information into a demand forecast.

Demand forecasting is not done on a worst case scenario. It does not anticipate the demand l during unusually severe weather or other unforeseeable factors which may affect demand.  !

An example of severe weather effects on demand (and capacity) occurred on January 18,1994, in Midwest and Mid-Atlantic areas of the United States. Only MAAC and Virginia Power had to institute the manual curtailment of rum load (rotating blackouts), but less drastic procedures wem instituted throughout most of the  !

Eastern Interconnection.  ;

l Demand is the rate at which electric energy is delivered to or by a system or part of a system. ... at a given instant or averaged over I any designated inserval of time, t19]

5 Baseload capacity is used to serve an essennally constant level of customer demand. [19]

6 operating reserve is shat capability above firm system demand required to provide for regulation, load forecasems error, equipment ,

error, forced and scheduled outages, and local area protection. [19]

7 spumag reserve is unloaded generation, which is synchronized and ready to serve additional demand... t19]

8 Nonspmmng reserve is that operating reserve not connected to the system but capable of serving demand within a specific time, or interruptible demand that can be removed from the system in a specifud time. Inactruptible demand rney be included in the nonspinning reserve provided it can be removed from service within ten minutes, t19) 6 1

- _ _ - - _ - . . i

i The temperature as l measured at the "

Washington National Airport began to drop f*-+-*g_,v from about 35'F. at

/q %A ,p> ~

n "E

5 a.m. to 8*F. at u "

• • ~

/ \ - =

midnight. [20] In the MAAC PJM [21] ama x ,, 1 'w s ,"

E  ;

and in Northern Virginia, i

• NN , .

[22] peak electric

• "N -

a r N u r demand in the afternoon o gan ,

and evening increased a -

_;e j inversely with the l + '""" " * *"'""" l

• , , , , , , , , , ,,,,.. . . . ., . .. .. . ., =* [

temperature when it was expected to drop with the == l change in usage from i commercial to residential. Figure 4.1.1: Temperature vs. Peak Demand on l Because the temperature January 18, 1994 [20], [21], [22]

decreased to atypical ,

values, the increase in residential loads exceeded the decrease in commercial loads.  :

Demand peaked at 7:00 p.m. and remained higher than the daytime peaks through midnight of the following day. Figure 4.1.1 shows the relationship of temperature to peak demand for the 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> beginning at 0000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> on January 18.

Utilities throughout the Eastern Interconnection began emergency procedures to reduce demand. Emergencies were declared in Pennsylvania, Maryland, and the l District of Columbia. Government offices and many businesses closed early on January 19 and remained closed on January 20. The emergency was ended by midday on January 20, though some voltage reductiom continued into the evening.

When demand is projected to exceed supply as it did in the January 18,1994, cold '

spell, utilities purchase power from adjacent systems. In this case, these systems were also strained by the same cold weather problems; but the New York Power Pool did reduce voltage to its customers and imported power from the New England Power Pool and Canada in order to assist the PJM area. SERC FLA, through SERC SOU also exported power to the mid-Atlantic States. [23]  ;

Because of the cooperation of all entities involved, the load reduction procedures were successful and the Eastern Interconnection was never close to loss of load or collapse because of low frequency.

i Demand for electricity by nuclear plants usually occurs when the unit is not producing enough power to supply house loads which may include the safety-related systems. Some nuclear plants supply safety-related loads directly from offsite power at all times. This i

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power must be available at all times. Power to start up must also be supplied to the nuclear unit's generator. Offsite power for nuclear plants is not included in the utility's demand -

management program, but it may be affected by an automatic actuation in response to a grid fault.

That is, a nuclear plant's voltage will not be reduced, nor will the plant load be shed by the demand management schemes; however, grid faults have caused nuclear plants to be isolated from the grid. See Section 5 for examples.

All Reliability Councils project a yearly increase in peak demand over the next ten years.

ECAR projects a 1.85 percent increase in peak demand, ERCOT estimates a 2.0 percent increase, MAAC's forecasted increase is 1.4 percent, MAIN expects to see a 1.75 percent increase, MAPP projects a 1.9 increase in peak demand, NPCC expects the lowest increase -

1.0 percent, SERC estimates a 2.1 percent increase, SPP anticipates a 1.6 percent increase in peak load, and WSCC is forecasting a 1.2 percent increase in peak demand for WSCC NW, 1.7 percent for WSCC RM, a 1.9 percent increase for WSCC ANM, and a 1.4 percent increase in WSCC CSN. [14]

See Appendix A for chans showing peak demand projections for each area.

4.2 Generation' i

A utility generates electricity by various means

steam turbines, l gas turbines, internal combustion engines, jet engines, hydro wuct.EAn turbines, and a number of other ss

! means. Additional electricity

may be furnished by independent STEAnd j power producers. ses j HYDRO 15%

4 Appendix A contains charts of

rated capacity'0 vs actual

,7,g;,3, i generation for 1994 by region omg, n and subregion developed from ss information found in the NERC

[ ES&D' database showing percentage of the total capacity Figure 4.2.1: U. S. Capacity by Prime Mover [11]

which is generated by each type Generation is defined as the process of producing electrical energy from other forms of energy; also. the arnount of electricity s produ:cd. It is also used to indicate the equipment for producing electricity, especially when the term generating capacity is used.

1 [19]

j 10 Capacity is defined as the rated continuous load carrying ability . , of generation ... equipment. [191 l 8 i

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. of prime mover. Also, the nuclear units which contribute to the capacity in the region or i subregion are named. Steam turbines", however fired, are the principle means of electric generation in all but two subregions, where nuclear steam electric plants provide 51 percent

. of the power generated and hydro / pumped storage units provide 68 percent of the power generated. There are no nuclear units in two sub-regions. [11]

l By generator nameplate rating, nuclear units range from 75 MW to 1403.2 MW, and average about 908.6 MW. Steam turbines" range from 3 MW to 1425.6 MW, however, the average steam unit generates 202 MW. Gas turbines range from 2.5 MW to 138.1 MW and average 38 MW. Internal combustion engines range from less than 1 MW to 21.4 MW, and average 2 MW. Hydro units range from less than 1 MW to 700 MW, and average 27.7 MW.

Pumped storage plants are tallied with hydro units. Steam units produce 58 percent of the generation nationally; gas turbines / internal combustion engines / jet engines (GT/IC/JE), 7 pement; nuclear,15 percent; and hydro,15 percent. Figure 4.2.2 compares the total number of power plants by types to the amount of generation produced by that type and Figure 4.2.3 depicts the average size of the different type of power plants.

Prime Mover j l l  ;;l l si..m l pgggg l l l l l l l I  !  ! I orncus ll l l l l l l l l l l l l l

l  ! l ,  !  !  !  !

l om.e l

i l

l i

l l

i l

gl

\

i l

l i

l l

i l

l i

l l

i l

4 3 2 1 0 100 200 300 400 500 800 Plants X 1000 MW X 1000 Figure 4.2.2: Total Number of Plants vs Total Capacity of Plants by Prime Mover [11]

U Nuclear units are steam electric plants but are tallied separately in this study as they are in the Rehability Councils' IE-411 responses and most other hterature.

9

8 9 1

Prime Mover 4

I I I I I e I i e i GT/8C/JE 13 l l l l l l t i i t

] 1 i l I i l i i l I i g

I I I I I Hydro 27.7 l l l l l I i l I i

I I I I I I I I I j sseam soa l l l  !

I I I i l l I i i l i i i l 1

Nuc8eer sos.h

. . l i  !

o 200 400 soo soo 1,000

uw j Figure 4.2.3

Average Generating Capacity of Power Plants by Prime Mover [15]

4 i

4.3 Capacity Margin [13]

This section addresses capacity margin.i2 Capacity margin is the amount by which

generating capacity exceeds the forecast peak demand. [19]

1 Events have shown that factors such as unit availability and transmission line capacity affect the adequacy of capacity margin that is actually available for use. Improving unit availability and improving transmission line reliability are the principal methods specified by the Councils for maintaining adequate capacity margin. Bringing units under construction on 12 Capacity margin (%) = (ne capacity resources (maximum output of its generators

+ the maximum output of the generators of the independent power producers in the area

+ power purchases

- the capacity of inoperable generators

- power to run the power plants

- sales))

MINUs (net intemal demand

- direct control load management

- interruptible demand. if they can be made available to the system in ten mmutes or less)

DIVIDED BY (net capacity resources)

EXPRESSED As A PERCENT. [11) 10

. line and purchasing power from non-utility generators were also mentioned as means of

improving the capacity margin status.

l The charts in Appendix A, which were developed from data given in the ES&D' database, show capacity margin projections for 1996 to 2005, as well as demand projections for that period. The term " projection" is particularly fitting to describe capacity margins in that the numbers get less firm as the distance from the present increases.

