Text

Response to Request for Additional Information Measurement Uncertainty Recapture Power Uprate
	ML090020382
Person / Time
Site:	Calvert Cliffs
Issue date:	12/29/2008
From:	Flaherty M; Calvert Cliffs, Constellation Energy Group
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	Download: ML090020382 (100)
	v • d • e

Calvert Cliffs Nuclear Power Plant 1650 Calvert Cliffs Parkway Lusby, Maryland 20657 Constellation Energya Nuclear Generation Group December 29, 2008 U. S. Nuclear Regulatory Commission Washington, DC 20555 ATTENTION:

Document Control Desk

SUBJECT:

Calvert Cliffs Nuclear Power Plant Unit Nos. I & 2; Docket Nos. 50-317 & 50-318 Response to Request for Additional Information -

Measurement Uncertainty Recapture Power Uprate Power Plant. Unit Nos. 1 and 2 License Amendment for

- Calvert Cliffs Nuclear

REFERENCES:

(a)

Letter from Mr. D. R. Bauder (CCNPP), to Document Control Desk (NRC) dated August 29, 2008, License Amendment Request: Appendix K Measurement Uncertainty Recapture - Power Uprate Request (b)

Letter from Mr. D. V. Pickett (NRC) to Mr. J. A. Spina (CCNPP), dated November 04, 2008, Request for Additional Information Re: License Amendment for Measurement Uncertainty Recapture Power Uprate-Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2 In Reference (a), Calvert Cliffs Nuclear Power Plant, Inc. submitted a license amendment request to the Nuclear Regulatory Commission (NRC) for a measurement uncertainty recapture power uprate for Calvert Cliffs Nuclear Power Plant, Units 1 and 2.

In Reference (b) the NRC requested additional information to be submitted to support their review of the submittal. Our response to this request is attached.

Aoo(

ý-ie~A

Document Control Desk December 29, 2008 Page 2 Should you have any questions regarding this matter, please contact Mr. Jay S. Gaines at (410) 495-5219.

Very truly yours, STATE OF MARYLAND COUNTY OF CALVERT

TO WIT:

I, Mark D. Flaherty, being duly sworn, state that I am Manager - Engineering Services, Calvert Cliffs Nuclear Power Plant, Inc. (CCNPP), and that I am duly authorized to execute and file this License Amendment Request on behalf of CCNPP. To the best of my knowledge and belief, the statements contained in this document are true and correct. To the extent that these statements are not based on my personal knowledge, they are based upon information provided by other CCNPP employees and/or consultants. Such information has been reviewed in accordance with company practice and I believe it to be reliable.

Subscribed and sworn before me, a Notary,lRublic in and for the State of Maryland

,this N day of.,

2008.

and County of WITNESS"r my Hand. and Notarial Seal:

My Commission Expires:

MDF/KLG/bjd 2~ >{364*

Notary Publi&2 mlve,'.

a/' /

/

Date

Attachment:

(1) Response to Request for Additional Information - Measurement Uncertainty Recapture Power Uprate cc:

D. V. Pickett, NRC S. J. Collins, NRC Resident Inspector, NRC S. Gray, DNR

ATTACHMENT (1)

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION -

MEASUREMENT UNCERTAINTY RECAPTURE POWER UPRATE Calvert Cliffs Nuclear Power Plant, Inc.

December 29, 2008

ATTACHMENT (1)

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION - MEASUREMENT UNCERTAINTY RECAPTURE POWER UPRATE

RAI 1

Provide the maximum value in megawatts electric (MWe) for the existing and uprated power level for Calvert Cliffs Units 1 and 2.

CCNPP Response:

Calvert Cliffs maximum expected Summer Gross MWe generation:

Existing Uprated Unit 1 896 908 Unit 2 885 897 These values are the maximum theoretical MWe increase expected due to the Measurement Uncertainty Recapture (MUR) uprate. Actual uprated values will be determined after a period of operation at the increased MUR power uprate value of 2737 MWT.

RAI 2

In Section V.4 of Attachment 2 of the license amendment request, the licensee states that the Pennsylvania, New Jersey, Maryland Interconnection has preliminarily reviewed the power uprate for impacts and grid stability and concludes that the proposed electrical output will not have any effect on grid stability or reliability. Provide details of the grid stability study and discuss in depth the assumptions, methodology, cases studied, and evidence to support the aforementioned conclusion.

CCNPP Response:

Since the Pennsylvania, New Jersey, Maryland Interconnection's (PJM) preliminary review, they have performed both an interim impact study (Enclosure 1) and a final impact study (Enclosure 2). These studies bound the expected increase in MWe due to the MUR uprate that is indicated in the response to RAI 1 above.

Also attached is a copy of the PJM Systems Dynamics Working Group procedure manual (Enclosure 3) and the PJM Manual 14B (Enclosure 4 contains only Section 2 of PJM Manual 14B as Section 2 is the applicable portion of the manual.

PJM Manual 14B can be viewed in its entirety at www.pjm.com/documents/manual.aspx).

These two manuals provide details of the inputs, assumptions, methodology, cases studied, and supporting evidence for the conclusions listed in the "Network Impacts" section of Enclosures 1 and 2.

RAI 3

For the power uprate of 1.38%, please identify the nature and quantity of megavolt ampere reactive (MVAR) support necessary to maintain post-trip loads and minimum voltage levels. Also address how the power uprate would affect MVAR support. Are there any compensatory measures the licensee would take to address the potential depletion of the nuclear unit's MWAR capability on a grid-wide basis as a result of the power uprate?

CCNPP Response:

The final impact study (Enclosure 2) contains the maximum MVAR capability used in the PJM model.

This capability is within the main generator's D-curve ratings.. Since no problems were identified in, no compensatory measures are necessary.

1

ATTACHMENT (1)

RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION - MEASUREMENT UNCERTAINTY RECAPTURE POWER UPRATE

RAI 4

Provide a detailed comparison of existing ratings with uprated ratings and the effect of the power uprate on the plant service transformers.

CCNPP Response:

For the Calvert Cliffs electrical auxiliary power system, the MUR uprate will only impact a small number of non-safety-related 4 kV motors by increasing the pump brake horsepower to support increased flow requiiements. The combined increased horsepower required results in a maximum anticipated 87 kVA and 77 kVA total load increase to the plant electrical system for Unit Nos. 1 and 2, respectively.

The Calvert Cliffs plant service transformers are rated 500/14 kV, 3 phase, 60 Hz, 100 MVA.

The transformers and associated 13 kV and 4 kV electrical systems are designed such that the entire service load from both Unit Nos. 1 and 2 can be aligned through one service transformer. In this case, maximum calculated load is expected to increase from its current value of 96.7 MVA, to a value of 96.87 MVA with the addition of the MUR related additional load. This is within the transformer 100 MVA rating.

ENCLOSURES

1. Generator Interconnection #K27/M04 Calvert Cliffs 55 MW Interim Impact Study, May 2004

2.

Generator Interconnection # M04 Calvert Cliffs 55 MW Impact Study, November 2005

3.

PJM System Dynamics Working Group Procedure Manual, February 2006

4.

PJM Manual 14B: PJM Region Transmission Planning Process, Section 2, Revision 12, Effective Date: 08/08/2008 2

ENCLOSURE (1)

Generator Interconnection #K27/M04 Calvert Cliffs 55 MW Interim Impact Study, May 2004 Calvert Cliffs Nuclear Power Plant, Inc.

December 29, 2008

Generator Interconnection

K2 7,M04 Calvert Cliffs 55 MW IneIm Impact Study May 200' Docs #26508

General Queues K27 (35 MW) and M04 (100 MW) are Constellation Power Source, Inc. requests for interconnection of an additional 135 MWs (summer capacity) at Calvert Cliffs associated with the following uprates:

Urate Unit 1 Unit 2 June 2004 June 2004 June 2004 December 2004 June 2005

1 Steam Gen Replacement

1 LP Turbine Replacement

2 Steam Generator Replacement

1 Appendix K

2 Appendix K 21 MW 62 MW 12 MW 95 MW 25 MW 12 MW 37 MW

'[his Interim Impact Study (May 2004 to June 1, 2005) addresses the requirements for Interim Capacity Interconnection Rights (CIRs) of 55 MW. which is scheduled to be in-service in 2004 prior to the completion of a final Impact Study for Queue positions K27 and M04.

Calvert Cliffs Nuclear Plant is located in Lusby, Calvert County, Maryland.

Direct Connection Requirements Queues K27/M04 uprates of existing Calvert Cliffs Units #1 and #2 does not require new or upgraded Direct Connection facilities. The existing Unit #1 and #2 connection is shown on the one line diagram below.

0© O4 I 2

Power Factor Requirements (at 55 MW Interim increase level)

PJM OATT Section 57.4.1 requires that "A Generation Interconnection Customer shall design its Customer Facility to maintain a composite power delivery at continuous rated power output at the generator's terminals at a power factor of at least 0.95 leading to 0.90 lagging".

Calvert Cliffs Unit 1 can receive a maximum interim increase of 35 MW CIR if the reactive capability in EDart is updated and maintained at a 367 MVAR value. Any additional capacity increase will require installation of reactive resources to maintain a 0.90 lagging power factor.

Calvert Cliffs Unit 2 can receive an increase of 20 MW based on the grandfathered reactive capability design in accordance with PJM's Business Rule which waives PJM OATT Section 57.4.1 requirements for MW increases of 20 MW or less to existing (grandfathered) generation facilities. Any additional capacity increase will require installation of reactive resources to maintain a 0.90 lagging power factor.

Network Impacts The Calvert Cliffs Queue K27/M04 Interim Interconnection was studied as 55 MW capacity increase to Calvert Cliffs Units #1 (20MW) and #2 (35MW). Queues K27/M04 were evaluated for compliance with reliability criteria for summer peak conditions in 2004. Potential network impacts were as follows:

Generator Deliverability No problems identified.

Multiple Facility Contingency - Tower Line Outages (MAAC Criteria IIC)

No problems identified.

Short Circuit No problems identified.

The planned Unit 2 uprates do not change the generator impedance; however, there was a change of impedance for the Unit #1 generator, and Units #1 and #2 generator step-up transformers were replaced with GSUs having a differant impedance.

Stability Analysis (MAAC Criteria IV)

No problems identified.

Stability analysis was performed at light load conditions and for maximum summer generator output with the proposed plant uprates of 55 MW associated with K27 and M04 queue projects.

See Attachment #1 for the fault cases evaluated. The range of contingencies evaluated was limited to that necessary to demonstrate compliance with MAAC reliability criteria.

3

Note: While the stability analysis has been performed at expected extreme system conditions, there is a potential that evaluation at different level of generator MW and/or MVAR output at different load levels and operating conditions would disclose unforeseen stability problems. The regional reliability analysis routinely performed to test all system changes will include one such evaluation. Any problems uncovered in this or other operating or planning studies will need to be resolved.

Stability analysis was performed at light load conditions and for maximum summer generator output with the proposed plant uprates associated with the K27 and M04 queue projects. See Attachment #1 for the fault cases evaluated. The range of contingencies evaluated was limited to that necessary to demonstrate compliance with MAAC reliability criteria New System Reinforcements None required.

Contribution to Previously Identified System Reinforcements None.

4

ATTACHMENT #1 Stability Analysis Results CALVERT CLIFFS K27 and M04 (55MW Interim Impact Study)

Breaker Clearing Times (cycles)

Station Primary (3ph/slg)

Stuck Breaker timer (total)

All BGE 500 kV 4.5 13 All PEPCO 500 kV 4.2 12.1 Criteria Test Faults (All stable)

K27-1a 3ph @ Calvert Cliffs 500 KV on Calvert Cliffs-Chalk Point 500 KV K27-lb slg @ Calvert Cliffs 500 KV on Calvert Cliffs-Chalk Point 500 KV, stuck @ Calvert Cliffs K27-2a 3ph @ Calvert Cliffs 500 KV on Calvert Cliffs-Waugh Chapel 500 KV cktl K27-2b slg @ Calvert Cliffs 500 KV on Calvert Cliffs-Waugh Chapel 500 KV cktl, stuck @

Calvert Cliffs K27-3a 3ph @ Calvert Cliffs 500 KV on Calvert Cliffs-Waugh Chapel 500 KV ckt2 K27-3b slg @ Calvert Cliffs 500 KV on Calvert Cliffs-Waugh Chapel 500 KV ckt2, stuck @

Calvert Cliffs K27-4a 3ph @ Chalk Point 500 KV on Chalk Point-Possum Point 500 KV K27-4b slg @ Chalk Point 500 KV on Chalk Point-Possum Point 500 KV, stuck @ Chalk Point K27-5a 3ph @ Chalk Point 500 KV on Chalk Point 500/230 KV TX1 K27-5b slg @ Chalk Point 500 KV on Chalk Point 500/230 KV TX1, stuck @ Chalk Point K27-6a 3ph @ Possum Point 500 KV on Possum Point-Ladysmith 500 KV K27-6b slg @ Possum Point 500 KV on Possum Point-Ladysmith 500 KV, stuck @ Possum Point K27-7a 3ph @ Possum Point 500 KV on Possum Point-OX 500 KV K27-7b slg @ Possum Point 500 KV on Possum Point-OX 500 KV, stuck @ Possum Point K27-8a 3ph @ Waugh Chapel 500KV on Waugh Chapel-Brighton 500 KV K27-8b slg @ Waugh Chapel 500KV on Waugh Chapel-Brighton 500 KV, stuck @ Waugh Chapel 5

Additional Test Faults (All Stable)

K27p-2a same as K27-2a with Chalk Point-Calvert Cliffs 500 KV O/S on maintenance K27p-2b same as K27-2b with Chalk Point-Calvert Cliffs 500 KV O/S on maintenance K27p-3a same as K27-3a with Chalk Point-Calvert Cliffs 500 KV O/S on maintenance K27p-3b same as K27-3b with Chalk Point-Calvert Cliffs 500 KV O/S on maintenance K27q-la same as K27-1a with Calvert Cliffs-Waugh Chapel 500 KV cktl O/S on maintenance K27q-lb same as K27-1b with Calvert Cliffs-Waugh Chapel 500 KV cktl O/S on maintenance K27q-3a same as K27-3a with Calvert Cliffs-Waugh Chapel 500 KV cktl O/S on maintenance K27q-3b same as K27-3b with Calvert Cliffs-Waugh Chapel 500 KV cktl O/S on maintenance K27r-la same as K27-la with Chalk Point-Possum Point 500 KV O/S on maintenance K27r-lb same as K27-1b with Chalk Point-Possum Point 500 KV O/S on maintenance K27r-2a same as K27-2a with Chalk Point-Possum Point 500 KV O/S on maintenance K27r-2b same as K27-2b with Chalk Point-Possum Point 500 KV O/S on maintenance K27r-3a same as K27-3a with Chalk Point-Possum Point 500 KV O/S on maintenance K27r-3b same as K27-3b with Chalk Point-Possum Point 500 KV O/S on maintenance K27s-la same as K27-1a with K27s-lb same as K27-lb with K27s-2a same as K27-2a with K27s-2b same as K27-2b with K27s-3a same as K27-3a with K27s-3b same as K27-3b with Chalk Point 500/230 KV TXI 0/S on maintenance Chalk Point 500/230 KV TXI 0/S on maintenance Chalk Point 500/230 KV TX 10/S on maintenance Chalk Point 500/230 KV TXI 0/S on maintenance Chalk Point 500/230 KV TXI O/S on maintenance Chalk Point 500/230 KV TX1 0/S on maintenance 6

ATTACHMENT #2 (Generator and GSU Data)

Unit Capability Data Gross MW Output GSU MW Losses \\AA/

Unit Auxiliary Load MW I

Station Service Load MW Net MW Capacity Net MW Capacity = (Gross MW Output - GSU MW Losses* - Unit Auxiliary Load MW - Station Service Load MW)

Queue Letter/Position/Unit ID:

K27 and M04 (Calvert Cliff unitl)

Primary Fuel Type:

Nuclear Maximum Summer (920 F ambient air temp.) Net MW Output**.

