NEPOOL OPERATING PROCEDURE NO. 17

Load Power Factor Correction

Approved:		August 20, 1998 by the NEPOOL Regional Market Operations Committee and the NEPOOL Regional Transmission Operations Committee to be implemented for the Second Effective Date for Market Implementation.

References:

NEPOOL Operating Procedure No. 5			Unit Outages (OP 5)

NEPOOL Operating Procedure No. 12		Voltage and Reactive Control (OP 12) 

NEPOOL Operating Procedure No. 14		Technical Requirements for Generation and Load (OP 14)

NEPOOL Operating Procedure No. 19		Transmission Operations (OP 19)

SATELLITE INSTRUCTIONS:

CONVEX:			NONE

MAINE:			NONE

NEW HAMPSHIRE		NONE

REMVEC II			NONE

TABLE OF CONTENTS

I.	Introduction	3
II.	Load Power Factor Requirement	3
III.	Survey Procedure and Evaluation	4

Appendices

Appendix 1 - Methodology for Developing Load Power Factor Limits

Appendix 2 - Instructions for the NEPOOL Power Factor Survey

I.	
Introduction

Large power transfers on the transmission system and the provision of first contingency coverage requires that adequate reactive capacity be maintained on generators to sustain system voltages.  Participants should not rely so heavily on reactive support from the transmission system that voltages cannot be maintained during stressed system conditions.  On the other hand, Participants should not over-correct their loads such that reactive power (VARs) are being exported to the transmission system creating high voltages and degrading system stability.  To provide for reliable operation, the reactive requirements of the system must be analyzed from a regional standpoint.  The analysis must recognize the following:

1.		Large power transfers within or between pools/areas can significantly increase reactive power (I2X) losses;

2.	The loss of 345KV transmission lines can load remaining lines more heavily and significantly increase I2X losses;

3.	Outages of major generators not only remove significant reactive sources but can also result in large MW transfers and increased I2X losses;

4.	Power transfers can reach a point where not enough VARs can be transmitted to or away from an area to maintain acceptable voltages;

5.	The system can reach a state where even though voltages appear adequate, most available VAR generation is being used and a contingency might seriously degrade voltages and reactive performance, and may necessitate emergency action;

6.	During light load periods, line and cable charging may produce voltages so high that circuits must be opened to reduce voltages;

7.	Insufficient reactive compensation in a single area can impact neighboring areas and affect overall pool operation.

II.	Load Power Factor Requirement

This NEPOOL Operating Procedure establishes ranges of acceptable load power factors for various NEPOOL areas to provide for reliable system reactive performance.  The ranges of acceptable load power factors consist of a bandwidth of load power factor expressed as a function of load level.  The bandwidth between a pair of limiting curves represents the range of recommended load power factor.  The ranges are determined through loadflow simulations at various load levels.  Appendix 1 contains the methodology for developing the ranges of acceptable load power factors. 

The Transmission Provider has responsibility to monitor and manage power factor and add/remove reactive resources to meet the Area’s established ranges of acceptable load power factors.  Generating units connected to the bulk power transmission system and sub-transmission system are expected to comply with the voltage schedules in OP 12 (as applicable) and operate according to reactive capability curves provided under OP 14.
  
The ISO will conduct an annual review of the most recently developed curves to determine if they require updating.  Factors to be considered are significant changes in the transmission and/or generation system, load growth, etc.  If it is determined that the curves require updating, the necessary studies will be undertaken by the ISO, with Participant input through the Voltage Task Force.

III.	Survey Procedure and Evaluation

On an annual basis, the ISO Staff will survey the NEPOOL Participants to measure compliance with the ranges of acceptable load power factors.  This survey procedure is covered in Appendix 2, Instructions for the NEPOOL Power Factor Survey.  By surveying load power factors and comparing them against the ranges, the ISO can determine if load power factors are within reasonable tolerances for reliable operation.  The survey data also provides the ISO with more accurate data for conducting studies.