The adequacy" of the projected capacity margin is determined by each Council by comparing the percent of projected capacity margin to an acceptable percent or by probabilistic assessment.' ECAR uses the probabilistic method and has determined that annual generation availability must remain above 78 percent for the dependence on i supplemental capacity resources" to remain at less than one to ten days per year. Their average annual generation availability for the past ten years has averaged 80.1 percent and 1

was 81.7 percent for 1995. For ECAR, generation availability is critical. The aging of generating capacity necessitates increased maintenance and lengthened outages. By 2005,59 percent of ECAR's capacity will be over 30 years old and about 22 percent will be over 40

years old. [15]

ERCOT capacity additions have been utility owned, but this year, ERCOT is projecting a i higher percentage of IPP capacity additions, which are unidentified and uncommitted at l present. ERCOT's minimum capacity margin criteria is 13 percent. Their projected margins i - from 18.3 percent to 10.8 percent - are considered adequate if load serving entities allow f

sufficient lead time to get capacity additions on line. [14] MAAC projects adequate capacity to meet Regional reliability goals of 20 percent reserve margin if undetermined resources can be committed within the lead time available. [14] MAIN uses the loss of load probability

analysis to assess the adequacy of their system. MAIN will have adequate generating

, capacity to meet its one-day-in-ten-year criterion throughout the entire period. [14] MAPP requims a 15 percent minimum planning reserve margin" above non-coincident demandi' .

4 They do not expect to meet that goal based on proposed and committed additional generation capacity; however, power sources are judged adequate over the ten-year period. [14]

NPCC states that near-term availability of operable capacity in New England may be lower j than required to meet customer demand because the three Millstone Nuclear Units, the

Connecticut Yankee Nuclear Unit (Haddam Neck), and the Maine Yankee Nuclear Unit are i

" Adequacy is defined as the ability of the electric system to supply the aggregate electdcal demand and energy r .guirements of the j

< customers at all times. taking into account scheduled and reasonably expected unscheduled outages of system elements. (19] {

" supplemental capacity resources include assistance from neighboring Regions. contractually interruptible demands. and direct control

{ load management. [19]

" Plannmg reserve margin is the difference between . . expected annual peak capability and expected annual peak demand expressed 1 i as a percentage of the annual peak demand. [19]

16 Non :oincident demand is the sum of two or more demands that occur in different demand intervals. (19]

l I 11 i

i j

.. . -. -. .-~ . - - - .- - .- . . - . . . - - -

a e shut down. On the long term, compensation for the lack of output from the named nuclear

units in the form of increased dependence on IPPs, increased import of power from Canada,

,{

and other potential sources will provide adequate resources for the period. The New York i area anticipates adequate reserve margin over the period. For NPCC, IPPs have become the 4

second largest source of electricity behind nuclear [14]

SERC lists their capacity resource margin as 15 percent throughout the period, which is

considered adequate. [14] Note that Florida it Ixluded in this projection. The capacity 1

margins of SPP range from 16.4 percent to 13 percent. SPP expresses concerns that

' generation reliability is difficult to assess in the increasingly competitive marketplace. They report that operators had difficulty accessing resources (without regard as to price) on several j days in 1995. [14]

i WSCC reports each sub-region separately, listing four issues which could impact reliability j

to varying degrees: 1) unusual operating conditions and potential voltage instabilities, 2)

competition and increasing pressure to reduce costs,3) changes in the structure of the l ,

electric industry, and 4) uncertainties associated with competition and change. WSCC NW reports very high water levels resulting in surplus power sales. They also report steps taken j

to alleviate the potential for voltage collapse during peak demand conditions. WSCC RM

{ reports more than adequate capacity to meet peak demand requirements. WSCC ANM j

reports that competition and deregulation has begun to affect operations and expansion plans.

They express concern that some aspects of deregulation adds uncertainties to the planning process and could adversely affect reliability. Environmental concerns have also impacted

• operations. WSCC CSN reports significant changes in the electric power industry within California will occur as a result of regulatory action by the California Public Utilities Commission in their December 20,1995 decision on restructuring the electric power industry-l (q.v.). On the whole, WSCC assesses its capacity margins adequate for the projected period.

i [14]

1 4

4.4 Plant Age j i

The information concerning age of power plants was developed from " Inventory of Power  !

Plants in the United States 1994." [15] The information concerning the age of power plants i

[ in Table 20 is titled ". Year of Initial Operation." The power plant being operated at a site could be as old as the initial startup date would indicate, parts of it may be original equipment, everything may have been replaced many times since startup, or the original plant may have been razed and a new plant built on the site. Almost all of the oldest plants are t

hydro units and some of them are known to be in excess of 60 years of age. This section's i

charts and tables equates age with initial startup date - maximum possible age.

a The power plant with the oldest initial operational date in the United States is an 900 KW hydro unit located in California. Other plant sites with an initial operation before 1900 are located in New York, North Carolina, Texas, Utah, Vermont, and Washington.

t l 12  ;

I

a e 2000 300

• new x 10o0 -

. y a _ ,,,

t -

i.o. -

g$; j

's' '/ l 200 1

io - i _

is.

P X t 500 -

0 h / uj -

E I I@L

- I ll 1 .

/.-//////// / ~*

Age Figure 4.4.1: Plant Age [15]

Figure 4.4.1 shows the number of plants built in each decade and their werage capacity.

Note that both peaked in the 1970s.

Table 4.4.1: Number and Capacity Power Plants in the United Sto:es by Age [15]

Age Period No. Pct. MW Pct.06-105 1890-1899 23 0.2 14.9 0.0 86-95 1900-1909 221 2.3 426.1 0.1 76-85 1910-1919 503 5.2 1908.4 0.3 66-75 1920-1929 732 7.5 4320.8 0.6 56-65 1930-1939 441 4.5 4703.6 0.7 46-55 1940-1949 902 9.3 14977.6 2.1 36-45 1950-1959 1780 18.3 90592.0 13.0 26-35 1960-1969 1958 20.2 149033.7 21.4 16-25 1970-1979 1972 20.3 271513.7 39 6-15 1980-1989 914 9.4 141854.2 20.4 2-5 1990-1993 269 2.8 17501.6 2.5 1

13 )

i

[

{i

- Although 47.3 percent of the operating plants may be older than 35 years, they produce only  ;

about 16.8 percent of the total U.S. electrical capacity. An additional 60.4 percent of U.S.

electrical capacity is produced by plants which may be 16 to 35 years old. The newest plants '

i - 2 to 15 years old - produce 22.9 percent of the power with 12.2 percent of the plants. See  !

Table 4.4.1.

4

?

With 38.2 percent of the U.S. electricity generated by plants 26 years or older, age has the i j potential to become a factor in grid stability. As ECAR expressed, the need for equipment

{

outages may increase as well as their length. [14] The event at Virgil Summer in 1989 listed  ;

the age of nearby plants and the need for extra protection for them as a factor in the event.

i Appendix B contains additional information on plant age, sorted alphabetically, by maximum .

age, and by average age.  ;

i I  !

j i

}  !

4 1  !

l I 'f f

t

)

h i

l f

i 5

14

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

j e r l i

. 4.5 - Emergency" Procedures i

q Although regional Reliability Council procedures differ, the thrust is the same: maintain the l

reserve margin to supply excess demand; but, when reserves drop, take steps to protect the

! integrity of the grid. The steps detailed in this section are taken from one Reliability Council report as representative of steps taken to achieve these goals. In capital letters, the L responsibility for restoring operating reserves is spelled out: "IN THE EVENT OF l OPERATING RESERVE DEFICIENCY, THE DEFICIENT SYSTEMS HAVE THE i PRIMARY RESPONSIBILITY FOR RESTORING OPERATING RESERVES TO THE

] DESIRED LEVEL When the deficient systems are unable to correct the deficiency, all

systems in (region] should take actions to aid in restoring Operating Reserve." [5]

i

I. Operating Reserve (OR) Deficiency Condition 4 A. The [ Region] Coordination Center shall

1. monitor the OR status, i 2. analyze daily reports,and

{ 3. conduct load and capacity surveys, j B. If OR is below minimum, t 1. declare a [ region) Operating Reserve Deficiency Condition, and

! 2. reevaluate scheduled maintenance.

! 3. Remove generation capacity limitations where practical.'

4. Return transmission facilities to service where capacity or interchange j conditions can be improved.

j 5. Synchronize all available generating facilities, holding fast-starting peaking units in a standby state,if appropriate.

6. Make arrangements to purchase power.

II. Alert Condition A. (Deficient system) If OR is less than 75 percent of the minimum requirement,

1. Declare a [ region] Alert condition, and i

2. Perform the steps under I.B. i

3. Institute effective voltage reduction procedures, curtailment of interruptible loads, or both.  !

B. (All systems) When the OR is below 65 percent of the minimum requirement, l institute effective voltage reduction procedures, curtailment of interruptible  !

loads, or both.

C. When OR cannot be restored to above 75 percent of the minimum requirement, neighboring systems are required to exchange information on their resp:ctive OR status to arrange transaction schedules to improve overall reliability.

U An emergency is any abnormal system condmon that requires automatic or immediate manual action to prevent or limit loss of transmission facilities or generation supply that could adversely affect the reliability of the electric system. [19]

15

, - - , - e .