873 Maximum Summer (920 F ambient air temp.) Gross MW Output:

908 Minimum Summer (920 F ambient air temp.) Gross MW Output:

Maximum Winter (300 F ambient air temp.) Gross MW Output:

Minimum Winter (300 F ambient air temp.) Gross MW Output:

Gross Reactive Power Capability at Maximum Gross MW Output - Please include Reactive Capability Curve (Leading and Lagging): 367 MVAR lagging, -50 MVAR leading Individual Unit Auxiliary Load at Maximum Summer MW Output (MW/MVAR):

Individual Unit Auxiliary Load at Minimum Summer MW Output (MW/MVAR):

Individual Unit Auxiliary Load at Maximum Winter MW Output (MW/MVAR):

Individual Unit Auxiliary Load at Minimum Winter MW Output (MW/MVAR):

Station Service Load (MW/MVAR):

70 MW spread evenly over the 2 units

GSU losses are expected to be minimal.

- Your project's declared MW, as first submitted in Attachment N, and later confirmed or modified by the Impact Study Agreement, should be based on either the 920 F Ambient Air Temperature rating of the unit(s) or, if less, the declared Capacity rating of your project.

7

Unit Generator Dynamics Data Queue Letter/Position/Unit ID:

K27 and M04 (Calvert Cliffs unitl)

MVA Base (upon which all reactances, resistance and inertia are calculated):

1020 Nominal Power Factor:

0.9 Terminal Voltage (kV):

25 Unsaturated Reactances (on MVA Base)

Direct Axis Synchronous Reactance, Xd(1):

1.61 Direct Axis Transient Reactance, X'd(i):

0.355 Direct Axis Sub-transient Reactance, X"d(i):

0.280 Quadrature Axis Synchronous Reactance, Xq(i):

1.51 Quadrature Axis Transient Reactance, X'q(i):

0.557 Quadrature Axis Sub-transient Reactance, X"q(i):

0.280 Stator Leakage Reactance, XI:

0.21 Negative Sequence Reactance, X2(i):

0.235 Zero Sequence Reactance, XO:

0.190 Saturated Sub-transient Reactance, X"d(v) (on MVA Base):

0.235 Armature Resistance, Ra (on MVA Base):

Time Constants (seconds)

Direct Axis Transient Open Circuit, T'do:

6.771 Direct Axis Sub-transient Open Circuit, T"do:_

0.031 Quadrature Axis Transient Open Circuit, T'qo:_

0.385 Quadrature Axis Sub-transient Open Circuit, T"qo:

0.053 Inertia, H (kW-sec/kVA, on KVA Base):

4.395 Speed Damping, D:

0 Saturation Values at Per-Unit Voltage [S(1.0), S(1.2)]:

0.1, 0.44 Units utilize a GENROU Generator model 8

Unit GSU Data Queue Letter/Position/Unit ID:

K27 and M04 (Calvert Cliffs unitl)

Generator Step-up Transformer MVA Base:

Two 810 MVA TX connected in parallel Generator Step-up Transformer Impedance (%, on transformer MVA Base):

20.55% (both)

Generator Step-up Transformer Rating (MVA):

810.0 Generator Step-up Transformer Low-side Voltage (kV):

25.0 Generator Step-up Transformer High-side Voltage (kV):

500.0 Generator Step-up Transformer Off-nominal Turns Ratio:

1.05 Generator Step-up Transformer Number of Taps and Step Size: __ 3 taps of 2.5 % above And 1 tap of 2.5% below 9

Unit Capability Data Gross MW Output GSU MW Losses *Unit Auxiliary Load MW Station Service Load MW Net MW Capacity Net MW Capacity = (Gross MW Output - GSU MW Losses* - Unit Auxiliary Load MW - Station Service Load MW)

Queue Letter/Position/Unit ID:

K27 and M04 (Calvert Cliff unit2)

Primary Fuel Type:

Nuclear Maximum Summer (920 F ambient air temp.) Net MW Output**:

867 Maximum Summer (920 F ambient air temp.) Gross MW Output:

902 Minimum Summer (920 F ambient air temp.) Gross MW Output:

Maximum Winter (300 F ambient air temp.) Gross MW Output:

Minimum Winter (300 F ambient air temp.) Gross MW Output:

Gross Reactive Power Capability at Maximum Gross MW Output - Please include Reactive Capability Curve (Leading and Lagging):350 MVAR lagging, -50 MVAR leading Individual Unit Auxiliary Load at Maximum Summer MW Output (MW/MVAR):

Individual Unit Auxiliary Load at Minimum Summer MW Output (MW/MVAR): __

Individual Unit Auxiliary Load at Maximum Winter MW Output (MW/MVAR):

Individual Unit Auxiliary Load at Minimum Winter MW Output (MW/MVAR):

Station Service Load (MW/MVAR):

70 MW spread evenly over the 2 units

GSU losses are expected to be minimal.

- Your project's declared MW, as first submitted in Attachment N, and later confirmed or modified by the Impact Study Agreement, should be based on either the 920 F Ambient Air Temperature rating of the unit(s) or, if less, the declared Capacity rating of your project.

10

Unit Generator Dynamics Data Queue Letter/Position/Unit ID:

K27 and M04 (Calvert Cliff unit2)

MVA Base (upon which all reactances, resistance and inertia are calculated):

1003 Nominal Power Factor:

Terminal Voltage (kV):

22.0 Unsaturated Reactances (on MVA Base)

Direct Axis Synchronous Reactance, Xd(i):

1.599 Direct Axis Transient Reactance, X'd(i):

0.442 Direct Axis Sub-transient Reactance, X"d(i):

0.301 Quadrature Axis Synchronous Reactance, Xq(i):

1.561 Quadrature Axis Transient Reactance, X'q(i):

0.682 Quadrature Axis Sub-transient Reactance, X"q(i):

0.301 Stator Leakage Reactance, Xl:

0.2250 Negative Sequence Reactance, X2(i):

Zero Sequence Reactance, XO:

Saturated Sub-transient Reactance, X"d(v) (on MVA Base):

Armature Resistance, Ra (on MVA Base):

Time Constants (seconds)

Direct Axis Transient Open Circuit, T'do:

5.95 Direct Axis Sub-transient Open Circuit, T'r&:_

0.035 Quadrature Axis Transient Open Circuit, T'qo:_

1.5 Quadrature Axis Sub-transient Open Circuit, T"qo:

0.07 Inertia, H (kW-sec/kVA, on KVA Base):

3.346 Speed Damping, D:

0 Saturation Values at Per-Unit Voltage [S(1.0), S(1.2)]:

0.096, 0.3133 Units utilize a Genrou Generator model 11

Unit GSU Data Queue Letter/Position/Unit ID:

K27 and M04 (Calvert Cliff unit2)

Generator Step-up Transformer MVA Base:

Two 810 MVA TX connected in parallel Generator Step-up Transformer Impedance (%, on transformer MVA Base):20.94% and 20.88%

Generator Step-up Transformer Rating (MVA):

810.0 Generator Step-up Transformer Low-side Voltage (kV):

22.0 Generator Step-up Transformer High-side Voltage (kV):

500.0 Generator Step-up Transformer Off-nominal Turns Ratio:

1.05 Generator Step-up Transformer Number of Taps and Step Size: __ 3 taps of 2.5 % above And 1 tap of 2.5% below 12

ATTACHMENT #3 Units #1 and #2 Capability Curves Unit # 1

1.

WHE the Voltage Regulator is fn MANUAL, ILEN the ste$dy-ste Reactive Load shali MO excee4 220 WAR (LP t502193 AI'4 PcLE.jXW~oWPV LrRPS42.MO VOLTS OW PF,

.,,J

-:,/

).c:"

-'"° 4,

.6

/ag P<

/~<

/

"H"

-,too, hi C

1 V0;-'-

k.'.-

O-L O.-OP*

~

c

~

i~OaP 1F Ranttv rL pXB C.IJVtA8E uwMr~yAflJI4HEkTM-1h' Unit #2 13

IL low SON alu lwe

SON, 14

ENCLOSURE (2)

Generator Interconnection # M04 Calvert Cliffs 55 MW Impact Study, November 2005 Calvert Cliffs Nuclear Power Plant, Inc.

December 29, 2008

Generator Interconnection

M04 Calvert Cliffs 55 MW Impact Study November 2005 Docs #319683

General Queue M04 is a Constellation Power Source, Inc. request for interconnection of an additional 55 MWs Capacity at Calvert Cliffs 500 kV station. The scheduled increase to Calvert Cliffs units 1 and 2 are expected to be complete in 2005.

Uprate Unit 1 Unit 2 2002-03 2004 2004 2004 2005

1 Steam Gen Replacement

1 LP Turbine Replacement

2 Steam Generator Replacement

1 Appendix K

2 Appendix K xx x

X X

Direct Connection Requirements Queue M04 uprates of existing Calvert Cliffs Units #1 and #2 does not require new or upgraded Direct Connection facilities. The existing Unit #1 and #2 connection is shown on the one line diagram below.

Waugh Chapel M04 Calvei Cliffs M04 rt I V k eQ..k fi 1'V 15072 Calvert Cliffs Chalk Point

2

Power Factor Requirements PJM OATT Section 57.4.1 requires that "A Generation Interconnection Customer shall design its Customer Facility to maintain a composite power delivery at continuous rated power output at the generator's terminals at a power factor of at least 0.95 leading to 0.90 lagging".

Calvert Cliffs Unit 1 can receive a maximum increase of 35 MW CIR if the reactive capability in EDart is updated and maintained at a 367 MVAR value. Any additional capacity increase will require installation of reactive resources to maintain a 0.90 lagging power factor.

Calvert Cliffs Unit 2 can receive an increase of 20 MW based on the grandfathered reactive capability design in accordance with PJM's Business Rule which waives PJM OATT Section 57.4.1 requirements for MW increases of 20 MW or less to existing (grandfathered) generation facilities. Any additional capacity increase will require installation of reactive resources to maintain a 0.90 lagging power factor.

Network Impacts Calvert Cliffs Queue M04 was studied as a 55 MW capacity increase to Calvert Cliffs Units #1 and #2 and evaluated for compliance with reliability criteria for summer peak conditions in 2009.

Potential network impacts were as follows:

Generator Deliverability No problems identified.

Multiple Facility Contingency - Tower Line Outa2es (MAAC Criteria IIC)

No problems identified.

Local System Impacts No problems identified.

Short Circuit No problems identified for this Queue position.

Stability Analysis No problems identified New System Reinforcements None.

Contribution to Previously Identified System Reinforcements None.

3

ATTACHMENT #1 (Generator and GSU Data)

Unit Capability Data Gross MW Output GSU MW L osses *Unit Auxiliary Load MW Station Service Load MW Net MW Capacity Net MW Capacity = (Gross MW Output - GSU MW Losses* - Unit Auxiliary Load MW - Station Service Load MW)

Queue Letter/Position/Unit ID:

M04 (Calvert Cliff unit1)

Primary Fuel Type:

Nuclear Maximum Summer (920 F ambient air temp.) Net MW Output**:

873 Maximum Summer (920 F ambient air temp.) Gross MW Output:

908 Minimum Summer (920 F ambient air temp.) Gross MW Output:

Maximum Winter (300 F ambient air temp.) Gross MW Output:

Minimum Winter (300 F ambient air temp.) Gross MW Output:

Gross Reactive Power Capability at Maximum Gross MW Output - Please include Reactive Capability Curve (Leading and Lagging): 367 MVAR lagging, -50 MVAR leading Individual Unit Auxiliary Load at Maximum Summer MW Output (MW/MVAR):

Individual Unit Auxiliary Load at Minimum Summer MW Output (MW/MVAR): __

Individual Unit Auxiliary Load at Maximum Winter MW Output (MW/MVAR):

Individual Unit Auxiliary Load at Minimum Winter MW Output (MW/MVAR):

Station Service Load (MW/MVAR):

70 MW spread evenly over the 2 units

GSU losses are expected to be minimal.

- Your project's declared MW, as first submitted in Attachment N, and later confirmed or modified by the Impact Study Agreement, should be based on either the 920 F Ambient Air Temperature rating of the unit(s) or, if less, the declared Capacity rating of your project.

4

Unit Generator Dynamics Data Queue Letter/Position/Unit ID:

M04 (Calvert Cliffs unit1)

MVA Base (upon which all reactances, resistance and inertia are calculated):

1020 Nominal Power Factor:

0.9 Terminal Voltage (kV):

25 Unsaturated Reactances (on MVA Base)

Direct Axis Synchronous Reactance, Xd(,):

1.61 Direct Axis Transient Reactance, X'd(i):

0.355 Direct Axis Sub-transient Reactance, X"d(i):

0.280 Quadrature Axis Synchronous Reactance, Xq(i):

1.51 Quadrature Axis Transient Reactance, X'q(i):

0.557 Quadrature Axis Sub-transient Reactance, X"q(i):

0.280 Stator Leakage Reactance, XI:

0.21 Negative Sequence Reactance, X2(i):

0.235 Zero Sequence Reactance, XO:

0.190 Saturated Sub-transient Reactance, X"d(v) (on MVA Base):

0.235 Armature Resistance, Ra (on MVA Base):

Time Constants (seconds)

Direct Axis Transient Open Circuit, T'do:

6.771 Direct Axis Sub-transient Open Circuit, T"do:

0.031 Quadrature Axis Transient Open Circuit, T'qo:_

0.385 Quadrature Axis Sub-transient Open Circuit, T"qo:

0.053 Inertia, H (kW-sec/kVA, on KVA Base):

4.395 Speed Damping, D:

0 Saturation Values at Per-Unit Voltage [S(1.0), S(1.2)]:

5

Unit GSU Data Queue Letter/Position/Unit ID:

M04 (Calvert Cliffs unitl)

Generator Step-up Transformer MVA Base:

Two 810 MVA TX connected in parallel Generator Step-up Transformer Impedance (%, on transformer MVA Base):

20.55% (both)

Generator Step-up Transformer Rating (MVA):

810.0 Generator Step-up Transformer Low-side Voltage (kV):

25.0 Generator Step-up Transformer High-side Voltage (kV):

500.0 Generator Step-up Transformer Off-nominal Turns Ratio:

1.05 Generator Step-up Transformer Number of Taps and Step Size: __ 3 taps of 2.5 % above And 1 tap of 2.5% below

6

Unit Capability Data GSU MW Losses *Unit Auxiliary Load MW

/ Station Service Load MW Net MW Capacity Net MW Capacity = (Gross MW Output - GSU MW Losses* - Unit Auxiliary Load MW - Station Service Load MW)

Queue Letter/Position/Unit ID:

M04 (Calvert Cliff unit2)

Primary Fuel Type:

Nuclear Maximum Summer (92' F ambient air temp.) Net MW Output**:

867 Maximum Summer (92' F ambient air temp.) Gross MW Output:

902 Minimum Summer (920 F ambient air temp.) Gross MW Output:

Maximum Winter (30' F ambient air temp.) Gross MW Output:

Minimum Winter (30 F ambient air temp.) Gross MW Output:

Gross Reactive Power Capability at Maximum Gross MW Output - Please include Reactive Capability Curve (Leading and Lagging):350 MVAR lagging, -50 MVAR leading Individual Unit Auxiliary Load at Maximum Summer MW Output (MW/MVAR):

Individual Unit Auxiliary Load at Minimum Summer MW Output (MW/MVAR): __

Individual Unit Auxiliary Load at Maximum Winter MW Output (MW/MVAR):

Individual Unit Auxiliary Load at Minimum Winter MW Output (MW/MVAR):

Station Service Load (MW/MVAR):

70 MW spread evenly over the 2 units

GSU losses are expected to be minimal.