The ISO is charged with the task of evaluating the survey results.  The evaluation is done by plotting the six load power factor points on graphs that establish the ranges of acceptable load power factors.  If all points for a Participant fall within the bandwidth of the curves, the standard have clearly been met.  If there are points outside the bandwidth, the ranges of acceptable load power factors have not been met.  The degree of noncompliance is quantified by identifying the one high load point and the one low load point which are furthest from the nearest curve (upper or lower).  For each of these two points, the reactive capability required to correct the load power factor to the nearest curve is then calculated.

A summary of the survey results will be presented to the NEPOOL Regional Transmission Operations Committee for appropriate action.

This NEPOOL Operating Procedure is intended to complement other NEPOOL Operating Procedures.  Generator reactive capabilities are submitted under NEPOOL Operating Procedure 14 (OP 14) - Technical Requirements for Generation and Load, Appendix B (Generator Reactive Limits).  Voltage and reactive operating constraints are directly addressed in NEPOOL Operating Procedure 12 (OP 12) - Voltage and Reactive Control and also considered in the Transmission Criteria of NEPOOL Operating Procedure 5 (OP 5)  - Unit Outages and in granting short term and annual maintenance schedule outages.  NEPOOL Operating Procedure 19 (OP 19) - Transmission Operation provides guidance on the reliable operation of the transmission system including voltage and reactive limitations and contingencies.

	APPENDIX 1
	METHODOLOGY FOR DEVELOPING LOAD POWER FACTOR LIMITS
I.	Area Definitions

The NEPOOL system is currently divided into five areas based on voltage/reactive performance, the number and strength of interconnections between voltage levels, and physical characteristics such as length of transmission lines, overhead or underground construction, etc.  These areas are updated from time to time as system changes dictate.  The five areas are shown in Diagram 1 and described below:

1.	North (Maine, New Hampshire, and Vermont)

The North area contains many power resources.  The long 345 and 115 KV lines in the North can cause excessively high voltage when reactive losses are low (lightly loaded lines).  When these lines become heavily loaded reactive losses increase significantly and can cause low voltages.

2.	Northeast Massachusetts

The Northeast area contains a large load relative to its one centrally located generating station.  The Sandy Pond converter, which imports up to 2000 MW from Quebec over the Phase II HVDC interconnection, resides on the outskirts of the Northeast Massachusetts area.  Power is transmitted into the area by several 345/115 KV step-down transformers,  115 KV lines and a 115 KV tie to the North area (Hudson-Dracut) that can automatically trip during periods of large Northern New England to Southern New England power transfers.

3.	Southwest (Connecticut and central/western Massachusetts)

The Southwest area contains a large load, an extensive 345 and 115 KV system consisting of moderate length lines, and a strong 345/115 KV interconnection due to numerous and dispersed step-down substations.  At intermediate load levels, large imports coincident with sparse economic generation could lead to low voltage.

4.	Southeast (Rhode Island and southeast Massachusetts)

The Southeast area can import or export large amounts of power depending on unit availability and dispatch.  The 345 and 115 KV lines are short and the 345/115 KV interconnection is strong due to numerous and dispersed step-down substations.  At heavy load levels, the unavailability of key generating units could lead to low voltage.

5.	Boston (the city and nearby suburbs)

Boston contains a significant 345 and 115 KV cable system.  The capacitive characteristic of these cables provides substantial reactive support during heavy load periods but may cause high voltage during light load periods.  The Boston area predominately imports power.

II.	Testing Criteria

A general criteria is used to provide for uniform levels of reliability within all the areas.  Two rules are applied during various stages of testing: zero VAR interchange and minimum/maximum voltage.  For this analysis, zero VAR interchange makes each area responsible for its own reactive needs and minimizes the need to consider voltage/reactive performance of areas outside of the area being studied.  Although zero VAR interchange is rarely achieved in actual operation, it builds into the load power factor requirements a level of reliability beyond that provided by the outage of lines and generators.

 The two rules described above are used to establish minimum and maximum load power factors for each area at three discrete load levels: heavy (100%), medium (75%), and light load (40%).  A curve connects the three minimum points and another curve connects the three maximum points.  The bandwidth between these two curves represents the range of load power factors that establish the standard.  Diagram 2 shows an example of minimum and maximum load power factors as a function of load level.

III.	General Testing Procedure

Export and import conditions are evaluated for each area at each load level with the most restrictive load power factor becoming the area standard.