- - - - - . . - . _ - - - .. - - - - . - . . . - - - - . -- ~ . . - -. - -.--

i 5.0 OPEP.ATIONAL EXPERIENCE NUREG-1032 divides operational experiences into three types: (1) plant-centered events which had an impact on the availability of offsite power, (2) grid blackouts or penurbations j which had an impact on the availability of offsite power, and (3) weather-related arvi other  :

events which had an impact on the availability of offsite power. Category 1 is not addressed -

in this study. Category 3 was separated into weather-related events and other events which )

perturbed the grid.  :

i 5.1 Grid Blackouts or Perturbations Which Impacted Nuclear Plants For the purpose of this study, the switchyard is considered to be a component of the grid.

In 1989, at Virgil Summer, technicians working in the generator stator cooling  ;

controls caused a loss-of-stator-cooling signal to be generated although stator cooling was not lost. The turbine tripped and the reactor scrammed. The nearby plants l which attempted to make up the load tripped because their generator protection was set high because of their age. The cascading failureiesulted in 16 units offline and a .

severely depressed voltage throughout South Carolina and neighboring States. Virgil Summer's 1E (safety-related) busses saw the degraded grid condition and isolated from the grid. The emergency diesel generators (EDGs) started and loaded the 1E busses. [LER 50-395/89-012]

• Also in 1989, a breaker failure in the switchyard of the Dresden site caused a partial  ;

loss of offsite power (LOOP) and a loss of annunciators on Unit 2 which led to the declaration of an alert. Unit 3 scrammed. The event was complicated by equipment i losses and failures on both units. [LER 50-249/89-001]

In 1989, a failure of a lightning arrestor at LaSalle 2 caused a scram on LaSalle 1, a I partial LOOP, multiple complications on both units which led to the declaration of an  !

alert and propagated to Braidwood where both units saw a voltage drop.

[LER 50-373/89-009; LER 50-456/89-003]

In 1992,' a breaker fault at Sequoyah 1, complicated by preexisting conditions and human error, resulted in a dual-unit scram, LOOP, natural circulation, EDG start and

. load, and actuation of the ice condenser. The local grid was depressed but not disrupted by the loss of Sequoyah's output. [LER 50-327/92-027J At various times, insulators contaminated by sea salt, bird droppings, blown dust, etc.

have caused line faults which caused transients at Pilgrim, Comanche Peak 1, and Diablo Canyon.

18 A loss of offsise power is loss of all normal AC power. both IE and non-lE components.

16

, , i In 1994, a main transformer failure at Beaver Valley I caused a reactor scram. The reactor scram caused a local grid perturbation which' led to the scram of Unit 2 and a LOOP on Unit 2. [LER 50-334/04-005]

On December 14,1994, a line fault caused by a contaminated insulator flashing over in a heavy fog on the Midpoint-Borah-Adelaide (Utah) 345 kV line tripped the line.

Problems were also experienced on other transmission lines in the area. Diablo -

Canyon Units 1 and 2 saw undervoltage on the reactor coolant pump busses and the reactors were automatically scrammed in anticipation of reactor coolant pump trip.

See AEOD/'I95-01 for details.

In 1995, a series of equipment failures at nearby substations caused both Limerick '

units' generator protective relays to isolate from the grid causing the reactors to ,

scram. The'PECO system experienced the loss of eight transmission lines and the Eastern grid experienced a brief frequency transient. [LER 50-352/95-002]  ;

On July 2,1996, a transmission line sagged into a tree in Idaho creating a ground fault which progressed into a major fault on the Western Interconnection. Again, the ,

nuclear plants saw a frequency transient but did not scram or lose offsite power. A .

similar event occurred the next day but did not propagate outside Idaho. [24]

On August 10, 1996, a line sagged into a tree again, this time in Oregon. The subsequent transient resulted in the loss of over 30,000 MW of load,25,000 MW of generation, which is 17% of the total western U.S.-Canada generation, and the tripping of 190 generating units including both Diablo Canyon Units and Palo Verde Unit I and Unit 3. [25]

Diablo Canyon declared the normal 500 kV offsite power source inoperable. Both ,

~ Units transferred to the alternate offsite power source. [LER 50-275/96-012]  ;

Palo Verde did not lose offsite power. [LER 50-528/96-004]

1 Factors which contributed to the incident were high transmission loads and equipmer l out of service. WSCC NW has a winter peak and summer is outage season. l California was suffering a lengthy hot spell and less expensively produced hydro- l electric power was availabic. [25]

17 i

I

' From a DOE database [26], information on grid disturbances reported from 1985-1993 shows the disturbances to be caused by downed lines, equipment outages, demand management, and other causes. Storms were the principal initiators of disturbances,

' followed by equipment failure, ambient temperature, sabotage, fire, and other causes.

Figure 5.2.1 illustrates this distribution.

4 Nh

/ Egutpsment Folksre Seerme

= "'

1 1

l oehe,

= -

m_ f

}

11%

3 s

Eedenent Outages sabotage N

)  % -_ ._ ,

as% tog , a4%

i "'

Type of Disturbance \

' Cause of Disturbance

{

1 i

Figure 5.2.1: Grid Disturbances [26] '

a l 5.2 Weather-Related Events Which Have Perturbed the Grid Weather-related events have impacted the availability of offsite power. Most weather-related events not associated with Hurricane Andrew" were caused by lightning.

Crystal River 3 had a LOOP in 1989 with one EDG out for maintenance when lightning destroyed a current transformer. One IE bus was without power for two minutes. [LER 50-302/89-025]

l Lightning struck a breaker at Waterford 3 in 1990, causing it to malfunction, explode, and burn. Because of preexisting conditions, the reactor scrammed on high pressure.

One EDG started and locded. [LER 50-382/90-012]

An alert was declared at Yankee-Rowe in 1991 when lightning destroyed a lightning arrestor and faulted a disconnect switch resulting in a turbine trip, LOOP, loss of I

l I'

Hurricane Andrew was a unique event of enormous impcM; however it is not being addressed in this study because it has been the subject of Information Notice 93453.

• Effects of Humcane Andrew on Turkey Point Nuclear Generating station and Lessons Learned,* and NUREG-1474.

• Report on the Effects of Hurricane Andrew on Turkey Point Nuclear Generating station frt,m August 20 - 30,1992.*

18

1 I

d communications, engineered safeguards features (ESF) actuation, and EDG start and load. [LER 50-029/91-002]

. l A complicated scram at Waterford 3 in 1991 was caused by lightning which caused a  !

grid voltage transient. There was excessive cooldown of the reactor coolant system, I

manual ESF actuations, and multiple equipment failures. Offsite power was not lost.

[LER 50-382/91-013]

l In 1991, dual-unit scrams at Palo Verde 1 and 3 were caused by lightning which i caused a three-phase fault without ground on a transmission line. There was no i

LOOP, but the EDGs did start. [LER 50-528/91-010]

Other recent dual-unit scrams caused by lightning occurred at Comanche Peak and Vogtle in 1995. Offsite power saw a brief frequency depression following each event, crused by the loss of generation. [LER 50-445/95-002] [LER 50-424/95-002]

5.3 Other Events Which have Perturbed the Grid In 1989, during an intense solar magnetic disturbance, a severe grid disturbance occurred in a portion of NPCC in Canada. The storm was also implicated in the failure of two main transformers at Salem 1. Solar magnetic storms cause ,

! geomagnetically-induced currents (GIC) on Earth which can affect electrical  ;

equipment, particularly main transformers. Salem Units 1 and 2 and Hope Creek have reported ten main transformer failures since startup of Salem 1 in 1977, four of which are known to have been caused by GIC. The vulnerability of Salem and Hope ,

Creek to GIC damage is unique among nuclear plants, but common to other types of power plants in areas known to be vulnerable to the effects of GIC. [27]

In 1989, a lineman working in the switchyard at Brunswick 2, grounded a potential transformer (PT) (which should never be grounded), thinking it was a current transformer (CT), the utility's standard. The resultant explosion vaporized the ground s cable, punched a hole in the isolated phase bus duct, and caused a recirculation pump to trip. The reactor was manually scrammed to prevent operation in a region of potential core instability. A LOOP occurred and the EDGs started and loaded their i 1E busses. [LER 50-324/89-009] i Several forest fires and brush fires have impacted the operation of the grid. Fires I threaten equipment and personnel. Fires produce smoke which creates a lower i resistance pathway between transmission lines, causing line faults.

In 1990, at Hope Creek, a brush fire near transmission lines resulted in a complicated scram but no LOOP. [LER 50-354/90-003]  !

19

)

l l

I

In 1990, at Diablo Canyon, a forest fire caused a scram but no LOOP. In 1994, a forest fire caused a partial LOOP but no scram. [LER 50-275/90-015; 94-016]

In 1992, at Oyster Creek, a forest fire caused a LOOP and a complicated scram.

[LER 50-219/92-005]

An earthquake caused a partial LOOP in 1992 at Humboldt Bay, which was in a SAFSTOR condition (permanently shutdown, but with fuel in the spent fuel pool)

[LER 50-31/92-002].