- Your project's declared MW, as first submitted in Attachment N, and later confirmed or modified by the Impact Study Agreement, should be based on either the 920 F Ambient Air Temperature rating of the unit(s) or, if less, the declared Capacity rating of your project.

7

Unit Generator Dynamics Data Queue Letter/Position/Unit ID:

M04 (Calvert Cliff unit2)

MVA Base (upon which all reactances, resistance and inertia are calculated):

1003 Nominal Power Factor:

Terminal Voltage (kV):

22.0 Unsaturated Reactances (on MVA Base)

Direct Axis Synchronous Reactance, Xd(i):

1.599 Direct Axis Transient Reactance, X'd(i):

0.442 Direct Axis Sub-transient Reactance, X"d(i):

0.301 Quadrature Axis Synchronous Reactance, Xq(i):

1.561 Quadrature Axis Transient Reactance, X'q(i):

0.682 Quadrature Axis Sub-transient Reactance, X"q(i):

0.301 Stator Leakage Reactance, Xl:

0.2250 Negative Sequence Reactance, X2(i):

Zero Sequence Reactance, XO:

Saturated Sub-transient Reactance, X"d(v) (on MVA Base):

Armature Resistance, Ra (on MVA Base):

Time Constants (seconds)

Direct Axis Transient Open Circuit, T'do:

5.95 Direct Axis Sub-transient Open Circuit, T"do:_

0.035 Quadrature Axis Transient Open Circuit, T'qo:_

1.5 Quadrature Axis Sub-transient Open Circuit, T"qo:

0.07 Inertia, H (kW-sec/kVA, on KVA Base):

3.346 Speed Damping, D:

0 Saturation Values at Per-Unit Voltage [S(1.0), S(1.2)]:

0.096, 0.3133 Units utilize a Genrou Generator model

8

Unit GSU Data Queue Letter/Position/Unit ID:

M04 (Calvert Cliff unit2)

Generator Step-up Transformer MVA Base:

Two 810 MVA TX connected in parallel Generator Step-up Transformer Impedance ( %, on transformer MVA Base):20.94% and 20.88%

Generator Step-up Transformer Rating (MVA):

810.0 Generator Step-up Transformer Low-side Voltage (kV):

22.0 Generator Step-up Transformer High-side Voltage (kV):

500.0 Generator Step-up Transformer Off-nominal Turns Ratio:

1.05 Generator Step-up Transformer Number of Taps and Step Size: __ 3 taps of 2.5 % above And 1 tap of 2.5% below

9

ATTACHMENT #2 (Unit #1 and #2 Capability Curves)

10

Unit #1I I.

WHI~ the Voltage Ragulaor Is In, MANUAL.

wi the 9teed-stote Reacgve Load shall NMI exceedi 220 MVAR (ILI, 1BO2191 AM 4Po i XWOw WVA, =0 RPY 2&00 VOLTS LA GO:2oG I:

> I avow r-MNUJALL 1

20WA (e

CLI1 ~

kc"A UMT~Y~1~3J J+

r~,Jw~D~L~C&~A~H3>T

-33~ni

2 r 7

I I

eO- "

nd_

PUP 6m ffi 4e too

01r e

12

ENCLOSURE (3)

PJM System Dynamics Working Group Procedure Manual, February 2006 Calvert Cliffs Nuclear Power Plant, Inc.

December 29, 2008

PJM SYSTEM DYNAMICS WORKING GROUP PROCEDURE MANUAL February 2006

FOREWORD This manual is a product of the PJM System Dynamics Working Group (SDWG). PJM footprint encompasses several NERC reliability regions consisting of many transmission owners. The manual contains the scope, study guidelines and procedures which define and support the activities of the SDWG.

The procedural manual is intended for use by PJM and members of PJM for the purpose of creating and maintaining dynamics base cases and dynamics simulation details that are to be used to evaluate the dynamic performance of the systems in the PJM footprint.

PJM and most of the Regional member utilities use Power Technologies Inc. (PTI) Power System Simulator (PSS/E) software. Therefore, the various activities in the procedure manual incorporate PTI's procedures and nomenclature in describing these activities.

2 SDWG Procedure Manual February 2006

TABLE OF CONTENTS I

INTRODUCTION..................................................................................................

4 II PURPOSE OF THE SDWG....................................................................................

5 III PR O C E D U RE S.................................................................................. 6 IV APPENDIX 1-REGION CRITERIA N E R C C R IT ER IA............................................................................... 9 M A A C C R IT E R IA....................................................................................................

11 E C A R C R IT E R IA.....................................................................................................

13 SERC CRITERIA................................................

14 MAIN CRITERIA............................................................................ 15 V

APPENDIX 2 - TRANSMISSION OWNER CRITERIA BGE CRITERIA.............................................................................. 16 DVP CRITERIA....................................................

................ 20 AEP CRITERIA..........................................................-

23 PPL C R IT E R IA................................................................................. 24 CornEd CRITERIA......................................................

............... 25 P H I C riteria................................................................................

.26 VI APPENDIX 3 - GENERATOR DATA REQUEST FORM.................... 27 VII APPENDIX 4 - CLEARING TIMES BY TO................

.................... 30 VIII APPENDIX 5 - NUCLEAR UNITS REQUIREMENTS................................. 31 SDWG Procedure Manual February 2006

1. INTRODUCTION Dynamic Stability Analysis is performed by PJM as a part of the system impact study for proposed generation interconnection to the PJM system. PJM also conducts periodic appraisals of PJM system performance and dynamic assess ment of the effects of system condition changes which are deemed to have a reasonable possibility of occurring during PJM system operation. PJM staff performs the bulk of the analysis by applying the criteria set by NERC, NERC reliability regions and also applicable transmission owners' criteria where the new projects are interconnected.

4 SDWG Procedure Manual February 2006

II. PURPOSE OF THE SDWG PJM System Dynamics Working Group (SDWG) was created by PJM Planning Committee (PC) in January 2005 in order to develop and maintain an integrated system dynamics analysis procedure manual for PJM system. The manual is developed for the use of PJM and its members in planning and to evaluate operating conditions of the PJM bulk electric power systems.

5 SDWG Procedure Manual February 2006

Il.

PROCEDURES Dynamics base cases Base cases for stability analysis are created in a similar manner to that of the load flow base cases.

However, additional information is necessary in order to simulate the combined dynamic responses of various system components across the transmission system. Included in this additional information are models for generators, excitation systems, power system stabilizers, governors, load models and various other equipment.

A dynamic simulation links the system model or load flow information with the dynamic data or models to determine if the system and generators will remain stable for a steady-state and various disturbances.

The current RTEP summer peak case is used as a starting point to create new dynamics cases (light load and peak load) in the following year.

The following steps are observed in creating and updating the two dynamics cases.

1) Obtain and Review the Designated RTEP Power Flow Case The power flow case is reviewed with regards to its linkage to the dynamics database.

2) Correlate the Power Flow Data with the Dynamics Data Correlate the RTEP power flow data with the dynamic data to determine any missing dynamics data. Also determine if there is any data in the database for which there is no corresponding power flow data.

3) Review the Power Flow and the Dynamics Database for Questionable Data Review the RTEP power flow data and its dynamics data files such as DYRE, CONEC and CONET to identify questionable and bad data.

Testing and Initializing Dynamics Cases The following steps are observed in creating dynamics simulation cases.

Perform Initialization Based on DYRE, CONEC, CONET and RAWD Files Read the updated power flow data (RAWD or saved case) into the PSS/E power flow program. Solve the AC power flow case. After the AC solution, convert the generators and load using the CONG and CONL activities. Using activities FACT and TYSL, solve the converted power flow case. Save the converted case.

Using the PTI PSS/E dynamics simulation skeleton program, read in the solved converted power flow case. Perform activities FACT and TYSL.

Perform activity DYRE and read in the DYRE dynamics data file. Note and document any warning and error messages that are displayed. Create the CONEC and CONET files and compile command procedure before exiting the PSS/E dynamics simulation program.

Resolve any problems identified by the activity DYRE Add the user-written source codes to the respective CONEC and CONET files and execute the compile command procedure previously created. Create a snapshot to be used with the PSSDS executable. Execute CLOAD4 to link the files, thereby creating a PSSDS executable.

Using the user PSSDS executable created, read in the solved converted power flow case.

Perform activities FACT and TYSL. Perform activity STRT. Note any states that are not initializing properly, i.e., any dynamic states whose derivatives are not zero, within the 6

SDWG Procedure Manual February 2006

standard tolerance. Document and correct as needed these noninitializations of states.

Repeat this procedure until all initialization problems have been corrected.

Once all the dynamic state initialization problems have been corrected, create a new snapshot, and using activity RUN execute the dynamic simulation for 20 seconds, unperturbed. Use PTI's PSAS to establish output channels for these simulations.

Adjust the integration time step and/or correct data until the dynamic simulation (unperturbed) is judged to be steady-state stable.

The final, initialized set of power flows and the associated snap-shots, along with the compile file (DSUSR.dll file for the PC platform) and the GNET/CONL files are provided to the PJM members for their use.

Load Level Each RTEP dynamic case is one of the following model types:

Summer Peak Load: the summer peak demand expected to be served Light Load: 50% of the summer peak load. Pumped storage hydro units are modeled in the pumping mode.

Outside Equivalents The regions adjacent to PJM are modeled in sufficient details using their models from the NERC power system dynamics database (SDDWG)

Dispatch The assumptions used for generation dispatch can be critical to the results. It is generally accepted that units operating at their highest possible power output and generating as little reactive power as necessary to maintain voltages are likely to be less stable. Normally, the units in the vicinity of the project under study will be turned on to their maximum real power output with unity power factor at the high side of the GSU's. However, some Transmission Owners do not set the high side of GSU to unity power factor, instead adjust units VAR output to hold scheduled voltages.

Modeling Details Where the GSU of a synchronous or induction generator or synchronous condenser is not modeled in the RTEP power flow case, the GSU shall be represented in the dynamic case. Station light and power Load is also required to be modeled explicitly. Currently a few units have their station light and power loads modeled in the RTEP cases.

Simulation Details The Criteria for performing studies in the PJM system shall meet the requirements of the NERC Reliability Standards, NERC reliability region criteria, applicable transmission owner criteria and applicable specific generating plant criteria. The following factors need to be addressed in simulations; a) Criteria Based Case lists:

1) Faults Types: Close-in three phase faults, close-in single line to ground faults with stuck breaker and close-in single line to ground faults with the communications failure cleared with zone2 time.

7 SDWG Procedure Manual February 2006

2)

Clearing Times: All clearing times used are representative "worst case scenarios" for use as a screening tool for dynamic studies. Clearing times are provided by the Transmission owners to the PJM Relay Subcommittee (Appendix 4). Actual clearing times are used when stability problems are identified.

3) Reclosing: Only high speed reclosing is modeled if present.

b) Maintenance outages: All EHV line maintenance outages near a generating plant are evaluated for three-phase, normally cleared faults only. No breaker failure or 2 d zone test is applied.

c) Margins: With the machine modeled at net unity power factor at the high-side of the GSU, transient stability must be maintained when the following tests are applied:

Add 0.25 cycles to the nominal primary clearing time for 3 phase, normally cleared faults.

Add 0.25 cycles to the nominal primary clearing time for single-line-to-ground faults, plus an additional 0.5 cycles added to the nominal backup clearing time for stuck breaker.

Add 0.25 cycles to the nominal primary clearing time for single-line-to-ground faults, plus an additional 1.25 cycles to the nominal Zone2 clearing time for failure of primary relaying.

PPL does not use fixed time margins. They increase study area generation MW output by 7% as a margin.

d) Monitoring requirements: Rotor angle, Real power output, EFD, speed and terminal voltage of units under study are monitored. Bus Voltages in the same area are also monitored.

e) Acceptable Voltage Dip: Following the disturbance, the voltages of the monitored buses maintain acceptable voltages within +/-5% of the original precontingency voltages f) Acceptable Damping: Following the disturbance, the oscillation of the monitored parameters display a positive damping of oscillation. The positive damping can be observed by drawing an envelope connecting each succeeding peak of the oscillation of the monitored element. This envelope will demonstrate a steady decay within the appropriate test period (normally 10 seconds). Positive damping demonstrates an acceptable response by the system, and no further analysis is required.

g) with/Without PSS: If a PSS is going to be out of service for more than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , it is evaluated for any possible unit output restriction unless it has been studied for that condition in previous simulation testing.

Load Models Static loads are typically modeled in accordance with each Area's or Region's practice as follows Real Power Reactive Power Region Constant Constant Constant Constant Current %

Impedance %

Current %

Impedance %

MAAC 100 0

0 100 ECAR 100 0

0 100 MAIN 100 0

0 100 SERC

100 0

0 100

Applicable to DVP, only PJM Member Company in SERC. Rest to be from the SDDWG dynamics cases 8

SDWG Procedure Manual February 2006

APPENDIX 1 NERC Criteria Table I. Transmission System Standards - Normal and Emergency Conditions Category Contingencies System Limits or Impacts System Stable and both Thermal and Loss of Demand Voltage Limits or Cascading Initiating Event(s) and Contingency within Curtailed Finn Outages Element(s)

Applicable Transfers Rating' A

All Facilities in Service Yes No No No Contingencies Single Line Ground (SLG) or 3-Phase (30) Fault, with B

Normal Clearing:

Yes Nob No Evc:nt resulting in the

1. Generator Yes Nob No loss, of a single

2.

Transmission Circuit Yes Nob No element.

3.

Transformer Yes No b No Loss of an Element without a Fault Single Pole Block, Normal Clearing Y

4.

Single Pole (de) Line YesNob No SLG Fault, with Normal Clearing8 :

C

1. Bus Section Yes Planned/

No Evcnt(s) resulting in Controlled' the loss of two or

2. Breaker (failure or internal Fault)

Yes Planned/

No more (multiple)

_Controlled' elements.

SLG or 30 Fault, with Normal Clearing, Manual System Adjustments, followed by another SLG or 30 Fault, with Normal Clearinge:

Yes Planned/

No

3. Category B (B 1, B2, B3, or B4) contingency, Controlled' manual system adjustments, followed by another Category B (BI, B2, B3, or B4) contingency Bipolar Block, with Normal Clearing8 :

4. Bipolar (dc) Line Fault (non 30), with Normal PlaYnedN Clearing8 :

Yes Controlled' No

5.

Any two circuits of a multiple circuit towerliner Yes Planned/

No Controlled' SLG Fault, with Delayed Clearing8 (stuck breaker or protection system failure):

6.

Generator Yes Planned/

No Controlled'

7.

Transformer Yes Planned/

No Controlled' S. Transmission Circuit Yes Planned/

No Controlled'

9.

Bus Section Yes Planned/

No Controlled' 9

SDWG Procedure Manual February 2006

Standard TPL-O01 System Performance Under Normal Conditions D

d 30 Fault, with Delayed Clearing (stuck breaker or protection system Evaluate for risks and Extreme event resulting in failure):

consequences.

Lxtemeevet rsulingin May involve subst two or more (multiple)

1. Generator

3.

Transformer cMyiole aubat elements removed or customer Deman Cascading out of service.

2.

Transmission Circuit

4. Bus Section generation in a w antial loss of d and

'idespread 30 Fault, with Normal Clearinge:

5. Breaker (failure or internal Fault) area or areas.

Portions or all of the interconnected systems may or may not achieve a new, stable operating point.