Loadflows used for these tests are developed using the assumptions listed in Appendix 1, Table 1.  Testing focuses on only one area at a time - i.e. "study area".  To develop minimum load power factor limits the loadflow case is biased toward low voltage conditions.  To develop maximum load power factor limits the loadflow case is biased toward high voltage conditions.

Low voltage/minimum load power factor testing is done in two distinct stages.  Stage I testing establishes load power factors that are verified in Stage II testing.  The most restrictive load power factor of the two stages becomes the area standard.

High voltage/maximum load power factor testing involves only Stage I testing.

IV.	
Low Voltage Bias - Stage I Test

In Stage I testing the study area is biased towards low voltage conditions.  Then the worst contingency is simulated along with all normal operator actions that can be achieved in ten minutes.  Finally, the load power factor of the study area is adjusted until voltages are at minimum values (generally 95% or a pre-determined specific limit for a critical bus) or the area begins to violate zero net VAR interchange.  Note that both rules are respected in this stage.

1.	Bias the study area for low voltage conditions (This step should be skipped or scaled back for an area if it removes a disproportionate amount of generation in that area):

-	MW Importing Conditions

Reduce MVAR and MW supply by outaging the generator that has the most severe impact on voltage/reactive conditions or 10% of normally operating generation in the study area, whichever is greater (reducing MW supply decreases reactive support and increases MW imports and reactive losses).  Compensate for the generation outage by increasing generation outside of the study area but within NEPOOL.

-	MW Exporting Conditions

Increase reactive losses by heavily loading the transmission system.  For peak load levels dispatch up to 90% of the generation capacity inside of the study area.  For off-peak load levels commit additional generation above levels required by economic dispatch, up to area transmission limitations.

2.	Simulate the contingency (line or a generator) that causes the most severe low voltage/reactive conditions in the study area.  For MW exporting areas the most severe contingency is usually a line contingency.  For MW importing areas the most severe contingency is usually a generator contingency.  Compensate for a generator contingency by depleting the area's 10 minute reserve and starting up to two-thirds of the area's ICU's.  Pick-up the remainder outside of the study area but within NEPOOL (all pump storage and all ICU's in areas outside of the study area may be used).  Adjust generation to the extent possible to relieve transmission overloads.

3.	Reduce the study area's load power factor until essentially all available generator lagging reactive capability is depleted and the area begins to import reactive power (zero VAR interchange rule) or a significant number of transmission bus voltages drop below 95% (voltage rule).  Record the area MW and MVAR load as the PRELIMINARY STAGE I MINIMUM AREA LOAD.

V.	Low Voltage Bias - Stage II Test (allowing VAR interchange)

In Stage II testing all areas are set to their minimum load power factor as determined in Stage I.  Each study area (except the Northeast area) is then biased towards low voltage conditions, one at a time.  The worst contingency is then simulated allowing VAR interchange.  Compensation for a generator contingency is accomplished by inertial pick-up where essentially all replacement power flows across the New York to New England tie lines.  This stage of testing simulates conditions, as they would be 2-3 minutes after the contingency when automatic control actions have completed but before operator action or significant governor response.

If voltages in the study area are acceptable, then the PRELIMINARY STAGE I MINIMUM AREA LOAD POWER FACTOR becomes the FINAL STAGE II MINIMUM AREA LOAD POWER FACTOR.  If the study area has a significant number of buses with low voltage, then increase the study area's load power factor until transmission voltages generally rise above 95% (only the minimum voltage rule is observed - VAR interchange is allowed).  Record the area MW and MVAR load as the FINAL STAGE II MINIMUM AREA LOAD.

VI.	High Voltage Bias

1.	Bias the study area for high voltage conditions (This step should be skipped or scaled back for an area if it removes a disproportionate amount of generation in that area):

-	Biasing for high voltage conditions involves backing down MW transfers to low values and evaluating the effect of reactor banks and generators with large leading capabilities.  Reducing MW transfers and line loadings tends to decrease reactive losses and increase charging.  In cases where a unit contingency is being tested, MW interchange should be set-up so that it is relatively small after loss of the unit.