On January 17, 1994, an earthquake struck southern California. At that time and for that reason, the grid in the western states began to separate. The western grid -

separated into north and south islands. The frequency in the south island increased

, - and some loads were lost. Transmission lines tripped and generating units tripped or  ;

j reduced power. Diablo Canyon, in the north island, experienced low frequency. l WNP 2 was also in the north island. Operating nuclear plants in the south island ,

which experienced high frequency were San Onofre and Palo Verde. See

, AEOD/T94-01 for details. On the other hand, the Loma Prieta earthquake in 1989  ;

did not cause g' rid disturbances outside a limited area. The damage to the grid caused l

] by an earthquake is determined by the strategic importance of the equipment mvolved. ]

I t 4

4 l

l

$ I 1

l l

20

. 6.0 POTENTIAL PROBLEMS WITH GRI.D STABILITY 6.1 Normal Contingencies Reliability Councils' minimum criteria for stability require the grid to be operated in a stable 2

manner during and after normal contingencies . NPCC2 requires stability.of the bulk power system to be maintained during and after the most severe of the contingencies listed in Table 6.1. [7] Stability analyses to ensure adequate transmission capability are performed to satisfy the Reliability Councils' criteria. Offsite power availability is related to grid conditions, but the stability analyses done to ensure adequate transmission capability do not necessarily give sufficient assurances that offsite power to nuclear plants will be adequate at all times, as Section 6.3 demonstrates.

Table 6.1: Normal Contingencies [7]

1.- A p w three-phase fault on any generator, transmission circuit, transformer or bus .

section, with normal fault clearing

2. Simultaneous phase to ground faults on different phases of two adjacent transmission circuits on a multiple circuit tower.

3. A permanent phase to ground fault on any transmission circuit, transformer, or bus section with delayed fault clearing 22

4. Loss of any element w thout a fault

! 5. A permanent phase to ground fauli _ circuit breaker, with normal fault clearmg

6. Simultaneous gim; loss of boih poles of a direct current bipolar facility

7. The failure of a circuit breaker associated with an S[pecial }P[rotective }S(ystem] to opera'e .

when required by the following: loss of any element without a fault; or a per=nn-w phase to -

ground fault, with normal fault clearing, on any tranernimaion circuit, transformer or bus'section 6.2 Severe Contingencies [7] ,

Other contingencies with more severe consequences for the grid are listed in Table 6.2. l These are considered unpredictable and steps to reduce their probability of occurrence are ,

recommended by the Reliability Councils as well as measures to mitigate those consequences  !

should the event occur. Analyses of these contingencies to determine their effects att being l 20 .Ihe term

• normal conomeency* defines conditionsunder which the stability of Ibc bulk power system must be maintained. 'Ihe term  ;

• severe comangency' describes conditions under which the stability of the bulk power system cannot be guaransned [

I  !

specific Regional information is sometimes given as representative of all Regions. While it may 1: presentative. there may be

. differences in Cneeria from Region to Region. Information on the same subject for Regions other than the one named should be obtained from the Crieeria of that Region.

22 An element is any electrical device with terminals which may be connected to other electrical devices; usually limited to a generator, transformer, transmission circuit, an HVDC pole. braking resistor, a series or shunt compensating device. or bus section. [19]

21 j i

I L .-

} conducted by the utilities. System stability is nof assured during these severe contingencies.

j_

Adequate offsite power under these circumstances is best assured by preventing the severe '

contingency from occurring (as demonstrated in Section 6.3)-

Table 6.2: Severe Contingencies [8] i i

1. Imss of entire capability of a generating station j

4

2. Less of all lines emanating from a generating station, switching station or substation

3. {

Loss of all tranannasion circuits on a conunon tight-of-7 v

- 4; Per==nant three-phase falt on any generator, transmissioichat, transformer, or bus section, with delayed fault cleanng and due regard to reciosing facilities --

5. The sudden &vy of a large load or major load center .

6. "Ilie eflect of severe power swi@ ansing from outside the Council's interconnected systems j

7. Failure of a M prasareian system, to operate when required following norma' contingencies j

8. 11te operation or perual operauon of a special protective system (SPS) for an event or condition for which it was not intended to operate l

l 6.3 Potential Problems '

Four reports of potential problems related to grid stability were found in which licensees i reviewed stability analyses and instabilities were discovered. The reviews were done as a followup of Information Notice 89-83, " Sustained Degraded Voltage on the Offsite Electrical  ;

Grid and loss of Other Generating Stations as a Result of a Plant Trip," in response to a '

question raised during an electrical distribution functional inspection, and following actual events. The reports are summarized in Table 6.3 and a more detailed event description is given in Sections 6.3.1 through 6.3.4.

l 22

l

. Table 6.3: Grid Instabilities Discovered by Plant Analyses PLANT DATE PROBLEM l ANO1 10/5/91 Dunng peak sununer loads, if both units were off line and the 500-kV auto-transformer was unavailable, the 161-kV offsite power source might not be able to maintain adequate voltage to ANO loads during accident conditions.

Haddam Neck 4/15/92 With the Millstone units at full power, the grid lightly loaded, and Millamae 1,2,&3. a heavy flow of power from the east to the west, certain ground faults could cause the loss of the local grid and trip the Millstcoe units.

Salem 1&2 6/2/87 Necessary to reduce power on Salem and Hope Creek units when -

Hope Creek 9/27/92 severe weather is in the area to avoid grid instability should a unit scram. Necessary to trip a unit if the Deans 500-kV line is out of service and the Keeney line is lost.

Point Beach 1&2 10/12/91 Two scenanos involving tran==6 anion line outages with the Kewaunee 3/28/93 potential to cause loss of all offsite power to Kewaunee were ,

identified. Two instances occurred when Kewaunee and one Point <

Beach unit were offline and the licensee for Point Beach l requested technical specifications (TS) surveillance relief to avoid the possibility of tripping the second Point Beach unit and causing grid degradation.

?

6.3.1 ANO 1: Inability of 161-kV Offsite Power Source to Maintain Adaen=ta Voltane l During the review of Information Notice 89-83, " Sustained Degraded- Voltage on the Offsite i Electrical Grid and less of Other Generating Stations as a Result of a Plant Trip," for i applicability to ANO, licensee engineers found that offsite grid loading on the 161-kV system

~ had increased to the point where reanalysis was necessary to determine the system's +

capability to supply adequate offsite power to ANO. in: ner:tmp determined that, with Units 1 and 2 shut down during expected summettime peak loads the 161 kV system could not provide adequate offsite power to ANO should the 500-kV auto-transformer become  !

unavailable.

The degraded grid voltage analysis accepted by the NRC in 1979 was not updated because no requirement for periodic update existed. The transmission planning engineers recommended m*=ary improvement on the transmission system to maintain adequate voltage on the system. 'Ihe offsite voltage criteria for ANO were more testrictive than the transmission I system criteria; therefore, the ANO offsite voltage requirements were not met.

]

Procedural requirements were established to maintain adequate offsite power to ANO until i permanent arrangements could be made. Transformer tap changers and capacitor bank )'

installation were completed in 1992. [LER 50-313/91-010]

)

23

l i

1 1

6.3.2 Millstone 345-kV Instability  :

i '

Following an electrical distribution system functional inspection, the NRC requested that i

Northeast Utilities (the licensee for the Millstone and Haddam Neck units) provide the results of a simulation of a three-phase fault with delayed clearing due to a breaker failure with a transmission circuit out of service. Northeast Utilities performed several simulations in order to show that, although stability could not be maintained during the event as suggested by the NRC, the system could maintain stability following all normal contingencies and all extreme

contingencies that involved a breaker failure at Millstone. The previous study, done in 1979 and thought to remain valid for current conditions, showed that stability could be maintained.

The simulations showed instability.

• At this point, Northeast Utilities reviewed system stability. Part I of the review concentrated on simulating the normal contingencies listed in Table 6.1. They found that an output of Millstone of 2680 MW could no longer be properly supported by the grid under light system loading conditions. Retiring uneconomical smaller units following the addition of larger resources including the Seabrook nuclear plant (1150 MW), non-utility generators (2000 MW), and the Phase II High Voltage Direct Current (HVDC) Interconnection (2000 MW) to Hydro Quebec concentrated generation in the Millstone area above the level that could be supported by the rest of the system should a normal contingency occur.

The Millstone station output interface, composed of four circuits which are the only connection between Millstone and the grid, is critical to the stability of Millstone operations.

A scheme called " severe line outage detector" (SLOD), an SPS, trips either Units 1, 3, or both following a loss of three of the transmission lines from the station. The 1979 study showed that the SPS in service was sufficient to eliminate stability concerns. The 1992 study showed that with all critical systems elements (generation units, etc.) in service, stability problems exist unless there are limits on the amount of generation from the Millstone units.

That amount of generation was determined to be 2620 MW.

With one critical systems element out of service, a stability problem existed. The two most severe contingencies that experienced instabilities required that Millstone output be reduced i to 1870 MW to achieve stability. The change in system response from 1979 to the present was in the output routing of a single, large, fossil-fueled unit. [LER 50-245/92-020]

6.3.3 blem mi Hooe Creek Transmission Iine OW=e Problems In 1987, a barge accident on the Delaware River damaged or destroyed several towers on the Keeney transmission line. Since the line was expected to be out of service for a year, the .