"Evaluation of these events may

6.

Loss of towerline with three or more circuits neighboring systems.

7. All transmission lines on a common right-of way

8. Loss of a substation (one voltage level plus transformers)

9. Loss of a switching station (one voltage level plus transformers)

10.

Loss of all generating units at a station I1. Loss of a large Load or major Load center

12. Failure of a fully redundant Special Protection System (or remedial action scheme) to operate when required

13.

Operation, partial operation, or misoperation of a fully redundant Special Protection System (or Remedial Action Scheme) in response to an event or abnormal system condition for which it was not intended to operate

14.

Impact of severe power swings or oscillations from Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.

b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.

c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected transmission systems.

d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed contingency of Category D will be evaluated.

e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.

f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station entrance, river crossings) in accordance with Regional exemption criteria.

10 SDW(T" Procedure Manual February 2006

MAAC Criteria Reliability Standards The bulk transmission system shall be developed:

with flexibility in switching arrangements, voltage control, and other control measures, to ensure reliable system operation under a wide range of operating conditions, so that with all transmission facilities in service and normal scheduled generator maintenance, the loadings of all system components, shall be within normal ratings, stability limits and normal voltage limits, so that it can be operated to meet the following unscheduled contingencies, at all forecasted load levels and firm transfers, without instability, cascading or widespread interruption of load.

A.

The loss of any single transmission line, generating unit, transformer, bus section, circuit breaker, Phase Angle Regulators or single pole of a bipolar DC line in addition to normal scheduled outages of bulk electric supply system facilities without exceeding the applicable emergency rating of any facility or applicable voltage criteria. This shall include the loss of any single facility due to a three-phase fault with normal clearing time and the loss of any single facility with no fault. After the outage, the system must be capable of readjustment so that all equipment (on the MAAC and neighboring systems) will be. loaded within normal ratings and within normal voltagecriteria.

B.

After occurrence of a contingency outage and the readjustment of the system specified in II.A, the subsequent contingency outage of any remaining generator, line, Phase Angle Regulator or transformer without exceeding the short-time emergency rating of any facility and within emergency voltage criteria. After this outage, the system must be capable of readjustment so that all remaining equipment will be loaded within applicable emergency ratings and voltage criteria for the probable duration of the outage.

C.

The loss of any two circuits of a multiple circuit tower line which is one mile or greater in length, bipolar DC line, a faulted circuit breaker or the combination of facilities resulting from a single phase to ground fault coupled with a stuck breaker or other cause for delayed clearing in addition to normal scheduled generator outages without exceeding the applicable emergency rating of any facility or applicable voltage criteria. After the outage, the system must be capable of readjustment so that all equipment will be loaded within applicable emergency ratings for the probable duration of the outage.

In determining the bulk transmission requirements, recognition shall be given to the occurrence of similar contingencies in neighboring systems and their effect on the MAAC system. Interruption of interruptible load in the area of study may be used for readjustment of the system. Stability includes both voltage and angular stability in the 11 SDWG Procedure Manual February 2006

transient time frame and beyond. Contingencies may be simulated at any voltage level but only the performance of the Bulk Electric Supply System of MAAC will be evaluated.

12 SDWG Procedure Manual February 2006

ECAR Criteria Reliability Standards

1. Individual systems shall be planned such that with all transmission facilities in service and with normal (pre-contingency) operating procedures in effect, the network can deliver generator unit output to meet projected demands and provide contracted firm transmission services.

2. Individual systems shall be planned such that the network can be operated to supply projected demands and contracted firm transmission services with any single outage of a transmission line, transformer, special control device or generator due either to a forced outage or the failure of a primary protective device or special protective scheme.

The transmission systems shall also be capable of accommodating bulk facility maintenance outages scheduled prior to such contingencies.

3. Individual systems shall be planned such that the network can be operated to supply projected demands and contracted firm transmission services with contingencies such as the loss of a bus section, breaker failure, double circuit tower outage or the delayed clearing of a single line to ground fault of a generator, bus section, or transmission element. Such contingencies can result in the outage of more than one element or facility. The controlled interruption of demand, the planned removal of generators, or the curtailment of contracted firm power transfers is permitted.

4. The transmission systems shall also be capable of accommodating facility maintenance outages, scheduled prior to such contingencies.

5. Individual systems shall be planned such that Cascading shall not result from the condition of a single outage of a transmission line, transformer, special control device or generator due either to a forced outage or the failure of a primary protective device or special protective scheme, followed by a second single outage. Before or after the second contingency, the controlled interruption of demand, the planned removal of generators, manual intervention or the curtailment of contracted firm power is permitted.

13 SDWG Procedure Manual February 2006

SERC Criteria The SERC Region does not have its own separate Reliability Criteria as such and has adopted the NERC Reliability Standards as its basis for planning the bulk electric power system.

However, SERC has prepared several Supplements where NERC requires Regions to establish certain requiremnets for their members and/or need clarification to be compliant with the NERC requirements.

SERC recognizes that its individual members can have their own internal criteria that is more stringent than the NERC Standards or the SERC Supplaments. However, they may not be less restrictive than the NERC criteria.

Dominion Virginia Power (DVP) is the only SERC member at present that has joined PJM for operational control of its transmission system. The details of stability study criteria for DVP is listed in Appendix 2.

14 SDWG Procedure Manual February 2006

MAIN Criteria MAIN GUIDE NO. 2 TRANSMISSION PLANNING PRINCIPLES AND GUIDES Reliability Standards

1. Electric systems should be planned such that under credible contingencies at projected customer demand levels and anticipated electricity transfers, system voltages and facility loading remain within acceptable limits.

2. Credible, less probable multi-element contingencies at projected customer demand levels and anticipated electricity transfers should be evaluated for risks, consequences, and corrective actions to avoid cascading outages or voltage collapse resulting in uncontrolled interruptions to customer electric supply over a wide area.

3. System normal and single contingency conditions at projected customer demand levels and higher than anticipated electricity transfers should be evaluated for risks,

consequences, and corrective actions to avoid cascading outages or voltage collapse resulting in uncontrolled interruptions to customer electric supply over a wide area.

15 SDWG Procedure Manual February 2006

V. APPENDIX 2 BGE Criteria Dynamic Analysis III.D.1 Introduction Dynamic stability describes the ability of the power system to remain synchronized following a disturbance. Dynamic stability analysis includes transient or first swing stability analysis and up to 10 minutes after any disturbance. Analyzing the system for dynamic stability is crucial to the security of the system, as certain contingencies on the system could cause the system to become unstable.

Because the growth in system loads tend to make the system more stable by adding additional damping, dynamic stability analysis is performed when system changes occur that could affect dynamic performance. The need for this analysis is initiated via various sources including but not limited to the following:

Primary and backup relay scheme changes The addition, removal, or re-rating of generation on the system Generation control system changes Large network impedance changes Abnormal system configuration The base case for stability analysis is created in a similar manner to that of the load flow and short circuit base cases.

However, additional information is necessary in order to simulate the combined dynamic responses of various equipment across the transmission system. Included in this additional information are models for generators, excitation systems, power system stabilizers, governors, and various other equipment. A dynamic simulation links the system model or load flow information with the dynamic data or models to determine if the system or generators within the system will remain stable for various disturbances.

Loads are modeled as constant power in loadflow analysis; however, during stability analysis, loads should be modeled as constant current for the real portion (MW) and constant impedance for the reactive portion (MVAR) unless a representation is known that more specifically applies to the system studied.

All base cases are developed by PJM or MAAC and submitted to BGE upon request. BGE modifies the case as required to suit the specific study. The worst case load level (light, intermediate, or peak) should be utilized to study each scenario except when studies are initiated by bulk power operations with specific system conditions that need to be modeled.

The power system's response to a disturbance is simulated to determine whether or not the system remains stable. In most cases, the output of the simulation is analyzed in graphical form, either creating a power vs. angle curve or plotting system variables (angle, voltage, power, frequency, etc.) with respect to time.

The plot below illustrates a system disturbance that remains stable.

In this simulation, a fault occurred at time 0+ and the magnitude of the oscillations reduced in magnitude as time increased.

16 SIDWG Procedure Manual February 2006

Plot 1 System Remaining Stable After Disturbance Timie Two examples of unstable systems can be found below.' Plot 2 illustrates a system disturbance that causes sustained oscillations and Plot 3 illustrates a system disturbancethat causes dynamic instability.

1)

Timie Plot 2

System Experiencing Sustained Oscillations Timne Plot 3

System Experiencing Dynamic Instability 17 SDWG Procedure Manual February 2006

III.D.2 Disturbances Per PJM/MAAC criteria, the stability of BGE's and neighboring transmission systems must be sustained without loss of load for all contingencies as described in section IIl.D.l.a including:

Three-phase fault with normal clearing Single phase-to-ground fault with a stuck breaker or any other cause for delayed clearing The loss of any single facility with no fault For BGE, the system should remain stable given the following disturbances:

Three-phase fault at a point 80% of the circuit impedance away from the station under study with zone two clearing Failure of a generator Failure or all generation from one station Opening or closing of a transmission facility Loss of a large block of load Faulted circuit breaker For all of the disturbances above, the system must maintain angle stability. In cases where the system is unstable, the system should be enhanced to improve stability as set forth in section III.D.4.

llI.D.3 Performing the Analysis BGE performs dynamic stability analysis utilizing the PSS/e Power System Simulation software.

Base case load flow and dynamics data are obtained from either PJM or MAAC and will include the BGE system in as much detail as possible with the neighboring systems as modeled by PJM or MAAC. When performing the analysis the most up-to-date information should be used. This would include any recent enhancements to system models, generation models, or operating times.

For all contingencies involving faults, the fault clearing times are of the utmost importance. The amount of time it takes for a fault to clear has a direct impact on the stability of the system.

When performing dynamic stability analysis actual operating times should be obtained from the Design and Engineering Analysis section of the System Protection & Control Master Section whenever possible. These times include zone one and zone two clearing times, backup clearing times, reclosing times, and auto-transfer times. The clearing times include the total relay trip times plus the longest probable breaker interrupting times. Whereas in short circuit analysis we use the quickest possible total interrupting times to simulate worst case scenarios, for stability, we assume the longest possible total interrupting times to simulate worst case scenarios.

Often, transmission operations may request a stability analysis be performed for any contingency given the system in an abnormal configuration.

When these requests are made, great effort should be taken to modify the base case so that it is as similar as possible to the system configuration under study. The load level, generation dispatch, and voltage control mechanisms should be reviewed to create a study case as close as possible to what the system is experiencing.

III.D.4 Possible Solutions There are several ways to enhance system stability in the event that unstable conditions are identified. Some are listed below.

The addition of power system stabilizers Shorten fault clearing times (primary or backup)

Generation runback or trip schemes 18 SDWG Procedure Manual February 2006

Limitation of generation output Addition of transmission lines Addition of transmission series capacitors Addition of transmission shunt capacitors Addition of dynamic reactive devices Schemes for the removal or transferal of load An analysis of the system's response to a disturbance that causes instability will provide an indication as to what system enhancements can be employed to attain stability. An economic analysis must be performed to determine the best solution.

As a delivery company, BGE does not own generators to which it can make enhancements. BGE can only change the characteristics of the transmission system to make the system stable. PJM may direct those that control the generating stations to make changes to their units for stability problems and BGE may provide input to that process if the generating unit impacts BGE's facilities.

19 SDWG Procedure Manual February 2006

DVP Criteria There are many different variables that affect the results of a stability study. These factors include:

pre-fault and post-fault system configuration

" system load level and load characteristics

" generation dispatch patterns and unit dynamic characteristics

" type and locations of system disturbances

total fault clearing time(s)

" the amount of flow interrupted as a result of switching out a faulted element

" level of detail and accuracy of available models/data

" proximity to other generating units Many of these factors change in the operating arena on a continuous basis. Every effort should be made to evaluate the most severe, yet credible/probable combinations of line/faults/equipment failures.

General Requirements (for New and Existing Installations)

I The criteria for performing stability studies near generating stations on Dominion Virginia Power (DVP) system should meet, at a minimum, the requirements of the NERC Reliability Standards (the Standards).

Furthermore, some additional criteria have been established (see Additional Requirements below) as a prudent utility practice to maintain and enhance stability.

These additional measures should provide some margin to the minimum requirements of the Standards and should protect the system for any unpredicted deterioration in system operating conditions and/or data inaccuracies.

For breaker failure backup clearing, it will be assumed that only one pole is "stuck" where three separate mechanisms (independent poles) are available (e.g. all 500 kV breakers on DVP system).

The results of stability studies are generally valid for about 15 to 20 seconds following a disturbance.

Therefore, disturbance simulations will be carried out to 15 to 20 seconds, in general, and no attempt will be made to simulate any time re-closure after 15-second time period.

The transformer taps are frozen at the pre-disturbance level throughout the simulations.

Additional Requirements 20 SDWG Procedure Manual February 2006

A. For new Installations Stability must be maintained for the breaker failure backup clearing following a three-phase fault (not just. for a single-phase-to-ground fault as required by the Standards) near generating stations with all system components in-service as planned prior to the contingency.

The severity of the fault to be applied may be reduced to a two-phase-to-ground fault provided that out-of-step protection is applied to the generating unit(s). The generation tripped due to an out-of-step condition should be generally limited to an amount equivalent to the largest generator on the system.

Stability must also be maintained for the delayed-clearing of a three-phase fault due to a primary protection system failure with all system components in-service as planned prior to the contingency. The fault shall be placed at the end of the first zone coverage resulting in a second zone trip. It is not necessary to test for this condition where dual primary relays are installed.

B. For Existing Installations Stability must be maintained for the breaker failure backup clearing following a two-phase-to-ground fault (not just for a single-phase-to-ground fault as required by the Standards) near generating stations with all system components in-service as planned prior to* the contingency.

Stability must also be maintained for the delayed-clearing of a two-phase-to-ground fault due to a primary protection system failure with all system components in-service as planned prior to the contingency. The fault shall be placed at the end of the first zone coverage resulting in a second zone trip. It is not necessary to test for this condition where dual primary relays are installed.

Special Considerations Some of the items in Table I of the NERC Reliability Standards may not be very clear.

The DVP's interpretation is that, in general, engineering judgement must be applied in such cases. For example, at what system load levels the studies need to be performed? It is easy to say at "all load levels" but it is not practical. A.generator angular stability is generally more critical at lighter load levels than at peak load. Generally, DVP performs stability studies at 60 to 70 percent load levels since the system is exposed to this load level for longer period of time during a given year. Also, the plant under study is to be fully dispatched and nearby. other units may need to be dispatched being ON or OFF depending on system topology. Some locations may need to be studied with different base case scenarios with different generation dispatches to assess the proper impact on stability.

21 SDWG Procedure Manual February 2006

For a transmission component being out in the base case (i.e. forced or maintenance outages), this operating condition is generally for a short period of time. The decision to trip the unit for the next contingency, should it occur, or to reduce the output on a temporary basis would depend on the location and importance of the plant. The decision to install high-speed unit trips or special stability relays or to accept restriction on unit output will be made on a case by case basis. Furthermore, there may be situations where the cost is excessive, or it is not practical to engineer a project to alleviate an unstable condition(s). In such cases, a decision may be made to live with the situation as long as the probability of such occurrences is rare, and the resulting unstable condition is confined to local area only (i.e. without the danger of cascading).

22 SDWG Procedure Manual February 2006

AEP TRANSIENT STABILITY DISTURBANCE TESTING CRITERIA PREFAULT CONDITION All Transmission Facilities in Service 765 KV PLANTS 345 KV PLANTS 138 KV PLANTS IA Permanent single line-to-ground (SLG) fault with l(p breaker failure. Fault cleared by backup breakers.