2.	Simulate the contingency (line or a generator) that causes the most severe high voltage conditions in the study area.  The consequences of losing a unit and its reactive support or a reactor bank may further promote high system voltages.  Compensate for a generator contingency by depleting the area's 10-minute reserve. Pick-up the remainder outside of the study area but within NEPOOL (all pump storage and all ICU's in areas outside of the study area may be used).

3.	Adjust the study area's load power factor until essentially all available generator leading reactive capability is depleted and the area begins to export reactive power (zero VAR interchange rule) or a significant number of transmission bus voltages rise above 105% (voltage rule).  Use the area MW and MVAR load at this point to calculate the area load power factor and record this value as the MAXIMUM AREA LOAD POWER FACTOR.

Diagram 1 - Is a geographic map of New England depicting the five areas described in this Operating Procedure.

Diagram 2 - Is an example of the Load Power Factor Curve for an area (New England Load vs. Power Factor).    

	TABLE 1
	ASSUMPTIONS FOR OP 17 LOADFLOW DEVELOPMENT

 1.	Generator Data and Dispatch

a)	Scheduled voltages are controlled within limits specified in NEPOOL Operating Procedure 12 - Voltage and Reactive Control, Appendix B (Voltage and Reactive Survey).
b)	Reactive capabilities for large generators are the VAR limits at Claimed Capability per NEPOOL Operating Procedure 14 - Technical Requirements for Generation and Load, Appendix B (Generator Reactive Data) as documented on the NX-12D forms.
c)	Station service loads are modeled for all large generators, removed with bias generators, and not tripped with the contingent generator.
d)	An economic dispatch is performed assuming all New England units are available and respecting reserve requirements.  Dispatch half the pump storage.

 2.	Bus Data

a)	Initialize MW and MVAR load at each bus in each area using Company projections for the appropriate load level.  Use the total area MW and MVAR load to determine area load power factor and apply this load power factor to each bus in the area (uniform load power factor).
b)	Loads are independent of voltage (constant P and Q).
c)	Shunt capacitors that are on the transmission system are modeled.

 3.	Transformers and Tie Lines

a)	Automatic load tap changing is allowed in all tests.
b)	Boston phase angle regulators allowed to regulate flow between +1 and -1 tap position.
c)	Plattsburg to Sandbar (PV-20 line) flow regulated at 150 MW into New England.
d)	New Brunswick to New England (396-line) flow set to 700 MW with three Orrington capacitors available.
e)	Power flows between New York and New England and on the Highgate HVDC tie tested up to the transfer limits.
f)	Phase I and II dispatch determined by the Voltage Task Force.
g)	VAR interchange between OP 17 areas metered at the electrical midpoint of each tie line except where contracts specify entitlement to line charging.

	APPENDIX II
	INSTRUCTIONS FOR THE NEPOOL POWER FACTOR SURVEY
	
The purpose of this survey is to gather information to determine the degree to which individual NEPOOL Participants have corrected load power factor.

For the purposes of this survey, New England has been divided into areas.  The areas were determined based on common reactive/voltage characteristics and established interfaces within NEPOOL.  Participants which cover a wide geographic area may be included in more than one OP 17 area.  For Participants in multiple areas, a separate survey form for each area is required.  Table 1 of Appendix 2 lists the area(s) for each Participant.

Figure 1 of Appendix 2 illustrates how load power factors are calculated using total real and reactive loads.  These loads do not necessarily need to be metered; they can be calculated from whatever metering is available as long as they reflect the burden that the load places on the bulk transmission system.

The following instructions explain each line of the NEPOOL Power Factor Survey - Appendix 2, Table 2:

Line 1			Column No. - No entries required.

Line 2			Date - To be entered by the ISO.

Line 3			Hour Ending - To be entered by the ISO.

Lines 4 & 5		Step-down Transformer Load at Subtransmission/ Distribution Level - Enter the aggregate of the real and reactive loads on the low voltage side of the transmission step-down transformers that feed load from the 115 KV system or higher, incurred on the date and hour shown.  Information is to be gathered from actual metered quantities.  If actual metered data is not available, please enter your best estimate and enter an "E" next to the number.