' licensee developed a scheme designed to eliminate possible instabilities that might occur '

because that line was out of service. A stability analysis showed that with all three units operating at 75-percent power when the Deans 500-kV line faulted, stability problems would develop on all three units (Salem 1 and 2 and Hope Creek), r.ausing them to trip. The -

24

. analysis showed that all three units could be operated safely at full power with output on three lines, provided Salem I was tripped when the Deans line experienced an outage.

The trip-a-unit scheme was supposed to be in operation when all three of the units were operating above 75-percent power. During lightning or thunderstorm activity in the area, power would be reduced below 70 percent and the trip-a-unit scheme would be defeated. In June 1987, the scheme's operation was verified, when an unexpected lightning strike near the Deans switching station actuated the trip-a-unit scheme. Salem 1 tripped from 100 percent power. [LER 50-272/87-007]

In September 1992, the trip-a-unit scheme was again initiated when the Deans line was removed f ~ service for about one month. Salem 1 would have been tripped if the Yecney line experiv i an outage.

l 6.3.4 Kewaunee/ Point Beach I and 2 Transmission Line Outage Problems The Kewaunee unit and the two Point Beach units are located, as shown in Figure 6.4.1, on  !

Lake Michigan, about 75 miles north of Milwaukee, Wisconsin.

Two specific problem scenarios have been l identified at Kewaunee for which corrective O.g,,,g,,g m  !

responses have been identified. In scenario Appleton g n  !

A, with Kewaunee at maximum output, and S n., E line Q-303 out of service, line R-304 trips. l

1. 5' Kewaunee must back down 10 MW to avoid g, i grid instabilities which could cause the bfst generator to become unstable. The resultant generator mstability could cause the loss of i F-84 and Y-51, the remaining transmission .

- 1 lines. At 40 percent power with Q-303 out of service, when R-304 trips, Kewaunee 9 [- ****"

must back down 20 MW to avoid grid instabilities, generator instability, and loss Figure 6.4.1: Kewaunee/ Point Beach of all offsite transmission lines. Transmission Lines [5]

l l

In scenario B, with Kewaunee at 100 percent power, transmission line L-151 is out of service l and R-304 trips. No grid instabilities occur. At light load conditions (40 percent power),

Kewaunee must back down 20 MW to avoid possible grid instabilities, generator instability, and loss of all offsite transmission lines.

Although Kewaunee is more vulnerable, having fewer offsite transmission lines, Point Beach is also susceptible to similar grid instabilities. With Kewaunee in an outage and one Point Beach unit off line, a loss of the remaining operating unit during normal weekday loading would likely result in a degraded voltage condition to the extent that both Point Beach units 25

and Kewaunee IE busses would isolate from offsite power and would transfer to their EDGs.

Both licensees have taken steps to avoid having all three units offline simultaneously. They also took steps to compensate for the loss of generation should all three units be offline in order to assure grid reliability. Barring another complication, the MAIN WUM area would not experienced a blackout, according to the licensee for Point Beach. .

The size of the three plants (not large for nuclear plants, but much larger than other generating units in the an:a) and the remoteness of the sites are major contributors to the potentials for instabilities that exist. [LER 50-305/94-010]

6.4 The Changing Grid Certain emerging issues appear to offer a challenge to the reliability of the grid in the not-too-distant future: independent power producers and restmeturing. Detailed discussions of

. these emerging issues are beyond the scope of this study. They are introduced in the following paragraphs.

6.4.1 Indeoendent Power Producers In November of 1978, the Public Utility Regulatory Policies A'ct (PURPA) was enacted.

The number of facilities producing electricity for their own facilities and selling the  ;

remainder (cogeneration) and those producing electricity for sale to consumers (non-utility generators or small power producers) increased afterward, as a result of the favorable treatment in PURPA, among other things.

Maintaining reliability of the bulk power system while integrating these independent power producers (IPPs) as they are collectively called, is being addressed by NERC and its member Councils. [28]

l 6.4.2 Restmeturing of the Electric Industry

)

As a result of the passage of the U. S. Energy Policy Act of 1992, the Federal Energy Regulatory Commission adopted " Promoting Wholesale Completion Through Open Access; i Non-Discriminatory Transmission Services by Public Utilities," on May 10,1996. It was  !

formerly cited RM94-8.3GO; the current citation is Order 388. This document has become the basis for what is being called "restmeturing." The electric industry is undergoing l substantial changes, the nature of which is unfolding. How the reliability of offsite power to nuclear plants, in particular, will be affected is yet to be detennined.

1 26

7.0 ANALYSIS 7.1 Regulatory Background i Nuclear plants need power to cool the reactor core whether or not the plant is producing power. Consequently, the reliability of offsite power is important to nuclear safety. In 1979, the NRC identified the loss of all AC electrical power to the nuclear plant, called station blackout, as an unresolved safety issue.

7.1.1 Unresolved Safety Issue A-44: " Station Blackout"  :

Station blackout is the complete loss of AC electrical power in a nuclear power plant.

Because many safety systems required for removing decay heat from the reactor core and containment depend on AC power, the consequences of a station blackout could be severe.

Station blackout was shown to be an important contributor to the total risk from nuclear power plant accidents. Additionally, operating experience raised concerns that the reliability of both the onsite and offsite emergency AC power systems might be less than originally anticipated. l In 1979, the NRC designated station blackout as an unresolved safety issue and task action  !

plan A-44 was issued in July 1980. The final report on USI A-44 appeared in NUREG-1032, " Evaluation of Station Blackout Accidents at Nuclear Power Plants," dated June 1988.

7.1.2 10 CFR 50.63: "less of all altematine current oower" [29]

10 CFR 50.63 was adopted in 1988 to implement the resolution of USI A-44. It requires that "Each light water-cooled nuclear power plant licensed to operate must be able to withstand for a specified duration and recover from a station blackout as dermed in i 50.2.

{q.v.} The specified station blackout duration shall be based on the following factors:

(i) The redundancy of the onsite emergency ac power sources; (ii) The reliability of the onsite emergency ac power sources; l (iii) The expected frequency of loss of offsite power; and ,

(iv) The probable time needed to restore offsite power." l Implementation of this section was not required for plants licensed before July 21,1988, if )

the capability to withstand station blackout was specifically addressed in the operating license  ;

proceeding and was explicitly approved by the NRC. Other plants licensed prior to July 21, 1988 and facilities licensed after that date were required to make submittals addressing the factors as listed in the regulation.

27

7.1.3 Renulatory Guide 1.155: " Station Blackout" [30]

This regulatory guide described a means acceptable to the NRC staff for meeting the requirements of f50.63 of 10 CFR Part 50. The regulatory guide further defines station blackout as the '" complete loss of all alternating current electric power to the essential and nonessential switchgear buses in a nuclear power plant." This loss included the loss of offsite power, turbine trip, and failure of the onsite emergency AC power system (usually the EDGs), but not the AC power to busses fed by station batteries through inverters or the loss of AC power from "ahernate ac sources."

7.2 Global Factors The factors which affect the availability of offsite power and are common to all plants are called " global factors." Among the global factors are demand, generation / capacity, capacity margin, and age.

Nuclear plants have been well insulated from the effects of high demand; however, in the Virgil Summer event, high demand was named as a contributor to the grid degradation that caused the 1E busses to isolate from the grid. Also, in the August 10,1996, Western Grid disturbance high levels of demand contributed to the initiation of the event. Peak demand projected for 10 years in each region of NERC shows a steady increase as shown in Appendix A. Low capacity margins indicate that a potential for problems does exist. The insulation of nuclear plants from the effects of excess demand may be eroded in the future.

Plant age averages 38 years. With 38.2 percent of the U.S. electricity generated by plants 26 years or older, age has the potential to become a factor in grid stability.

7.3 Specific Factors Factors which are specific to a plant or an area are called " specific factors." Among the specific factors are size, ability to isolate a fault, ability to purchase power, weather effects, and transmission load dynamics.

1 7.3.1 Sim Plant size caused a large load to be shifted to much smaller non-nuclear plants in the Virgil Summer event in 1989 and two separate events at Palo Verde 1 in 1989. The average nuclear plant size is 957 MWe, while the average steam-fired plant size is only 200 MWe.

IAss of a nuclear unit, therefore, drops a very large load on nearby units. Ioss of two nuclear units at one site simultaneously is a severe strain on the grid's resilience. Of the  ;

numerous dual unit scrams which have occurred (and one four-unit scram), only the WSCC l events of December 14,1994, in which both Diablo Canyon units scrammed, and August 10, 1996, in which both Diablo Canyon units and Palo Verde Units 1 and 3 scrammed, contributed to a major grid disruption.

28

l- ,

t

. 7.3.2 Ability to Isolate a Fault j l The Waterford event in 1990 involved a fault that propagated from offsite to Waterford.

Waterford scrammed and a cascading failure due to declining voltage occurred which was recorded at River Bend.12Salle and Braidwood are connected by two 235 kV lines for one

site to supply offsite power to the other. The lines also propagate grid disturbances from one

. to the other.

l l.