IB Permanent SLG fault cleared by primary breakers. 3(p fault developed following HSR. Fault cleared by primary breakers.

IC 39 line opening without fault.

ID Permanent SLG fault with unsuccessful HSR, if applicable.

Fault cleared by primary breakers, 2A Permanent SLG fault with I (p breaker failure. Fault cleared by backup breakers.

2B Permanent 3(p fault with unsuccessful HSR, if applicable.

Fault cleared by backup breakers.

2C 3(p line opening without fault.

2D Permanent 3(p fault with unsuccessful HSR, if applicable.

Fault cleared by primary breakers.

2E' 3p(

line opening without fault.

2F Temporary 3(p fault with successful HSR, if applicable.

One Transmission Facility Out of Service 3A Permanent SLG fault with 3(p breaker failure. Fault cleared by backup breakers.

3B Permanent 3y fault with unsuccessful HSR, if applicable. Fault cleared by backup breakers.

3C 3y line opening without fault.

3D Permanent 3cp fault with unsuccessful HSR, if applicable. Fault cleared by primary breakers.

3E 3y line opening without fault.

3F Temporary 3(p fault with successful HSR, if applicable.

3G 3(p line opening without fault.

IE.39 line without fault.

opening Two Transmission Facilities Out of Service IF Temporary SLG fault with successful HSR, if applicable.

IG 3(p line opening without fault.

2G 3(p line without fault.

opening 23 SDWG Procedure Manual February 2006

PPL Criteria With regard to PPL EU's stability analysis methods, in general, PPL follow MAAC criteria. PPL EU's interpretation of the criteria requires that system stability must be maintained, without significant loss of generation, for the following types of fault conditions occurring at the most critical location at ANY (peak, intermediate or light) load level:

1) Permanent three-phase fault cleared by normal primary relay action, including reclosing, if applicable.

2) Permanent phase to ground fault and the failure of a protective device to operate properly causing a stuck circuit breaker, delayed clearing or other events having similar probability of occurrence.

3) Permanent three-phase fault at a point 80% of the line impedance away from the generating facility under consideration with delayed (Zone 2) clearing times, including reclosing, if applicable.

In addition, PPL EU considers less probable contingencies to determine the severity of the consequences. These less probable events are:

a) Permanent three phase fault involving both circuits of a double circuit line with normal clearing and reclosing sequences, if applicable (tower failure scenario).

b) Permanent three-phase fault with stuck breaker or other cause of delayed clearing.

c) Permanent three phase fault on one line with an overtrip of another unfaulted line. Both the overtrip and clearing of the faulted line occur in normal primary clearing time. Reclosing sequences, if applicable, should be included.

If the tests normally performed show that the system will not remain stable, or the consequences of the less probable contingencies are severe, additional studies are performed to determine methods to eliminate the stability concern.

It should also be noted that in order to provide and maintain reasonable supply to PPL customers and other facilities, PPL EU assumes a transient synchronous stability safety margin of 7%. This implies that the net summer certified capacity of the generator being studied in the PPL EU territory is increased by 7% to account for periods of abnormal or unusual system operation.

24 SDWG Procedure Manual February 2006

ComEd Criteria CornEd Transmission Planning Security Criteria 25 SDWG Procedure Manual February 2006

PHI Criteria Dynamic Stability analysis is applied when we are studying either transient or voltage stability cases. It addresses the transmission system dynamic behavior for certain disturbances and determines if adjustments or enhancements are needed for reliable system operation.

For Transient Stability analysis, we study the system at light load. Transient stability refers to a situation where following a disturbance (e.g., single-line to ground or three-phase fault), electromechanical oscillations occur between generators. These oscillations may cause generators to become unstable and trip offline at some point after the disturbance. The time frame of this instability will be in the order of 0 to 10 seconds which will capture only generator inertial and excitation dynamics. We will apply the rotor angle maximum swing criteria (<100 degrees) and use bus voltage & frequency deviations.

For Voltage Stability analysis, we study the system at peak load. Voltage stability accounts for the longer-term effects, which are generally times greater than 30 seconds.

This type of analysis will involve the loss of more controls and equipment reaching their limits, which will eventually lead to a progressive voltage decrease followed by collapse. This includes the effects of prime mover control, LTC, and excitation limiters.

PHI, at a minimum, applies the same criteria set forth by PJM and MAAC regarding stability analysis. We use the same power flow cases and supporting files. We evaluate three-phase (3PH) faults, single-line-to-ground (SLG) faults, and single-line-to-ground (SLG) faults with stuck breaker. We also follow their same criteria for load modeling (100% constant current for real power and 100% constant impedance for reactive power).

26 SDWG Procedure Manual February 2006

Appendix 3 Generator data request form Unit Capability Data Gross MW Output Unit Auxiliary Load MW Net MW Capacity GSU MW Losses\\NV Station Service Load MW Net MW Capacity = (Gross MW Output - Unit Auxiliary Load MW)

Queue Letter/Position/Unit ID:

Primary Fuel Type:

Maximum Summer (92' F ambient air temp.) Net MW Output**:

Maximum Summer (920 F ambient air temp.) Gross MW Output:

Minimum Summer (920 F ambient air temp.) Gross MW Output:

Maximum Winter (300 F ambient air temp.) Gross MW Output:

Minimum Winter (30 F ambient air temp.) Gross MW Output:

Gross Reactive Power Capability at Maximum Gross MW Output - Please include Reactive Capability Curve (Leading and Lagging):

Individual Unit Auxiliary Load at Maximum Summer MW Output (MW/MVAR):

Individual Unit Auxiliary Load at Minimum Summer MW Output (MW/MVAR):

Individual Unit Auxiliary Load at Maximum Winter MW Output (MW/MVAR):

Individual Unit Auxiliary Load at Minimum Winter MW Output (MW/MVAR):

Station Service Load (MW/MVAR):

GSU losses are expected to be minimal.

- Your project's declared MW, as first submitted in Attachment N, and later confirmed or modified by the Impact Study Agreement, should be based on either the 920 F Ambient Air Temperature rating of the unit(s) or, if less, the declared Capacity rating of your project.

27 SDWG P:rocedure Manual February 2006

Unit Generator Dynamics Data Queue Letter/Position/Unit ID:

MVA Base (upon which all reactances, resistance and inertia are calculated):

Nominal Power Factor:

Terminal Voltage (kV):

Unsaturated Reactances (on MVA Base)

Direct Axis Synchronous Reactance, Xd(i):

Direct Axis Transient Reactance, X'd(i):

Direct Axis Sub-transient Reactance, X"d(i):

Quadrature Axis Synchronous Reactance, Xq(i):

Quadrature Axis Transient Reactance, X'q(i):

Quadrature Axis Sub-transient Reactance, X"q(i):

Stator Leakage Reactance, Xl:

Negative Sequence Reactance, X2(i):

Zero Sequence Reactance, XO:

Saturated Sub-transient Reactance, X"d(v) (on MVA Base):

Armature Resistance, Ra (on MVA Base):

Time Constants (seconds)

Direct Axis Transient Open Circuit, T'do:

Direct Axis Sub-transient Open Circuit, T"d0 :_

Quadrature Axis Transient Open Circuit, T'qo:_

Quadrature Axis Sub-transient Open Circuit, T"qo:

Inertia, H (kW-sec/kVA, on KVA Base):

Speed Damping, D:

Saturation Values at Per-Unit Voltage [S(1.0), S(1.2)]:

Units utilize a Generator model 28 SDWG Procedure Manual February 2006

Unit GSU Data Queue Letter/Position/Unit ID:

Generator Step-up Transformer MVA Base:

Generator Step-up Transformer Impedance (R+jX, or %, on transformer MVA Base):

Generator Step-up Transformer Reactance-to-Resistance Ration (X/R):

Generator Step-up Transformer Rating (MVA):

Generator Step-up Transformer Low-side Voltage (kV):

Generator Step-up Transformer High-side Voltage (kV):

Generator Step-up Transformer Off-nominal Turns Ratio:

Generator Step-up Transformer Number of Taps and Step Size:

29 SDWG Procedure Manual February 2006

r-I~

C,

.9 TO CO PJM Relay Subcommittee Survey of Fault Clearing Times ReprenettNe wor., case total clearing tlimes (cycles) 0*

Voltage Case Fault Level Condition AE DPL BGE GPU PPL PECo PEPCO PSEG AP VP*

CornEd AEP rhre pas LG fault w/ Norma Clearing -

1 rA,.=

=

3.0-35 3.0-4.0 SLG "a'"'/Dlyd larn 765 kV 2

Doe to Fe.ure of

,ro roe i_

30-3.5 3.0-4.0 3

(I.= toSokBekr(tGnrating Stations) no 14 SLG fault w/Delayed Clearing -

4 Due to Stuck Breaker (at Non-Generating Statioso) 1 11-12 14 IThree phase or OLD fautt err Normal Cleeritg -

1 tan 3.5-4,0 3.5-4.5 3.5-4.0 3.5 3.5.4.0 3.7-4.2 4

4 35-45 na 3.5-40 OLD faolt w/Dltayed Clearng-500 kV 2

yueto ailureo ofprnrayretlng 3.5 -40 35 - 4.5 24.5-25.5 3.5 3.5-4.0 37.42 4

21 3.5-4.5 na 3.5 -4.0 3 LGfeteStckeBrL er retGanerotinoSt0an 120-130 120-130 5

10-12,5 11.7-13.6 12 na 8.75.135" na 14 SLG fault wlDeayed Clewing -

4 Dusto Stuck Breaker (at Nr-Generting Stations) 10.0-12.5 12.0 - 13.0 12.0- 13.0 12 12.5 11.0-12.1 16 12 8.75-13,5 no 14 Three phase or SLG fault w/ Nonona Clearing -

T Al relaying tn service 3.5 - 4.)

3.0-4.5 3.5-4.0 SLG faunt w Delayed Clearing -

345 kV 2

Due to Failure of prnarty relaying 25.5-265 3.0-4.5 3.5 - 4.0 OLG fault By Dat.a4 Cl0aro.g -

3 DUe to Stuckd Breakr at Generating Stations) 13.0.140 7.5-13 15 SLG fatul w/Dalaad Clearing -

4 Due to Stuck Breaker (at Non-Genrenting Statioos) 13.0 14.0 11-13 15 Three phase or SLO (soul w] Nnorat Cltaing.

1 Alo.ylninserolna 4.0 - 50 4.0 - 5.0 4.5 4.0- 5.0 40 50 40.5.0 4.2-4.7 5

5 4.5-5.5 no 4.5-5.0 5LG f=Zu t Delayed Clearing -

230 kV 2

Due to Failure of primary relaying 34.0 - 35.0 24.0-25.0 34.0 34 35 28-30 42-4.7 30 30 30.0-33.0 no 4.5 - 5.0 L3 11etoStockBreaker(atGenersting Station) 16.5-17.5 15.0 -16.0 14.0- 15.0 14.0- 15.0 9.0 10.0 11.0-15.0 11.6-12.1 17 so 11.5 14.0 n

DuetoS kr C rsin Satins W -17.

1 1.5-14.0 '

a 16 SLG Naull w/Delayed Ctaring -

4 Due tO Slck Breaker (at Non-Generating Stations) 16.5-17.5 15.0. -1.0 14.0 - 15.0 14.0. 16.0 12.0. 17,0 11.0-15.0 11.6-12.1 17 15 1.5. - 26.0 no 16 Thres phase or SLG fault wf Normal Cleanng -

1 1

erotayo4n lart 5.0-70 5.0-7.0 4.5 5.0-7.0 5.0-8.0 6.0-7.0 4.4-6.4 6

7 45.5-55 3.5-6.0

4.

5.0 SLG faubt w/ Dalayed Clearing -

115kV 2

Due to Failure of prm=ryretaying 3540 - 37.0 350- 37,0 34.0 36 350 -60.0 30-32 4,4 30 36 33.0 -410 20-27 33 -63 OLD taolt w/lDetayod Clearing -

& 134kit 3

DuetoStockBreskerlen`eretongStation-(

17.5-19.5 17.5 19.5 14.0-15.0 17.0-20.0 30.0-60.0 17 20.6-22.0 18 na 11.5-260 13-15 il OLD fault wIDelayed Clearing -

4 Due to Stuck Brek (at Non-G.anrating Stations) 17.5.195 17.5-19.5 14.0- 15.0 19.0-20,0 30.0.60.0 17 20.6-22-0 1i 20 11.5 - 26.0 13-20 Is Trhree phaos or SLG fulst wt Nonnal Clearing.

I Arellayiag In -rie 6.0-10,0 5.0 - (0.0 5.0-10.0 7T0 t 120 9.0-110 6.4-6.7 6

4.5 -10.5 3.0-9.0 33 -63 SLG taoutl wDelayed Claring-69 kV 2

Dueto Fhoreol nnraryrelaymng 35.0-70.0 35,0-.70.0 36.0-40.0 300 -60.0 31-35 6.4-6.7 30 33.0-44.0 20-27 33-93 OLD fault wiDelayed Cleaing.

3

LrailnStockgBeakr letGnen Stations) 20.5-25.5 17.5-22.5 17.0.23.0 30.0 -600 15-20 22.6-24.0 na 11.5 -25.0 13-20 no SLG fault w/Delayed Clearing -

4 Due to tuck Breake (at Non-.Genereing Station) 20.50-25.5 175-22.5 0.0-230 30.0-60.0 68-20 22.6-24.0 lB 11.5-29.0 13-20 33-93 15 CPS

SUBJECT:

Calvert Cliffs Transmission Grid Interface Specification Page I of 2

REFERENCES:

1. Calvert Cliffs UFSAR

2. Calvert Cliffs Tech Specs

3. Docketed Correspondence

1.

500 kV Switchyard is designed to function reliability under all conditions of power plant operation. It will furnish startup power to the power plant, and reliably function and isolate trouble in the power system grid under normal and abnormal conditions.

2.

Load flow and stability studies indicate that the tripping of one or both fully loaded Calvert Cliffs generating units would not impair the ability of the system to supply plant service. These studies were made at projected peak load conditions and also at minimum load conditions when the two Calvert Cliffs units were supplying the entire Baltimore System. In addition, some major transmission circuits were assumed to be out of service at the time.

3.

The spinning reserve policy of the Pennsylvania-New Jersey-Maryland (PJM)

Interconnection, of which BGE is a member, is to maintain enough reserve capacity synchronized to the system to cover the largest single contingency in the PJM.

4.

Transient stability under fault conditions in the switchyard has been verified by digital computer study which included the interconnected systems and analyzed for various contingencies, including the failure of a 500 kV breaker to trip under a fault condition.

5.

The required switchyard operating voltage range to prevent operation of the vital 4kV bus degraded voltage relays is 500 to 550kV with an allowable contingency situation of 475kV (5% drop). If either of the plant service transformers are out of service, the required switchyard voltage range becomes 520 to 550kV. Operation of the vital 4kV degraded voltage relaying separates the vital 4kV system from the offsite sources and places them on the emergency diesel generators. This relaying operates if 4kV voltage drops to less than 90% of nominal for more than 101 seconds, 75% of nominal for more than 8 seconds or on loss of voltage after 2 seconds.

6.

Restoration of offsite power after a station blackout is assumed to take not less than 12 hrs to accomplish.

7.

The minimum requirement for frequency for offsite power for the Calvert Cliffs units is greater than 57.5Hz. If the frequency of the offsite power drops to 57.5Hz or less for 6 cycles, both Calvert Cliffs turbine/generators will trip on under-frequency. Buy procedure, both Calvert Cliffs units are operated at not less than 58.5 Hz. Also, the Calvert Cliffs units do not regulate frequency when paralleled to the grid.