Lines 6 & 7		Step-down Transformer Losses - Enter the aggregate of the real and reactive losses incurred on the transmission step-down transformers.  These quantities may be calculated manually or obtained from loadflow simulations.

Lines 8 & 9		Generation on Subtransmission/Distribution Level -Enter the aggregate amount of real and reactive power actually supplied at the subtransmission/distribution level.  Gather information from actual metered quantities.  If actual metered data is not available, please enter your best estimate and enter "E" next to the number.

Line 10		Capacitors installed on the Transmission System to Serve Area Load - Enter reactive power actually provided from capacitors that were installed on transmission buses to serve load.  Do not include capacitors that were installed on the transmission system for purposes other than to serve load (See Table 3 of Appendix 2).

Lines 11 & 12		Total Load Served from Generation and Transmission System - On Line 11, enter the sum of Lines 4, 6, and 8.  On Line 12, enter the sum of Lines 5, 7, and 9 less Line 10.

Line 13		Enter the calculated power factor.  The power factor is to be calculated from the real load (entered on Line 11) and reactive load (entered on Line 12):

Power Factor =                 MW                 
 		(MW2  +  MVAR2)1/2

If any information on Lines 4 - 6 is estimated, please provide, on a separate sheet of paper, a brief explanation of the basis for each estimate.  Please enter the Line number followed by the explanation.

An alternate method may be used to derive the power factor as long as it results in the power factor of the load which is served from the 115 KV transmission bus as illustrated in the drawing and sample calculation shown in Appendix 2, Figure 1.  If an alternate method is used, please provide an explanation of the method.

APPENDIX II - Table 1

Company	Area
Ashburnham	Southwest
Bangor	Northern
BECO Central	Boston
     Southern	Southeast
Boylston	Southwest
Braintree	Southeast
CES  Cambridge	Boston
     Southern	Southeast
CMP	Northern
Chicopee	Southwest
CMEEC	Southwest
Danvers	Northeast Mass
EUA	Southeast
Fitchburg	Southwest
Georgetown	Northeast Mass
Groton (Mass)	Southwest
Hingham	Southeast
Holden	Southwest
Holyoke	Southwest
Hudson	Southwest
Hull	Southeast
Ipswich	Northeast Mass
Littleton	Northeast Mass
Mansfield	Southeast
Marblehead	Northeast Mass
Middleborough	Southeast
Middleton	Northeast Mass
North Attleborough	Southeast
Newport	Southeast
NEES NE Division	Northeast Mass
     Central Division	Southwest
     Southern Division	Southeast
NU	Southwest
Pascoag	Southeast
Paxton	Southwest
Peabody	Northeast Mass
Princeton	Southwest
PSNH	Northern
Reading	Boston
Shrewsbury	Southwest
South Hadley	Southwest
Sterling	Southwest
Taunton	Southeast
Templeton	Southwest
UI	Southwest
VELCO	Northern
Wakefield	Northeast Mass
W Boylston	Southwest
Westfield							Southwest

	APPENDIX II - Table 2
	NEPOOL POWER FACTOR SURVEY
	PARTICIPANT                                                                                        AREA                           
DATE                  CONTACT PERSON                                                                                              TEL. NO.                          
 Fall  	             Winter            	Spring 	            Summer            
 Light	 Light	 Peak	 Light	 Light	 Peak
 Load	 Load	 Load	 Load	 Load	 Load
 (1) Column No.	   1	   2	   3	   4	   5	   6   
 (2) Date	       	       	       	       	       	       
 (3) Hour Ending	       	       	       	       	       	       
Step-down Transformer Load at
Subtransmission/Distribution Level:
 (4) MW	       	       	       	       	       	       
 (5) MVAR	       	       	       	       	       	       
Stepdown Transformer Losses:
 (6) MW	       	       	       	       	       	       
 (7) MVAR	       	       	       	       	       	       
Generation on Subtransmission/
Distribution Level:
 (8) MW	       	       	       	       	       	       
 (9) MVAR	       	       	       	       	       	       
Capacitors installed on the Transmission
System to Serve Area Load:
(10) MVAR	       	       	       	       	       	       
Total Load Served From
Generation and Transmission System:
(11) MW   = (4)+(6)+(8)	       	       	       	       	       	       
(12) MVAR = (5)+(7)+(9)-(10)	       	       	       	       	       	       
(13) Power Factor				         		             	               		       		             	                    