1 7.3.3 Plant (AreabSoecific Vulnerabilities i.

Because their initial stability analyses were not required to be updated, ANO, Millstone, and

Salem / Hope Creek sites became vulnerable to certain potential instabilities as detailed in ..

Section 6. In NPCC NE, smaller, less-efficient plants were retired when plants like Seabrook and Millstone 3 came on line. Many changes in the grid which affect its reliability ,

can go unnoticed in the absence of a challenge. Without regulatory requirements to update i their stability analyses, the licensees mentioned in Section 6 were motivated to reexamine  ;

i their stability analyses by an information notice, electric distribution system functional

inspections, and by events.

I t I

i l

4

)

i

. 29

i 8.0 IGNDINGS AND CONCLUSIONS I 8.1 General Findings l

The condition of the grid is dynamic: capacity changes; demand changes; transmission  ;

patterns change; equipment ages; new equipment is brought on line; and equipment is retired. Two relatively new factors are emerging: independent power producers and restructuring of the electric industry.

l NERC has adopted programs argi procedures to deal with forecasting, normal operations, emergency conditions, and recovery from system collapse. The programs and procedures as detailed in the various referenced documents appear to give a basis for assurance of orderly operation. ,

8.2 Specific Ndings The study findings are as follows:

(1) Demand will continue to increase yearly at a rate which will exceed the rate of increase of capacity growth further reducing capacity margins. Reducing capacity margins tends to-increase the chance of instabilities.

1 (2) Average plant age will tend to increase as older plants will have to remain on line to make up for the diminishing reserves. Schemes to protect the integrity of an aging generator may increase the potenti al for grid instabilities. Increases in outage occurrences and duration i may occur due to increased equipment failure due to aging. '!

(3) The 1979 stability analyses conducted to meet NRC requirements demonstrated adequate offsite power for nuclear plants in 1979. Most plants' stability analyses may not have been l

updated since then. '

i 8.3 Conclusion i

The " grid," the bulk power supply, as managed by the North American Electric Reliability Council member utilities, has adequate resources to give reasonable assurance that the reliabili.y of the system will be maintained under normal conditions. On the whole, the grid is stable and reliable. Problems described in the Regional assessments as indicated in

Section 4 as well as uncertainties introduced by restructuring of the electric industry indicate the need to monitor grid conditions on a regular basis.

L 30 I

l l

9.0 BIBLIOGRAPHY 1 U.S. Nuclear Regulatory Commission, " Evaluation of Station Blackout Accidents at Nuclear Power Plants," NUREG-1032, June 1988.

2 ECAR, Coordinated Regional Bulk Power Supply Program, DOE Form IE-411, Volumes I and II, Canton, OH, April 1,1992.

3 MAIN, Regional Reliability Council Coordinated Bulk Power Supply Program, DOE Form IE-411, Iombard, Illinois, April 1,1992.

4 Southeastern Electric Reliability Council, Coordinated Bulk Power Supply Program, DOE Form IE-411, Chattanooga, TN, April 1,1992.

5 Southwest Power Pool, Coordinated Regional Bulk Power Supply Program, DOE Form IE-411, Little Rock, AR, April 1,1992.

6 Northeast Power Coordinating Council, Regional Reliability Council Long Range Coordinated Bulk Power Supply Program, DOE Form IE-411, New York, NY, April 1, 1992.

7 Electric Reliability Council of Texas, Coordinated Bulk Power Supply Program, DOE Form IE-411, Austin, TX, April 1,1992.

8 MAPP, Regional Reliability Council Coordinated Bulk Power Supply Program, DOE Form IE-411, Minneapolis, MN, April 1,1992.

9 MAAC, Regional Reliability Council Coordinated Bulk Power Supply Program, DOE Form IE-411, Philadelphia, PA, April 1,1992.

10 Western Systems Coordinating Council, Coordinated Bulk Power Supply Program, DOE Form IE-411, Portland, OR, April 1,1992.

11 North American Electric Reliability Council, Energy Supply and Demand Database 8, Prmceton, NJ, June 1996.

12 North American Electric Reliability Council, NERC Operating Manual, Princeton, N.J.,

1995.

13 North American Reliability Council,1995 Annual Report, Princeton, N. J.,1996.

14 North American Electric Reliability Council, Reliability Assessment, 1996-2005,

! Prmceton, N. J.,1996 31 l

l 15 U.S. Department of Energy, Office of Coal, Nuclear, Electric, and Alternate Fuels, Energy Information Administration, " Inventory of Power Plants in the United States 1993," DOE /EIA-0095(93) Washington, D.C., December 1994. l 16 Federal Power Commission, Northeast Power Failure, November 9 and 10,1965, U.S.

Government Printing Office, Washington, D. C.,1%5. l 17 i Federal Power Commission, Staff Report on the July 13-14,1977 Electric System Disturbance on the Consolidated Edison Congpany of New York, Inc., System,  !

Washington, D. C., August 4,1977.

i 18 North American Electric Reliability Council, e-mail file, Prmceton, N. J.,1996 19 North American Electric Reliability Council, Glossary of Terms, Princeton, N. J.,1996 j.

20 Facsimile from National Oceanographic and Atmospheric Administration, National Climatic Data Center, Climate Services Division, " Surface Weather Observations:

Washington D.C. (National Airport), Asheville, N.C., January 18-21, 1994.

21 Telephone Conversation with MAAC PJM Dispatcher, February,1994.

1- l x

22 Telephone conversation with NRR Project Manager for Surry in February,1994.

4- l

{ 23 North American Electric Reliability Council, Report on Electric Utilities' Response to the 3

Cold Wave ofJanuary 1994, Princeton, N. J., April 11, 1994.

!- 24 Western Systems Coordinating Council, Disturbance Report for the Power System  !

l Outages that Occurred on the Western Interconnection on July 2,1996 andJuly 3,1996, I

Salt lake City, Utah. '

i 25 Western Systems Coordinating Council, Disturbance Reportforthe PowerSystem Outage that Occurred on the Western Interconnection August 10,1996, Salt Iske City, Utah. '

26 U.S. Department of Energy, Office of Emergency Planning, " Electric System i l Disturbances Reported to the Department of Energy for [ month year]" database, January l 1985-December 1994.

27 Information Access Group, Inc, Nuclear Department GSU Transformer Study Final i j - Report ofFindings and Recommendations, Prepared for Public Service Electric and Gas i 4

s Nuclear Department, Salem and Hope Creeks Nuclear Plants, N. J., March 26,1990.  !

l l - 28 North American Electric Reliability Council, Integrating Non-Utility Generators, j Pnnecton, N. J.,1992.

I' l

29 U.S. Code ofFederal Regulations, paragraph (a), " Requirements", subpart 63, part 50, t Chapter I, Title 10, " Energy".

32 5

30 U.S. Nuclear Regulatory Commission. " Station Blackout," Regulatory Guide 1.155, August 1988.

33

(.

i i .:

j LERs:

j 50-029/88-008 50-293/92-016 50-339/85-005 50-425/94-001

! 50-029/91-002 50-293/93-004 50-339/86-009 50-443/91-008

50-155/88-008 50-293/93-022 50-341/94-001 50-445/91-013 1

50-219/92-015 50-301/85-005 50-344/90-037 50-445/91-019 7 50-219/93-001 50-301/87-002 50-344/94-005

50-445/91-021 50-220/85-005 50-301/89-002 50-346/87-011 50-445/92-016 50-220/90-023 50-301/93-003 50-348/87-010

50-445/95-002 50-220/93-007 50-302/89-023 50-348/92-007

^

50-446/94-012 50-244/91-002 50-302/89-025 50-352/95-002 50-454/85-052 i 50-244/92-007 50-302/89-025 50-353/94-008 50-454/91-001 l 50-244/94-005 50-304/86-011 50-354/90-003 50-454/91-002

{ 50-244/94-012 50-304/90-011 50-362/85-010- 50-456/88-022

, 50-247/85-006 50-305/92-017 50-364/85-010

' 50-456/89-003 50-247/85-016 50-309/88-006 50-369/89-029

50-456/90-004 50-247/87-004 50-309/91-005 50-369/91-001 50-456/91-003 50-247/90-016 50-312/88-015 50-373/89-009 50-458/86-002 i 50-247/94-001 50-313/87-005 50-373/90-006 50-458/88-012

} 50-249/89-001 50-313/89-002 50-382/90-003 50-458/89-042 j 50-251/85-004 50-316/87-007 50-382/90-003 50-458/92-005

[ 50-254/90-013- 50-316/91-004 50-382/90-012 50-458/94-005 l

{

50-254/92-002 50-316/91-006 50-382/91-013 50-461/92-001 50-255/87-024 50-317/87-012 50-387/87-034 50-482/87-030

50-261/86-005 50-317/93-003 50-388/91-008 50-482/87-037 l l 50-263/91-019 50-321/88-018 50-395/89-012 50-482/92-016

50-263/94-003 50-321/91-001 50-395/91-003 50-483/85-005 i

)

50-265/85-009 50-323/86-001 50-395/92-008 50-483/85-011  ;