SUBJECT:

Calvert Cliffs Transmission Grid Interface Specification Page 2 of 2

REFERENCES:

I. Calvert Cliffs UFSAR

2. Calvert Cliffs Tech Specs

3. Docketed Correspondence

8.

Tech Spec requirements for offsite sources:

The offsite power supply shall consist of two qualified circuits between the offsite transmission network and the onsite Class 1E Electrical Power Distribution System.

Calvert Cliffs offsite supplies consist of 3 500kV transmission lines (each of which can handle the full output of both Calvert Cliffs Units simultaneously) and a single 69/13.8 kV line (which is designed to supply only the necessary power to maintain both Calvert Cliffs units in a safe shutdown condition simultaneously). Any two of the four aforementioned sources will satisfy the offsite source requirements in the Tech Specs.

Exelon and AmerGen Nuclear Generating Stations The following is a list of stability cases referenced in our plant UFSAR's that are beyond the required MAAC stability criteria.

Limerick:

1) The Limerick Units 1 & 2 generators are to be stable for the following cases:

a) 3 phase close in fault on any single 500 kV or 230 kV line, where the most critical Limerick circuit breaker fails to open and the fault is cleared at Limerick by backup protective equipment (8 cycles).

b) 3 phase high side or low side faults on the 4AIB transformer, where the most critical Limerick circuit breaker fails to open and the fault is cleared at Limerick by backup protective equipment (8 cycles).

c)

Simultaneous 3 phase close in faults on the 5030 and 5031 lines cleared by primary protection equipment (3.5 cycles).

2) The transmission system is to remain stable for the following three cases with either one or both Limerick units in service:

a) Loss of Peach Bottom Units 2 & 3 b)

Loss of the largest single load, North Wales substation c)

Simultaneous 3 phase faults on 5030, 5031, 220-62, and 130-30 lines in the vicinity of Perkiomen substation with normal clearing.

Peach Bottom:

No cases beyond the required MAAC stability criteria.

TMI:

No cases beyond the required MAAC stability criteria Oyster Creek:

1) There will be no Oyster Creek generating unit transient instability, transmission system transient instability, transmission line overloads or cascading outages as a result of a 3 phase fault with backup delayed clearing (i.e. stuck breaker) of any one of the two 230 kV lines emanating from Oyster Creek.

2) There will be no Oyster Creek generating unit transient instability, transmission system transient instability, transmission line overloads or cascading outages as a result of a 3 phase fault with primary relay clearing involving any of the 34.5 kV lines emanating from Oyster Creek.

Note: This is considered required by the MAAC criteria since a fault on the 34.5 kV system must not create bulk transmission system overloads, instability or cascading outages, however it is identified here for emphasis because of Oyster Creek's unique interconnections to the 34.5 kV system.

3) The simultaneous loss of the Oyster Creek generating unit and the largest generating unit in New Jersey (Salem Unit 2) will not result in transmission system transient instability, transmission line overloads, cascading outages or intolerable voltage conditions.

b 1

P PPL Susquehanna Stability Analysis Criteria The PPL 230kv and 500kV Transmission System is planned in accordance with Mid-Atlantic Area Council (MAAC) Reliability Principles and Standards.

In general, the stability requirements are that the system shall be maintained without loss of load during and after the following types of contingencies based on the latest load forecast prepared annually by the PJM Load Analysis Subcommittee.

Single contingency outage conditions (MAAC reliability criteria section IIA)

Double circuit tower line outage or single stuck circuit breaker conditions (MAAC reliability criteria section TIC)

Three phase faults with normal clearing time (MAAC reliability criteria section IV)

Single line to ground faults with a stuck breaker or other cause for delayed clearing (MAAC reliability criteria section IV)

The MAAC reliability criteria also require an evaluation of the ability of the bulk power system to withstand abnormal system disturbances (MMAC reliability criteria section V). The MAAC reliability criteria does not require that the bulk power system be planned and constructed to withstand these abnormal disturbances due to their low probability of occurrence. However, it is PPL Electric Utilities position to maintain these cases stable for PPL Susquehanna.

These abnormal system disturbances are analyzed not on the basis of their likelihood of occurrence but rather as a practical means to study the system for its ability to withstand disturbances beyond those that can be reasonably expected.

A total of six (6) contingencies identified in the FSAR Table 8.2-1 are required by MAAC standards.

Seventeen (17) other contingencies are not required by MAAC standards but analyzed to assure a high level of transmission system reliability. FSAR table 8.2-1 is attached with the list of stability cases performed for PPL Susquehanna LLC.

TABLE 8.2-1 SUSQUEHANNA UNIT #1 & #2 STABILITY CASE LIST (SUMMER LIGHT LOAD CONDITIONS)

M<..-

I

"...........:':?

Fault Tests Required to be Stable (8.2.1.5.C)

R-1 3 phase fault at Susquehanna 500 kV on the Sunbury 500 kV line. Fault cleared in primary Stable clearing time.

R-5 Phase-ground fault at Susquehanna 500 kV on Sunbury 500 kV line with Sunbury South 500 kV Stable circuit breaker stuck. Clear remote terminal In primary time. Delayed clearing of Susquehanna.

R-6 3 phase fault at Susquehanna 230 kV on the Susquehanna 500/230 kV transformer. Fault cleared Stable in primary clearing time.

R-7 3 phase fault at Montour 230 kV on Susquehanna 230 kV line. Fault cleared In normal primary Stable clearing time.

R-1 3 Phase-ground fault at Susquehanna 500 kV on Susquehanna-Wescosville-Alburtis 500 kV line with Stable Wescosville South 500 kV circuit breaker stuck. Clear remote terminal in primary time. Delayed clearing at Susquehanna.

R-1 8 3 phase fault at Susquehanna 230 kV on Harwood IE. Palmerton) Double Circuit. Fault cleared in Stable primary clearing time.

Rev. 54, 10/99 Page 1 of 4

0 I

TABLE 8.2-1 SUSQUEHANNA UNIT #1 & #2 STABILITY CASE LIST (SUMMER LIGHT LOAD CONDITIONS)

I Fault Tests Not Required to be Stable (8.2.1.5.C)

N-2 3 phase fault at Susquehanna 500 kV on the Sunbury 500 kV line with one breaker pole stuck at Stable Sunbury. Clear Susquehanna in primary time. Delayed clearing at remote terminal.

N-3 3 phase fault at Susquehanna 500 kV on the Susquehanna-Wascosvlle-Alburtis 500 kV line with Stable one Susquehanna 5001230 kV transformer breaker pole stuck. Clear remote terminal in primary time. Delayed clearing of Susquehanna.

N-4 3 phase fault at Susquehanna 500 kV on the Sunbury 500 kV line with one Susquehanna 500/230 Stable kV transformer breaker pole stuck. Clear remote terminal in primary time. Delayed clearing of Susquehanna.

N-8 3 phase fault at Susquehanna 230 kV on Montour line with stuck west bus breaker. Clear remote Stable terminal in primary time, clear Susquehanna with delay (lose Stanton-Susquehanna #2 230 kV line).

N-9 3 phase fault at Susquehanna 230 kV on Jenkins line with stuck east bus breaker. Primary Stable clearing at remote terminal. Delayed clearing at Susquehanna.

N-10 3 phase fault at Susquehanna 230 kV on the 500/230 kV transformer with stuck west bus Stable breaker. Primary clearing at remote terminal (Susquehanna 500 kV Switchyard). Delayed clearing at Susquehanna 230 (lose Stanton-Susquehanna #2 230 Kv line).

N-1 1 3 phase fault at Susquehanna 230 kV on Harwood line with stuck tie breaker pole. Clear two Stable poles in primary time. Clear stuck pole In delayed clearing time (lose Sunbury-Susquehanna 230 kV line).

Rev. 54, 10/99 Page 2 of 4

E SSES-FSAR 0

=

TABLE 8.2-1 SUSQUEHANNA UNIT #1 & #2 STABILITY CASE LIST (SUMMER LIGHT LOAD CONDITIONS)

I N-12 3 phase fault at Susquehanna 230 kV on E. Palmerton line with one pole stuck on west bus breaker. Clear two poles in primary time. Clear stuck pole in delayed clearing time (lose Stanton-Susquehanna #2 230 kV line).

Stable N-14 ' Susquehanna-Wescosville-Alburtis 500 kV and Susquehanna-Harwood (E. Palmerton) Double Stable Circuit 230 kV crossing failure (3 phase fault on all circuits). Automatically trip Susquehanna Unit

1. Clear Susquehanna-Wescosville-Alburtis 500 kV line In primary time. Clear Susquehanna-Harwood and Susquehanna-E. Palmerton 230 kV lines in primary time.

N-1 i 3 phase fault near E. Palmerton on all lines In E. Palmerton-Harwood R/W corridor. Clear Stable Susquehanna-Wescosville-Alburtis 500 kV line in primary time. Primary clearing of E. Palmerton-

_ Susquehanna and Harwood-Siegfried 230 kV lines.

N-16:

3 phase fault near Susquehanna on both lines In Sunbury-Susquehanna R/W corridor. Clear Stable Sunbury-Susquehanna #2 500 kV line in primary time. Primary clearing of Sunbury-Susquehanna

1 230 kV line.

N-17 iI3 phase fault near Susquehanna 500 kV at Sunbury 230 kV line crossing. Trip Susquehanna-Stable Wescosville-Alburtis 500 kV, Sunbury-Susquehanna #2 500 kV, and Unit #2 In primary time. Trip Sunbury-Susquehanna #1 230 kV in primary clearing time.

N-1 9 3 phase fault at Columbia-Frackville 230 kV line crossing. Trip Sunbury-Susquehanna #2 500 kV Stable line in primary time. Trip Columbia-Frackville and Sunbury-Susquehanna #1 230 kV lines in primary time.

N-20 3 phase fault on 230 kV side of Unit #1 main transformer. Trip Unit #1 main transformer. Trip Stable

Unit #1 and overtrip Unit #2 In primary time (loss of entire station).

N-21',; 3 phase fault at Susquehanna 230 kV on Unit #1 generator leads with a stuck west bus breaker.

Stable Trip Unit #1 and Stanton #2 line.

Rev. 54, 10/99 Page 3 of 4

0 SSES-FSAR TABLE 8.2-1 SUSQUEHANNA UNIT #1 & #2 STABILITY CASE LIST (SUMMER LIGHT LOAD CONDITIONS)

II I

N-23 Sudden loss of all lines from Susquehanna 230 kV Switchyard Stable N-24 3 Phase fault on Susquehanna-Jenkins 230 kV line 80% towards Jenkins with pilot relaying out.

Stable

=

Fault cleared in Zone 2 (backup) time at Susquehanna and Zone 1 time at Jenkins.

Rev. 54, 10199 Page 4 of 4

r1 Q SYSTEM DYNAMICS WORKING GROUPReid:2706

w*Revised:

2.7.2006 Mail Address Fedex Address Phone/Fax Numbers Mahendra Patel, Chair Mahendra Patel Office:

610-666-8277 PJM Interconnection Fax:

610-666-2296 PJM Interconnection 2621 Van Buren Ave.

E-Mail:

patelm3@pjm.com 2621 Van Buren Ave.

Norristown, PA 19403 Norristown, PA 19403 Admin. Asst./Secretary:

Phone:

Robert J. O'Keefe Robert J. O'Keefe Office:

614-552-1658 AEP Service Corp Fax:

AEP Service Corp 700 Morrison Road Internet: rjo'keefe@aep.com 700 Morrison Road Gahanna, OH 43230 Gahanna, OH 43230 Admin. Asst./Secretary:

Phone:

Jim Summers Jim Summers Office:

302-454-4137 Conectiv Power Delivery Fax:

Conectiv Power Delivery 401 Eagle Run Road Internet: jim.summers@conectiv.com 401 Eagle Run Road Newark, DE Newark, DE Admin. Asst./Secretary:

Phone:

Hertzel Shamash Hertzel Shamash Office:

937-331-4680 Dayton Power & Light Co.

Fax:

Dayton Power & Light Co.

1065 Woodman Drive Internet: hertzel.shamash@dplinc.com 1065 Woodman Drive Dayton, OH 45432 Dayton, OH 45432 Admin. Asst./Secretary:

Phone:

Kirit Doshi (RS-5)

Kirit Doshi Office:

804-819-2322 Dominion Virginia Power Fax:

804-819-2342 Dominion Virginia Power 120 Tredegar Street (RS-5)

Internet: kiritdoshi@dom.com P.O. Box 26532 Richmond, VA 23219 Richmond, VA 23261-6532 Admin. Asst./Secretary:

Phone:

Tom Wakeley Tom Wakeley Office:

215-841-4738 Exelon Energy Delivery - East (PECO)

Fax:

Exelon Energy Delivery - East (PECO) 2301 Market Street Internet: thomas.wakeley@peco-energy.com 2301 Market Street S6-2 S6-2 Philadelphia, PA 19101 Admin. Asst./Secretary:

Philadelphia, PA 19101 Phone:

42411 1 of 2 Page(s)

Revised:

2.7.2006 3:51 PM (ROS) SIS - SYSTEM INFORMATION SUBCOMMITTEE

SYSTEM DYNAMICS WORKING GROUP Revised: 2.7.2006 Mail Address Fedex Address Phone/Fax Numbers Ed Baznik Ed Baznik Office:

330-384-4581 First Energy Fax:

First Energy Internet: ejbaznik@firstenergycor'pcom Admin. Asst./Secretary:

Phone:

Mark Kuras Mark Kuras Office:

610-666-8924 MAAC Fax:

MAAC 955 Jefferson Ave.

Internet: kuras@pjm.com 955 Jefferson Ave.

Norristown, PA 19403 Norristown, PA 19403 Admin. Asst./Secretary:

Phone:

Steve Jeremko Steve Jeremko Office:

607-762-8836 NYSEG-RGE Fax:

NYSEG-RGE Carrigg Center Internet: stjeremko@nyseg.com Carrigg Center 18 Link Drive 18 Link Drive Binghamton, NY 13902 Admin. Asst./Secretary:

P.O. Box 5224 Phone:

Binghamton, NY 13902-5224 Mike DeCesaris Mike DeCesaris Office:

610-774-4558 PPL Electric Utilities Fax:

PPL Electric Utilities Two North 9th Street Internet: medecesaris@pplweb.com Two North 91h Street Allentown, PA 18101 Allentown, PA 18101 Admin. Asst./Secretary:

Phone:

Eric Sorber Eric Sorber Office:

570-830-1286 UGI Utilities, Inc.

Fax:

UGI Utilities, Inc.

400 Stewart Road Internet: esorber@ugi.com 400 Stewart Road Wilkes Barre, PA 18773 Wilkes Barre, PA 18773 Admin. Asst./Secretary:

Phone:

Mohamed Osman Mohamed Osman Office:

610-666-4648 Engineer PJM Interconnection Fax:

610-666-2296 PJM Interconnection 2621 Van Buren Ave.

Internet: osmanm@pjm.com 2621 Van Buren Ave.

Norristown, PA 19403 Norristown, PA 19403 Admin. Asst./Secretary:

Phone:

Wenzheng Qiu Wenzheng Qiu Office:

610-666-3155 Engineer PJM Interconnection Fax:

610-666.2296 PJM Interconnection 2621 Van Buren Ave.

Internet: qiuw@pjm.com 2621 Van Buren Ave.

Norristown, PA 19403 Norristown, PA 19403 Admin. Asst./Secretary:

Phone:

42411 2 of2 Page(s)

Revised:

2.7,2006 3:51 PM (ROS) SIS - SYSTEM INFORMATION SUBCOMMITTEE

ENCLOSURE (4)

PJM Manual 14B: PJM Region Transmission Planning Process, Section 2, Revision 12, Effective Date: 08/08/2008 Calvert Cliffs Nuclear Power Plant, Inc.