	APPENDIX II - Table 3
	OP 17 Capacitor Summary

 					         NOMINAL
STATION		             MVAR 		 TYPE* 

SOUTHWEST

Millbury			  63.0			AREA
Pratts Jct.		  	  63.0			AREA
No. Bloomfield #1	  	  52.4			AREA
No. Bloomfield #2	  	  52.4			AREA
No. Bloomfield #3		  52.4			AREA
Manchester #1		  	  52.4			AREA
Manchester #2		  	  52.4			AREA
Manchester #3		  	  52.4			AREA
Manchester #4			  52.4			AREA
Manchester #5			  52.4			AREA
Manchester #6			  52.4			AREA
Berlin #1		  	  39.8			AREA
Berlin #2		  	  39.8			AREA
Berlin #3		  	  39.8			AREA
Frost Bridge #1	   	  52.4			AREA
Frost Bridge #2		  52.4			AREA
Frost Bridge #3		  52.4			AREA
Plumtree #1		  	  39.8			AREA
Plumtree #2		  	  39.8			AREA
East Shore #1		  	  42.0			AREA
East Shore #2		  	  42.0			AREA
North Haven	 	  	  42.0			AREA
Sacket			  	  42.0			AREA
Norwalk #1		  	  39.7			AREA
Norwalk #2		  	  39.7			AREA
Glenbrook #1		  	  37.8			AREA
Glenbrook #2		  	  37.8			AREA
Glenbrook #3		  	  37.8			AREA
Glenbrook #4		  	  37.8			AREA
Glenbrook #5			  39.6			AREA
Darien				  39.6			AREA
Waterside			  39.6			AREA
Agawam #1			  52.2			AREA
Agawam #2			  52.2			AREA
Montville #1			  52.4			AREA
Montville #2			  52.4			AREA
Southington #1		  52.4			AREA
Southington #2		  52.4			AREA
Southington #3		  52.4			AREA

TOTAL         	          1837.6

	APPENDIX II – Table 3 (continued)
	OP 17 Capacitor Summary

NOMINAL
STATION			MVAR 	 TYPE* 

NORTHEAST MASS.

Tewksbury #1		  	  63.0		AREA
Tewksbury #2		  	  63.0		AREA

TOTAL		126.0

SOUTHEAST

Kent County		  	  63.0		AREA
Manchester St			  63.0		AREA
Barnstable		  	  40.0		AREA

TOTAL           	166.0

BOSTON

K-Street-1		  	  53.6		AREA
K-Street-2		  	  53.6		AREA
Mystic			  	  53.6		AREA
Lexington		  	  53.6		AREA
Baker Street #1	  	  53.6		AREA
Baker Street #2	  	  53.6		AREA
Needham		  	  53.6		AREA
Framgham/Leland	  	  53.6		AREA

TOTAL                       428.8

APPENDIX II – Table 3 (continued)
OP 17 Capacitor Summary

NOMINAL
STATION			MVAR 	  TYPE* 

NORTH

Beebe			  	  20.0		OTHER
Merrimack #1		  	  37.5		OTHER
Merrimack #2		  	  37.5		OTHER
Orrington #1		  	  67.0		OTHER
Orrington #2		  	  67.0		OTHER
Orrington #3		  	  67.0		OTHER
Maine Yankee		  	  30.6		AREA
East Fairfax		  	  24.8		AREA
Sandbar		  	  24.8		AREA
Essex #1		  	  24.8		AREA
Essex #2			  24.8		AREA
Williston		  	  24.8		AREA
Middlebury		  	  22.9		AREA
North Rutland		  	  24.3		AREA
Berlin				  24.8		AREA

TOTAL                       522.6

   *	Type of capacitor - AREA capacitors are capacitors that were installed to serve area load.  These capacitors can be claimed on line #10 of the NEPOOL Power Factor Survey form.  OTHER capacitors are capacitors that were installed for purposes other than to serve load, such as power transfers.  These capacitors cannot be claimed on line #10 of the NEPOOL Power Factor Survey form.