I 50-265/91-008 50-323/88-008 50-397/85-007 50-483/85-038 j 50-265/93-013 50-324/89-009 50-397/90-024- 50-498/91-007

! 50-271/91-005 50-324/90-015 50-397/90-031 50-499/89-009 50-271/91-014 50-324/91-016 50-397/91-017 50-528/85-063

! 50-272/91-024' 50-325/93-008 50-397/93-019 50-528/85-088 I

! 50-272/94-011. 50-327/85-034 50-397/95-007 50-528/86-003 I 50-275/90 015 50-327/92-027 50-400/89-017 50-528/86-047 I 50-275/93-011 50-331/91-008 50-410/89-014 50-528/88-010 50-275/94-010 50-331/92-001 50-410/91-017 50-528/89-001 l

!' 50-275/96-012 50-331/92-002 50-410/92-018 50-528/89-004 l 50-277/92-010 50-331/95-001 50-410/92-033 50-528/89-015 l ,50-277/92-012- 50-334/93-016 50-412/87-032 50-528/91-010 50-282/85-012 50-334/94-008 .50-412/87-036 50-528/92-016

'50-285/91-028 50-334/94-005 50-412/90-019 50-528/96-004 50-286/91-004 50-335/94-007 50-416/91-005 50-529/89-001 50-293/90-008 50-336/87-012 50-416/91-006 _50-530/89-001 ,

} 50-293/91-024- 50-336/88-011 50-424/95-002 50-530/91-008 i

34 i

4

i j . .

i :

! l 4

i l Appendix A t i l hh Demand Generation l

j g{

f >

Capacity Margin

! /' 3 Charts

~ ~ ~

l w ,

isc:nd

~.

j .

i

\

4

! i I

i i

P;ck Dem:nd far 10 Y;cra Ccpacity Mcrgin MW X 1000 Pct cs so 1

54 - - -

j 25 - - -- -- . . . . .....

• ~ 1B "

53 - ---

, _ g. 4_ _

_g _ gr-gg . ..... . .. .. .....

20 - -- - . . .. . ....

. T ' ". ?. . >

, , _ _ _ l

,,,r. . . .... .. ... . .....

_ x x x x x 33 10 i

/ / / / ////// / / / / / / / / / /

w., v..,

• _ . . x_...

I

[

I l

ECAR 1 Beaver Valley 1 & 2 i

m 8_- ,,--' Big Rock Point i

__ o,,_-m  ;

D. C. Cook 1 & 2 1 Davis-Besse 1995 Generation Fermi 2 1995 Capacity Perry A-1

P:ck Dem:nd f r 10 Yzra Ccpacity M rgin MW X 1000 Oct C3 40 - - -

' ' ' ' ' ' ~

sa - - --- - - - - - - -- - -- - - ---

c

' E 'E _

30 -

?-S  %- q _-----

- - - ' ------ -- ~ ~ ' S-53 --- -

25 - --- - --------- --- - - MI 48 - - - - - -'- -- - --- --

20 ----- -- -- - ----- - - - . -

43 -- ---- - *

~, L' es - " # - * * -

10 -o m

, g. -- ----------- - ,

_3' l gglp=.-*- -- - - - -

33 0

/ / / / / / / / / / / / / / / / / / / / .

Year Year ERCOT 9:"-" 9 wen

,,, o Comanche Peak 1 & 2 South Texas 1 & 2 1995 Capacity 1995 Generation .

1

,A-2

P ck Dem:nd f:r 10 Y;cro Ccpccity Mcrgin MW X 1000 Pct se 35 p

_ wa. ;; _ , ; ; _ _, + ,

25 - -------.. .. . . ...

~ - ,>n.= - . ..... . .

K_ ... . j.. _

.u

.. . 15 - -- --- . . . . . ..

ir" .

'S* / / / / / / / / / l~* / / / / / / / / /

Year Year i x . .., x_...

~

~.

"^^

Calvert Cliffs 1 & 2 Hope Creek

~~

(D~~'" 1995 Capacity 1995 Generation

. . , , Limerick 1 & 2 Peach Bottom 2 & 3 Salem 1 & 2 Susquehanna 1 & 2 Three Mile Island 1 A-3

P :k Demand fer 10 Y;cro C2pacity M2rgin MW Pct i e,000 35 l

....... ...... .. C 1N .,  %

, ... . ., ...... ......... s. ,__,_---1 25 --o-.u g ,w-

)

e

- - --~ ~ ~ -

7,500 ---

l a- so . .. . .. . . .

. . p .

^- "

., s'* .. . ..... .....

8 X--'X ~X - ^g -g -g

..- t IP" >

s 8 s' s' f f 4 f f 4' '  %*  %* 8 4 4 4 4' f S Year Year  !

l Ms.- *ww. M summer aww.

l i

i H

= MA N EMO

@ydr.9% =

._ m @M34% Callaway 1995 Capacity 1995 Generation

~

A-4

Ccp; city Mergin Pock Dam:nd fcr 10 Yacra  !

l MW X 1000 Pct  ;

45 24 fC 40 ~' ' -e w .;. g _ - -

- p .:. : ,_ _;. .ec .: q 35 - - - ----- - - - - ---

23 -- -*-

) 30 - ---- - - -

y, . . .

25 - - ---- --- - - - --

. _ ,;_, s

.- . W .~ ?

~

,,, ,. .-n - . T *~ ~ " . . .

,  ; x y l

> < < i i i eiii > < < < < < < < < < ,

Year Year j i

MA N NI Braidwood 1 & 2 I

Byron 1 & 2 l

Dresden 2 & 3

.- m LaSalle 1 & 2 1995 Generation Quad Cities 1 & 2 1995 Capacity Z,on i 1 & 2 i

I i

A-5

Pcck Demand far 10 Y;cra Ccpacity M:rgin MW Sct o.soo 40 s, coo - ----

C 35 s -e g- - - --. .... . ... . ......

30

- . - - - - D " * ' . e -- - m - - HI 3 .......... . ................

3,9 g 25 - - -------- - . ..

7,g ..

~

'8"'WV 7-

^

7,000 *----

,- e's

,,,g ir.

---* ~ ~

. . . . ........... is - - - . ... . .

j_ x c to s,o/oo / / / / / / / / / / / / / / / / / / /

Year Year M e.nenn

• wm w Msn

• winw -

MA N SCI S_o. 9feuc4eer15%

re,os Clinton 1995 Capacity 1995 Generation -

.A-6

P :k Dem nd far 10 Yacra Ccpacity MCrgin ' -

~

MW X 1000 Pct 13 35 12 - - - - -- -- - - - - -

( 30 -- --.. .. . ... . .

4 ,a -b = .g - --Il gp. g qq . . . . .. . . . . . .

25 -

)

gn . ... . . . .. . . ... .

. y .,, A l gg ,,,,,, _, ,,___ - ,

' v i m s,

,,,,,-S" 5 ^

g V. . . . . .. . . . . . . . g g)

_X_,n X 4 -.

8 10

/ / / / / / / / / / / / //////pp Year Year i

Hyeo 3%

heleer 21%

beteer 14%

= MA N WUM OHyeo2%

,,e_,,, Point Beach 1 & 2 .

Kewaunee ,

1995 Capacity 1995 Generation .

A-7  !

i

. . . . ~. _ _ _ _

P ck Dem:nd far 10 Y=ro Ccpacity M rgin i

MW X 1000 Pct 40 30 25 -

Yk ~ g----- ... . . ..

35 - - - - - - - -- (

,, . . . ]'- . .

,0,

, ,) . .... . .. . ..' '

-El

,p - 10 -----------.- ... .. ....

,, . . _ e-. e. E* . . .. . . .. .......

"~ 5 - - . . . . .

C

> $////////

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' " ' .,, Fort Calhoun Monticello 1995 Capacity 1995 Goerotion Prairie Island 1 & 2 ,

. .A-8 i

Pcck Dem:nd fsr 10 Y cro Capacity M:rgin MW X 1000 Pct 24 30 , ,

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25 -

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Year Year M simim.

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NPCC NE ,

Haddam Neck L

Maine Yankee ,

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om- n Pilgrim j 1995 Capacity 1995 Generation Seabrook i Vermont Yankee t

A-9 i

Pcck Demand fcr 10 Yccra Ccpacity Margin MW X 1000 Pct 32 40 30 -- - .. ... .. ,,,,,_ , ,,

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Ginna "d N - i 3s LPP 24%

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A - 10

Pack Demand f:r 10 Y:cra Ccpacity M rgin ' '

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~= Turkey Point 3 & 4 1995 Capacity 1995 Generation -

1 F

l A - 11 l

Pcck Demand f:r 10 Y;cro .Ccpacity M rgin .

MW X 1000 Pct 50 35 45 - -- * * **' ' '

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SERC SOU Farley 1 & 2  :

y* - oi,_ m s, m - ( Grand Gulf  !

-= Hatch 1 & 2 '

1995 Capacity 1995 Generation Vogtle 1 & 2 , j O

A - 12

Pc k Dem nd f r 10 Y Cra Ccpacity Margin '

MW X 1000 Pct to 3

30 -

17 .s . ..... . . . .. . . . ..