December 29, 2008

Working to RPerfect the Flow of -Energy

Manual 14B: PJM Region Transmission Planning, P 'rocess; Table of Contents PJM Manual 14B:

PJM, Region Transmission Planning Process Table of Contents I Table of Contents...................................................................................................

ii Table of Exhibits.........................................

I.........................................................

4 A pproval..........................................................

5 Current Revision....................................

......................... a.........................

........ 5 Introductio n.....................................................

o............ I ABOUT PJM MANUALS...

1 A BO UT T HIS M A N UA L..............

................................................................................... 1 In tended Audience......

R efere n ce s -.............................................................................

......... 2 U S ING T H IS M A N UA L...........................

2 OW hat -You W ill Find In This M anual.........

'3 ABOUT CRITIcAL ENERGY INFRASTRUCTURE INFORMATION (CEll)........................................... 3 PJM, Critical Energy Infrastructure Information Release Guidelines.........................

3 Section 1: Process Overview.....................................

I PLANNING PROCESS WORK FLOW..........................................................

1 TEAC AND-SUBREGIONAL RTEP COMMITrEEýAND RELATED ACTIVITIES..............

........................ 2 PLANNING.ASSUMPTIONS AND MODEL DEVELOPMENT...........

4

Reliability Plahning............

............................................. 4 Market Effiiency-Planning.......

4 RTEP PROCESS, KEY,C0MPONENTS:.-..... *...

..... o..,........,........

.......,.t..:*....

5 PLANNING CRITERIA.....

I.......

6 Reliability Planning........

6 Market Efficiency Planning........

0. 7 Section 2:,Regionai Transmission Expansion Plan Process.............................

8 TRANSMISSION PLANNING = RELIABILITY PLANNING + MARKET EFFICIENCY..........................

8...

8 THE R TE P PROCESS DRIVERS.............

10 RTEP RELIABILITY PLANNING..........,.................................

12

Establishing a Baseline........

12 Baseline R eliability Analysis 13 N eiar-Term Reliability Review....

................................................. 13

,Reference System Power Flow-Case........................

14

'Baseline 7:heqmal A.nalysis:

....................................... 14 Baseline Voltage:Analyslis.....

5.

Load D eliverability A nalysis..........

....... I........

1.........

15 Generation Deliverability Analysis...................

... 16

B aseline Stability A nalysis.....

17 Long Term R eliability I eview.

................... 17 Stakeholder re view of and input to Reliability Planning................................................................

18 RTEP INTEGRATES BASELINE ASSUMPTIONS, RELIABILITY UPGRADES AND REQUEST EVALUATIONS....... 20 RTEP COST RESPONSIBILITY FOR REQUIRED: ENHANCEMENTS........

.............. 21 RTEP M ARKET EFFICIENCY PLANNING..........................

...... ;.. 21

Manual 14B:. PJM Region Transmission Planning'Prcess Table of Contents Market Efficiency Analysis andStakeholde& Process............................

22 Determination:and evaluation of historical congestion drivers........................................ 22 Determination of projected congestion.drivers and potential remedies............

23 Evaluation of cost/benefitof advancing reliability projects........................24 Determinatiin and evaluation of cost/ benefit of potential RTEP projects specifically targeted for economic efficiency.....

24 Determination of final RTEP market efficiency upgrades..........................

25

.Submitting Alternative Proposals........................................

26 Ongoing,Reviewof Project Costs.........

........................................ 27 EVALU*AXiO OF PERATIIoNAL PERFORMANCE 'ISSUES........................

27 6-pe a on i P ro a c M e rC

... i.....i............ I....,.i...,........

~...,...i..........ii.......

i................ :27 Operational Performhance Metrics.

2 ProbabilisticRisk Assessment of PJM 500/230 kVTransformners...............

...................... 28 Attachment A: PJM Baseline Cost Allocation Procedures.................................

29 P U R PO S E.............................................................................................................................................

2 9 SCOPE.

29 SCHEDULE 12 CosT ALLOCATION PROCESS FOR BASELINE TRANSMISSION RELIABILITY AND MARKET EFFICIENCY UPGRADES...............................................................................................

... 29 R TEP Baseline Cost Allodation...........................

29 Attachment B:ý Regional Transmission Expansion Plan-Scope and'Procedure 32 P U R PO S E 3 2

,SCO PE

2.

32 PROCEDURE...................................

34

S C N i I !

N fG P o ' [UR.II..,:..::.:*,.. i.i:....... I....................................

..........I~........,38 SCENARIO`PL'A'NN IN G'PROC'ED'U'RE"...............

ý;.......3 Attachment C: PJM Deliverability Testing Methods............................................

40 INT R O D U C T IO IN,...............................................................................

.......... !............................... :.............4 0 DELIVERABILITY¥.METHODOLOGIES.....

40 OVERVIEW OF D ELIVERABILITY TO LOAD.......................

... 41I PJM LOAD'DELIVIERABILITY PROCEDURE[--CAPACITY EMERGENCY TRANSFER OBJECTIVE (CETO)....... 42 PJM LOAD DELIVERABILITY PROCEDURE-CAPACITY EMERGENCY TRANSFER LIMIT (CETL).............. 43 DELIVERABILITY OF GENERATION.................................

......................... 53 GENERATOR DELIVERABILITY PROCEDURE,..........................

.......... 1............... 54 Attachment D: PJMReliability Planning Criteria......

....... 58 Attac hmentD-1: Load Loss Definitions.

60 Attachment E: Market Efficiency Analysis Economic Benefit / Cost Ratio Threshold Test.....

....... 61 Total Annual Enhancem ent Benefit............................

61 TotalAnnual Enhancement Cost...........

63 PJM Manual 14B Revision History.....................................................................

64 PJM 0 2008 Revision 12;,Effective. Date: 08/08/2007

Manual 1.4B: PJM Region Transmission Plannihg'Process Section 2: Regional Transmission Expansion Plan Process.

c tip n2:2 Re gional iTansmission Expansion]P anProcessý In this section you will find an overview of the PJM Region transmission planning process, covering thefollowing areas:

Components of PJM's 15-Year planning The need and drivers fora regional transmission expansion plan Reiiability planning overview Specific components.f reliability planning and the, Stakeholder process Interconnection request drivers of RTEP Cost responsibilityfor. reliability related Upgrades Market efficiency planning review Specific components of market efficiency planning and the Stakeholder process.

O operational performance driven planning Specific. components of operational performance driven planning.

Transmnission Planning = Reliability Planning + Market Efficiency Effective'with the 2006 RTEP, PJM, after~stakeholder review and input, expanded its RTEP

,Process to extend the, horizon forconsideration of expansion or enhancement projects to fifteen years. This enables planningto anticipate longer lead time transmission needson a moretimelybasis.

Fundamentally, theBaseline reliability analysis underlies all planning analysis and recommendations. On this foundation, PJM's annual 15-year planning review now yields a regional plan that encompasses the following:

1T. Baseline:.reliability upgrades,, discussed in this.Section 2;

2. Generation 7and'transmission interconnection upgrades, discussed in Attachment C a6hd.Manua1 -14A.

3. Market efficiency driven upgradesdiscussed in this Section 2.

4. Operational performance issue driven. upgrades, discussed in this Section 2.

Exhibit 1,'shows the annual cycle of the 15-year RTEP process. This cycle integrates reliability and market efficiency analysis withinformation-transparency, stakeholder input and review and PJM Board of Manager approvals. This Cycle isdiscussed in detail in this and related manuals and attachments.. Activities shown on this diagram and their timing are

an, idealized view that will be. responsive to the RTEP and Stakeholder needs and thus may vary aiccordingly.

Revision 12, Effective-Date: 08/08/2008

Ma*ual 14B: PJM Region Transmission Planhinrg.Proces Section 2: Regional Transmission Expansion Plan Process Exhibit 1: PJM Annua! RTEPpianning tycle for 15-Year Plan This timeline represents the idealizedARTEP'process. At the, beginning of each RTEP cycle, PJM Will provide specifictimeine information for the Upcoming study cycle.

R E L-1A E31LtTY - mLA^NNINCG ubreQi.,rua RTriiP CotnmitL-initial as-Limpti.r~reth PJM% antnyr;is: nee~zr-tqrm relimbil-ity JI~i~,t~ikei~o~dr conrn cat~ri rexew~:cngoin~

IC EAQreview/inp~ut: riaiiy V

us~Lpgrzacie--

BiDNM rceicrw *9 krro-:rTEP rrdetiability plan ISMAR KET RIFFICZII~NIC' PLANNiNG tt-L~rrc-w-t RTRO weari.

j!PJMv:

Miarket effioiency iassurnptlons dlevelopmlent 1TEAC re\\,-iecw.'irput -rirý eI~

mtc

-2B IEýC40 revifewv arnd zipprn-v-,a: ma rket-effic~inn-y-23z~zumpticoni L24 analysis~: Ihistoric.I canesin projactilon c) Congestionw

'6 cnceptual solutionz PJM ;Arokyiý tfl4rt4~

i.ro-li~ibility upgrad.s-Oea dlný:Sakhiie vire

';o~iu~

PJMA arnalysis: new niarktji efifi viilv-ncy Seo~iutrc'n

30 TC cor Subrogio nal R rE7p Cdmarnitte c-_c-viftvv/lnput:mre

-4rTAC.

rc-,ie-w/irtput: rnarkeat rce-4 ciainad 4ty4c 3-2e TA meeoting corrmment pe-riod VfVIandC ZaPProval;O

RTE, n

'it iji rk lficEvrity plati

tH4, D..

J..l Fý-h

'Ma Ap, May% J U

J.

Am,,

54.iP Ovi H...

DM 4

4 44 4

4 0

44 4

4 0

4 4

4 4.4 4

4, 4

4 4

1

.4

'4 4

4 4

4 '

.4 4

4.

4 4 4

4

.4 4

4. 4 4

4 4

4 4#4 4

4 4

44 4

i.~O 4

4 4

.4 4

4 4

44 4

4 4

4

.4

.4 4

4 4

4 4.

-~

4 4

.14 4

4 4

4 I 4) 4 4~ 4 4

4 4

Manual 144B:.PJM Region Transmission Planning.Process Sectio 2d: Regional Transmisisioh. Expansion Plan Process The RTEP Process Drivers The continuing evolution and growth of-PJM's robust,and competitive regional markets rests on a foundation of bulk power system reliability, ensuring PJM's. ongoing ability to meet.

control area load-serving obligations. It also includes a commitment to enhance the robustness and competitiveness of Energy and Capacity markets by incorporating analysis and development.of market efficiency projects. Schedule 6 of the PJM Operating Agreement describeslthe PJM RTEP process, governing the means by which PJM coordinates the

.p.reparation of a plan for the enhancement, and expansion of the Transmission Facilities - on a reliable and environmentally sensitive basis and in full consideration of available economic

.and market.efficiency factors and alternatives - in order tomeet the demands for firm transmission service in the PJM regionh.PJM's:FERC-approved RTEP process preserves this foundation through independent ana lysis and recommendation, supported by broad

.stakeholder input and approval by an independent RTO Board in order to produce a single RTEP.

The PJM Region 'transmission planning process is driven by a number'of planning perspectives and inputs, including the following:

ReliabilityFirst Regional. Reliability Corporation2 (RFC) Reliability Assessment

-forward-1loking assessments performed'to assure compliance with NERC and applicable regional reliability corporation (ReliabilityFirst or SERC Reliability Corporation) reliability standards,, as appropriate.

SERO Reliability Corporation (SERC) Reliability Assessment P.JM AnnualReporton perationsý-:an assessment of the previous year's.

operational performance to assure that any bulk power system 'operational conditions which have emerged, e.g., congestion, are. adequately considered going forward.

PJM Load Serving Entity (LSE) capacity plans

' Generatorand Transmission Interconnection Requests -submitted by the developers of new generating sources and new Merchant Transmission Facilities, these requests seek interconnection in the PJM. Region (or seek needed enhancements as the result of increases in existing generating

'resources.)

t Transmission Owner and other stakeholder transmission development plans

° Interregional transmission development plans - the'transmission 'expansion

,plans of those powervsystems adjoining PJM, and in some cases, beyond.

° Long-termrFirm Transmission Service Requests.

Activities under the PJM c~ommittee.structure especially, the Planning Committee (PC), the.Transmission Expansion Advisory'Committee. (TEAC),

the'Subregional RTEP Committee, and local groups facilitated by. PJM within 2 ReliabilityFirst,. a7new regional reliability corporation under the North American Electric Reliability Corporation (NERC)', replaced three existing PJM-related reliability councils (ECAR, MAAC and MAIN) on January 1, 2006.

Manual 14B: PJM Region Transmission Planning Process Section 2: Regional Transmission Expansion Plan Process the TEAC established processes (seesection 1 "TEAC, Subregional RTEP Committee, and relate.d planning activities".)

PJM Development of Economic Transmission Enhancements based on Economic and Market Efficiency factors Operational performance assessments and reviews such as the aging Infrastructure Initiative - a Probabilistic Risk Assessment. of equipment that poses significant risk, to the Transmission. System.

The cumulative effect &f thesedriveirs is analyzed through the PJM 'Region transmission.

planniing process to develop a single" RTEP which.recommends specific transmission facility enhancements andexpansion on a reliable and environmentally sensitivebasis and. n full consideration of economic and market efficiency analyses See Attachment"B for details of the RTEP -' Scope.and Procedure.

NOTE:` The most recnt version f the PJM*R~ffk.ifr'9vaia~

PM Web site

.ýthttp://ww~w~ pi.cobmthlplain~gJr teqýr-ýhs-ekb-,.hnhtml These analyses are conducted on a continual basis, reflecting specific new customer needs as they are introduced, butalso readjusting as the needs of Transmission Customers and Developers change. One such RTEP baseline regional plan will be developed and approved each year Generation withdrawals have the potential'to impact study'resuIts for any mgeneratin nor merchant transmissionprojectthat doesn t an.executed

.Generation retirementswill not affect the,ýstudy resufor anygenertion or mrI erchanit trafismis~biopr(2je9t that has' received~an Irnpact.Study Report} ýJe_

Generationi reltirements icluded~i inte~rconnedi~onIproject studies w.ill be those announced as of the d~ate a project enters the intercon~nection queue.

In this way, the plan continually represents a reliable means.tomeet the power systemý requirements ofthe various Transmission.Customers and Interconnection Customers in a fully integrated fashion, at the same time preservingthe rightsof all parties with respect to thelTransmissionýSystem. The assurance of a reliable:TransmissionSystem and the protection of the"Transmission hCustomeri/Developer rights with respecttodthat :system coupled With the timely provision of information to stakeholders are the foundation principles of the OPJM transmhission pla'nning process.

The PJM Region transmission planning process also establishes the cost responsibility for the following types of facility enhancements as defined in the PJM Tariff:.

" Attachment Facilities Direct Assignment Facilities

" Network Upgrades (Directand Non-direct)

Local Upgrades Revision 12, Effective Date: 08/08/2008

Manual 14B: PJM Region Transmission Planning Process Section 2: Regional Transmission Expansion Plan Process:

-, Merchant Netwoerk,Upgrades Each RTEP encompasses a range of proposed power system enhancements: circuit breaker replacements to accommodate increased current interrupting duty cycles;; new capacitors to increase reactive power support; new lines, line reconductoring and new transformers to accommodate increased power flows; and, other circuit reconfigurations to accommodate power system changes as revealed by the drivers discussed above.