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Browns Ferry 1, 2, & 3 Sequoyah 1 & 2 1995 Capacity 1995 Generation [

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i A - 13 i i

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Pcck Demcnd f r 10 Y;cra Ccpacity Mcrgin MW X 1000 Pct sa 27 ~ -- - - -- --

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Year Year i

• _ _ . . . x _ . ....

1

~

_ SERC VAC 4

Brunswick 1 & 2 Cataba 1 & 2 H. B. Robinson 2

~ ~

McGuire 1 & 2

~

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~ North Anna 1 & 2

,,,,, , Oconee 1, 2, & 3 1995 Capacity 1995 Generation Shearon Harris .

Surry 1 & 2 V. C. Summer -

A - 14

PC2k Dem:nd f:r 10 Y;crs C pacity M rgin MW X 1000 Pct 20 45

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x. x e.e, . ....,

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Hydro 0% sounteer 14s l

_ ,Ny' _

t K , , , , ,

Wolf Creek x Other 14% Steam 90%

N 1995 Capacity 1995 Generation A - 15 ,

PC k Demand f r 10 Y cra Ccpacity Margin MW X 1000 Pct so 45

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Year Year x .. . x_...

i Hydre ,,

mm SPP SE 9 980%

~" ~"

ANO 1 & 2 R.iverbend

~"

Waterford 3 i 1995 Capacity 1995 Generation ,

. I A - 16

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Pc k Demand fzr 10 Y;2rs Ccpacity M:rgin MW X 1000 Pct 30 40

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,- *P w. m E SPP WCN 94 =~~ 1995 Generation 1995 Capacity A - 17

Pack Dem:nd fsr 10 Y;cro Ccpacity Mcrgin MW X 1000 Pct 21 40 y, . ... .... .. . .... .. .....

I n -

97 . .. . . . . . . . .

.C 30 -

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/ / / / / / / / / / / /////////

Year Year

., ar *. =

WSCC AZN 09evelser17%

_ m m

Palo Verde 1, 2, & 3 1995 Capccity 1995 Generation A - 18

Pcck Dem:nd far 10 Yacra Ccpacity M rgin Pct MW X 1000 a

so 35 - -- --- - - -- ---

y, . .

IP 4  % ,

30 -- - I '-D---e es & p - H I

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Yeer Yeer

~ ~ ~

/ -

WSCC CNV

-=

Diablo Canyon 1 & 2

% ~~ San Onofre 2 & 3 om. ies om, ,, j 1995 Capacity 1995 Generation i

[

A - 19 l

Pc k Demand for 10 Years Capacity M:rgin MW X 100p Pet 50 40 45 - ----- -- ----*-------

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< <<<<<<<<< Year M s w =

• wman M summe

• wmm

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- /

r WSCC NW NN ' oi om.- a t

't x WNP 2 si m m smm 1995 Capacity 1995 Generation O

A - 20 i

Peak Demand fzr 10 Years Ccpacity M:rgin MW Pct C,000 32 e

( ** ' ' '~~** '* *-- - -

C,500 - - - - - -

• ,--M'

'9* 4 IL p

5. # p- g y

4, 28 -N qp. - . -

g..... . . . . . . . . , .

.sy,,.

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24 - * ..... . . .

a n#

7,000'F- - - - -- - - - -- -- - - - --

22 - - - ---..... ..... . . ..

8,500 20

/ / / / / / / / / / / / / / / / / / / /

vf Year Hye. an Myee tes x\.//

sie.- eos V . . -

.g Other 4% geoem 79%

y -_

ota=

WSCC RM  :

f v' . ,

y f

1995 Capacity 1935 Generation ,

f A - 21

i.:

i ,

I i

Appendix B j $2, l

o 3 2,

! /\t Plant Age

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- - . - . _ . - . - . - - - . . . ._- - _ . - . -- ~ . . ~

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5 l* FLANT AGE PLANT AGE PLANT AGE (Ahhabeticauy by State) iUS (By Manknum Age) iUS (By Average Age) iUS State Max Min Avg Avg State Max Min Avg Avg State Max Min Avg Avg Alabama 70 4 39 I US 102 2 38 Montana 89 10 58 20 Arizona - 86 3 33 5 California 102 2 39 i Vermont 97 3 54 16 Arkansas 71 2 33 5 Utah 99 2 36 -2 Idaho 89 2 50 12

Cahfortua 102 2 39 1 Washington 97 2 40 2 Maine 92 5 50 12

Colorado 90 2 40 2 Vermont 97 3 54 16 N Hampshire 78 5 49 11  !

Connecticut 92 5 47 9 New York 97 3 44 6 Wisconsin 95 2 48 10

] Delaware 48 2 23 15 North Carolina 97 7 47 9 North Carolina 97 7 47 9  ;

Flornia . 59 2 25 13 Texas  % 2 31 7 Connecticut 92 5 47 9 Georgia 92 3 43 5 Wisconsin 95 2 48 10 South Camlina 90 4 46 8 l Idaho 89 2 50 12 Connecticut 92 5 47 9 New York 97 3 44 6 I

!!!inois 70 2 32 4 Maine 92 5 50 12 West Virginia 86 6 44 6 Indiana 82 2 31 -7 Georgia 92 3 43 5 Georgia 92 3 43 5

! bwa 82 2 38 0 Virginia 92 2 34 -4 Michigan 90 2 42 4 i Kansas 68 2 31 -7 Massachuseus 91 4 40 2 Minnesota 89 2 40 2

• Kensucky 70 5 37 -1 Nevada 91 2 37 -1 Oregon 89 2 40 2 l leuisiana 53 3 29 -9 South Carolina 90 4 46 8 Massachuseus 91 4 40 2 I i Maine 92 5 50 12 Pennsylvania 90 6 33 -5 Washington 97 2 40 2 MD&DC 70 2 30 -8 Michigan 90 2 42 4 Colorado 90 2 40 2 Massachusetts 91 4' 40 2 Colorado 90 2 40 2 California 102 2 39 1 Michigan 90 2 42 4 Oregon 89 2 40 2 Alabama 70 4 39 1 Minnesota 89 2 40 2 Idaho 89 2 50 12 US 102 2 38 Mississippi 59 11 35 -3 Minnesota 89 2 40 2 lowa 82 2 38 0 Missouri 66 2 30 -8 Montana 89 10 58 20 Nebraska 80 2 37 -1 Montana 89 10 58 20 West Virginia 86 6 44 6 Nevada 91 2 37 1 Nebraska 80 2 37 1 Arizona 86 3 33 -5 Kentucky 70 5 37 -l Nevada 91 2 37 -1 Tennessee 85 9 33 -5 Utah 99 2 36 -2 N llampshire 78 5 49 11 lowa 82 2 38 0 Mississippi 59 11 35 -3 New Jersey 65 2 29 -9 Indiana 82 2 31 -7 North Dakota 58 10 35 -3 New Mexico 6r 7 33 -5 Nebraska 80 2 37 -l Wyoming 73 3 34 -4 New York 97 3 44 6 N llampshire 78 5 49 11 Virginia 92 2 34 -4 North Carolina 97 7 47 9 Wyoming 73 3 34 4 New Mexico 68 7 33 -5  ;

North Dakota 58 10 35 -3 Ohio 72 2 29 9 Arizona 86 3 33 5 Ohio 72 2 29 -9 Arkansas 71 2 33 -5 Arkansas 71 2 33 -5 Ok!homa 71 4 32 4 Oklahoma 71 4 32 -6 Pennsylvania 90 6 33 -5 Oregon 89 2 40 2 Illinois 70 2 32 4 Tennessee 85 9 33 -5 Pennsylvania 90 6 33 -5 MD & DC 70 2 30 -8 South Dakota 64 4 32 4 Rhode Island 65 8 29 -9 Alabama 70 4 39 1 Oklahoma 71 4 32 4 South Carolina 90 4 46 8 Kentucky 70 5 37 -1 Dlinois 70 2 32 4 South Dakota 64 4 32 4 Kansas 68 2 31 -7 Texas  % 2 31 -7 Tennessee 85 9 33 -5 New Mexico 68 7 33 -5 Indiana 82 2 31 -7 Texas  % 2 31 -7 Missouri 66 2 30 -8 Kansas 68 2 31 -7 Utah 99 2 36 -2 New Jersey 65 2 29 -9 Missouri 66 2 30 -8 Vermont 97 3 54 16 Rhode Island 65 8 29 -9 MD & DC 70 2 30 -8 Virginia 92 2 34 -4 South Dakota 64 4 32 4 Rhode Island 65 8 29 -9 Washingion 97 2 40 2 Mississippi 59 11 35 -3 New Jersey 65 2 29 -9 West Virginia 86 6 44 6 Florida 59 2 25 -13 Ohio 72 2 29 -9 Wisconsin 95 2 48 10 North Dakota 58 10 35 -3 touisiana 53 3 29 -9 Wyoming 73 3 34 -4 touisiana 53 3 29 -9 Florida 59 2 25 -13 US 102 2 38 Delaware 48 2 23 15 Delaware 48 2 23 15 B-1