Requests for interconnection of new generators or transmission facilities, while not the sole drivers of the PJM Region transmission planning process, are a key component of the RTEP. Analyzing these'requests has requiredadoption of an approach that establishes baseline system improvements driven, by known inputs, followed by separate queue-defined, cluster-based impact study analyses. Overall' PJMWs RTEP process - under a FERC-approved RTO model - encompasses independent analysis, recommendation and approval to ensure that facility enhancements and cost responsibilities can be identified in a fair and non-discriminatory manner, free ofany market.sector's influence. All PJM market.

participants can be assured that the proposed RTEP was created on a level playing field.

RTEP Reliability Planning Establishing a Baseline In order-to establish a reference point for the annual development of the RTEP reliability analyses a 'baseline'.analysis-of system adequacy and-security is necessary. The purpose of this analysis is. threefold:

To identify areas where the systemn,.as planned, is not in compliance.with applicable NER Cand the applicable regional reliability council (ReliabilityFirst or SERC) standards, Nuclear Plant Licensee requirements and PJM reliability standards including equipment replacement and/or upgrade requirements.under PJM'sAging Infrastructure Initiative, The baseline system is analyzed using the same criteria and analysis methods that-are used:for assessing the impact of proposed new interconnection projects. This ensures that the need for system enhancements due to baseline, system requirements and those enhancements due-to new projects are-determined in a consistent and equitable manner.

To-develop and recommendjfacility enhancement plans, including cost estimates and estimated in-service dates, to bring-those areas into compliance..

Toesta~bish the baseline facilities and costs.for system reliability. This forms the baseline for determining facilities and expansion costs for interconnections to the:Transmission System that cause the need for facilities beyond those required for system reliability.

The system as planned to accommodate forecastdemand, 'comnmitted resources, and commitments for firm transmission service for a specified time frame is-tested for

.compliance with NERCOand the applicable regional r'eliability council (ReliabilityFirst or SERC) standards, Nuclear Plant Licensee reqUirements, PJIM Reliability Standards and:PJM design standards.. Areas not in compliance with the standardsoare identified and enhancement. plans to achieve compliance.are developed.

Revisibn 12, Effective Date: 08/08/2008

Manual 144B: PJM, Region Transmission Planning. Process Section 2: Regional Transmission Expansion Plan Process The baseline' analysis and the resulting expansion plansserve as the base system for conducting Feasibility Studies~for all proposed generation and/or merchant transmission facility. intefconnection projects and subsequentSystem Impact Studies.

Baseline ReliabilityAnalysis PJM's most.fundamental, responsibiity is to plan and operate:a safe and'reliable Transmission System that serves all-long term firm transmission uses onPa comparable and not unduly discriminatory basis. This~responsibility is addressed by P.JM.RTEP reliability planning. Reliability planning is a series of detailed.analyses that ensure reliability under the most stringent of the applicable NERC, PJM or local criteria. To accomplish this. each year, the RTEP cycle extends'and updates the transmission expansion planwith a 15 year review This cycle entails'several steps. The folowing sectionhsdescribe each step's assumptions, process and criteria. Attachments.A through G of this manual add essential details of various aspects of the reliability planning process.

Reliability planning involves a neai-term and a longer term review. The near terr analysis is applicable for the current year through the current year plus 5. The longer term view is applicable for the current year plus.6 through plus. 15. Each review entails multiple analysis steps subject to: the specificcriteria that depend on the specific facilities and the type of analysis being performed.

The analysis is initiated in December prior to each annual cycle. and concludes with review by theJTEAC and approval.by the PJM Board about October (TEAC and the PJM Board are apipraised; regu larly throughout the process and partial reviews and approvals of the plan may occur throughout the year.)JThe TEAC,:Subregional RTEPand.PJM Planning, Committee roles-in the developmeht of the reliability portion of the RTEP are described in Schedule 6 of the:PJM operating Agreement.

Near-Term Reli ability Review The near-term reliab lity review,(current year plus.5) provides reinforcement for criteria violations that are revealed.by 6pplicable contingency analysis. System conditions'reviealed as near violations will bermonitored and remedied. as needed in th6efollowing year~near-term analysis. Violations that occur in many deliverability areas or severe violations in any one area will bereferredto, the long term analysis for added study of possible more robust system enhancement. PJM annually conducts this detailed review of the current-year plus 5.

Each year :of the period through thecurrent year plus4 ("in-c lose years) has been, the subjectof previous years" detailed analyses. ln~addition, for each 6f these,"in-close" years, PJM uP dates and issues addendum to address changes as necessary throughout thfe year.

For examople planned generation modificationsor Changes in transmission topology can*

trigger restud*y and.the issuance :of abaseline addendum. This islreferred to~asýa "retool" study. (For example generators that drop from the Q's cause restudy andan addendurnto be issued for affe, cted baseline analyses.) Also each year. during the establishment of'the assumptions for the :new annual baseline analysis, current updated views of load,'

transmission topology, installed generation, and generation and transmission maintenance are assessed for-thei"in-close"* range of years tovalidate the continued applicability of each of the "in-close : baseline analyses and resulting upgrades (including any addendum.)

Adjustments in the."in-cl6se" analyses are performed as deemed necessary, by PJM. PJM,

Revision 12, EffectiveDate: 0810812008

Manuai 148. PJM Region TransmissionPfan'nlng Process Section 2: Regional Transmission Expansion.Plan Process adjustments to. analyses. All criteria thermral and voltage violations resulting from the near term analysesare produced using solved AC power flow solutions. Initial massive contingency screening may use DC.power flow solution techniques.

There areseVen :stepls in an annual near-term reliability review. They are:

Develop a Reference System PowerFlow Case Baseline Thermal Baseline Voltage Load Deliyerability - Thermal Load Deliverability - Voltage, Generation Deliverability - Thermal Baseline Stability These reliability related steps are followed -by a scenario analysis that ensures the robustnessof the plan by looking at impacts of variations in key parameters selected by PJM. Each of these steps are'described in more detail in the following material Reference System Power Flow Case The reference.power flow~case and the analysis techniques :comprise the full set of analysis assumriptions:and parameters for reliability analysis. Each case is developed from the most recent set of Eastern Reliability Assessment Group system models. PJM transmission planning revises this model, asneeded to incorporate all of the current system parameters and assumptions. These assumptions include current loads, installed generating capacity, transmission and generation maintenance, system'topology, and firm transactions. These

'assuumptionswill be provided to and reviewed bythe Subregional RTEP Committee. The subregionalmodeling reviewand. modeling. assumptions meeting provides the opportunity for:stakeholdersto review and provide inputto the development -of the reference power

systemrmodels:used to perform the; reliability analyses.

The results-of any locational capacity market -auction(s) will be.used to help determine the

'amountfand l.ocation of:generatiOn or demand side resourcesto: be included in the reliability modeling. Generation or demand side resourcesthat are cleared in any locational capacity marketauction will.be.included'in the reliability modeling, and generation or demand side resources that~either do not bid or do not: clear in any locational capacity market auction will not be included in-the reliability modeling. All such modeling.described here, will comport With the capacity construct provisions approved by the FERC.

Subsequent to the subregional stakeholder modeling reviews facilitated by PJM, PJM will developthe final set of reliability assumptions to be presented to TEAC for review and comment;, after which PJM will finalize the reliability review reference power flow. This model is~expected to be-available in early Januaryof each year to ihterested stakeholders, subject to applicable confidentiality and CEll requirements, to facilitate their review of the results of

.the, reliabilitymodeling analyses.

Baseline Thermal Analysis Baseline thermal analysis is a thorough ýanalysis of the reference power flow to ensure thermal adequacy based on normal (applicableto system normal.co0 nditions prior to PJM©,2008 14 Revisioh 1'2, Effective Date: 08108/2005

Manual 14B: PJM Region Transmission Planning Process Section 2: Regional Transmission Expansion Plan Process contingencies) and emergency (applicable after the occurrence of a contingency) ratings specific to the'Transmission Owner facilities being examined. It is based on a 50/50 load

ýforecast froqm the laies!t-available.'PJM Load Forecast Report.(50% probability,that the actual load is higher orlower than the projected load.) lt-encompasses-an exhaustive analysis of all NERC category A, B and, C events and-themost critical common mode outages. Final results. are supported. with AC power flow solutions.

For normal conditions, all facilitiesshall be loaded within their normal ratings. After each single contingency, all control equipment is allowed to adjust. After the first contingency of a multipleýcontingency event (NERC category, C.3, also referred to as an "N-1-1" event,) all system adjustments are made to achieve a new steady state power-flow; including redispatch'in preparation for the next contingency. Subsequent to redispatch all facilities must be-within normal ratings; Afterthe second -contin.gency-of-the pair the technique.for single contingencies is followed except.that phaseshifters are.locked and do not adjust to, hold flow. AIIviolations of emergency ratings are recorded and reported and tentative

.solutions will be developed. These study results Will be presented toand reviewed with stakeholders.

Baseline Voltage Analysis-Baseline.voltage analysis parallels the thermal analysis. It uses the same power flow and examines all the same NERC category A and B events. Baseline voltage analysis does not examine categoryC or common mode outages. Also, voltage criteria are examined for compliance. PJM examines system performance for both a voltage drop criteria andan absolute voltage criteria. The voltage-drop is calculated as the, decrease in bus voltage from the initial. steady state, power flowto the post-contingency power flow. The. post-contingency poWer flow is.s6lved with generators".holding a local generator bus voltage.toa prev-cobntingency-level consistent with specific Transmission Ownerspecifications. In most instances this is.the preocontingehby generator bus Voltage Additionally, all phase shifters, transformer taps, switched shunts, and DC lines are locked for the-post-contingency solution: SVC's'are allowed to regulate.

The absolUtevoltage criteria isexamined.for:the same contingency set by.allowing transformer taps, switched shunts -and:SV.C's to regulate, locking phase-shifters and allowingsgenerators to hold steady state'voltage criteria. (generally aný agreed upon voltage on the, high Voltage bus at the generator location.)

In all instances, specific Transmission Owner voltageý criteria are obser ved. All violations are,

,recorded and reported and tentatiye-:solutions:will be developed. These study resjlts will be presented to and reviewed with stakeholders.

Load Deliverability Analysis The load deiverability tests are.a unique set of analyses designed to ensure that-the Transmission System provides a comparable transmission function throughout.the-systern.

These tests ensure that the Transmission System is adequate to deliver each load area's requirementsfrom the aggregate-of. system generation. The tests develop an "expected value" of-loading after testing an extensive-array of probabilistic dispatchesto determine thermal limits. A deterministic dispatch method is'used to create imports for the voltage criteria test. TheTransmission System reliability criterion used is 1 event of failure in 25 PJM.©C2008'"

15 Revisionl 2, Effective Date.08/08/2008

Manual 14B: PJM Region Transmission Planning Process Section,2: Regional Transmission Expansion Plan Process years. This is intended to design transmission so. that it is not more limiting than the generation system which is planned toea reliability criterion of 1 failureevent in' 10years.

Each load areas' deliverability target transfer level'to achieve the transmission. reliability criterion is. separately developed using a probabilistic modeling of the loadand generation system. The load deliverability tests described here measure the design transfer level supported by the Transmission System for comparison to the target transfer level.

Transmission upgrades are specified by PJM to achieve the target transfer level as necessary. Details of the load deliverability procedure can be found in Attachment.C.

Thermal This test examines the deliverability under the stressed conditions of a 90/10 summer load forecast' That is,a forecast that only has:a 10% chance of being exceeded. The transfer limit tothe load is determined for system normal andall

,single contingencies (NERC category Aand B criteria) under ten thousand load study.area dispatches with calcUlated probabilitiesof occurrence. The dispatches are developed: randomly based on. the availability data for each generating unit..This results in an expectedvalue:of system transfer capability that is compared to'the target level.to determine system adequacy. As* with allthermal transmission, tests applied by PJM the applicable Transmission Owner normal and emergency ratings are applied, The steady state and single contingency power flows are. solved c'onsistent.with the similar solutions described for the baseline thermal analyses.

Voltage This:,testing procedure is.similar to the thermal load deliverability test except that*

voltage~criteria are evaluated andthat a deterministic dispatch procedure is used to increase study area imports'. The voltagpe1tests and criteria are the same as those performed for the. baseline voltage.analyse~s.

Generation Deliverability Analysis The generator deliverability testfor the reliability analysis ensures that, consistent with the load deliverability single contingency testing procedure, the Transmission System is capable of delivering the aggregate system generating capacity at peak load with all firm transmission uses modeled. The procedure ensures sufficient transmission capability in all areas of the. system.to export an arnountof generation capacity at least equal to the amount of certified capacity resources in each "area". Areas, as referred to in the. generation deliverability test, are unique to each study and depend.on the electrical system characteristics thatr may limit transfer. of capacity resources. For g efieratordeliverabiity areas, are, defined with respect to each.transmission element thatrmay limit transfer of the aggregate'of certified installed6generating capacity. The cluster of generators with significant impacts on the potentially limiting element is the "area" for that element.. The starting point power flow.is'the same power flow case set, up for the baseline analysis. Thus the same baseline loadand ratings criteria'apply. As already mentioned the same contingencies used for load deliverability apply and the same single contingency power flow solution techniques also apply. Detail,6f :the generation deliverability procedure, can be.found in AttachmentC.

One additional.step is applied after generation deliverability isensured consistent with the load deliverability tests. The additional step.is required bysystern reliability criteria that call for adequate and. secure.transmission dur ng~certain NERO' category C common modeý PJM © 2008 16 Revision, 12, Effective Date: 08/08/2008

Manual 14B: PJM Region Transmission Planning Process Section 2: Regional Transmission Expansion Plan Process outages. The procedure mirrors the generator deliverability, procedure with somewhat lower deliverabiity requirements consistent with the increased severity of the contingencies, The:detailsof the generator deliverabilitý procedure including methods of creating the-study dispatch can be found in Attachment C.

Baseline Stability Analysis PJM'ensures generator and system stability during its interconnection studies for each new generator. In, addition, PJM annually performs stability analysis for approximately one third of"the existing generators on the system. Analysis is performed on the RTEP baseline power

'flow.. These analyses ensure the system is transienitly stable andthat all system oscillations display positive damping, Generator stability is performed for critical systemconditions, which includes light load and three phase faults with normal clearing plus single line to.

ground: faults with-delayed clearing. Also, specific-Transmission owner designated faults'are examined for-plants on their respective systems,

{PJM IS CURRENTLY EVALUATING STABILITYANALYSIS NEEDS RELATED TO RFC

,CRITERIA. ANY REVISIONS OR ADDITIONS, TORTEP STABILITY ASSESSMENTS WILL BE, INCLUDED HERE: AS THAT REVIEW PROGRESSES AND WILL BE PRESENTED THROUGH THE APPROPRIA TE PJM MANUAL REVIEW PROCESS.)

Finally, PJM will initiate special stability studies as the need arises. The impetus for such special studies commonly includes but is not limited to conditions arising from operational performance reviews or major equipment outages.

Long Term Reliability Review The PJM RTEP reliability review process examines the longer term planning horizon using a currentyear plUs 15 p(wer flow model and ac'urrent year plus 10 power flow model.

Assumptions and model developmeintregarding this longer term view will be'presented and reviewed and stakeholder input will be. considered in the same process used for the near-term review. The longer term view of system reliability is subject to, increased uncertainty due to:the increased'likelihood of changesin theanalysisastime progresses. The purpose of the:long'.term reviewis~to anticipatefsystem trends which may require longerlead time solutions.. This enables PJM to take appropriate action when system issues. may require; initiation during.the near term horizon in anticipation of potential violations in the longer term.

System issues, uncovered that are amenable to shorter lead'time remedies will be addressed as,they enter into the near-term horizon.

CurrentYear Plus 15!Analysisý The. Longer term reliability review involving single and multiple contingency analyses is coInducted to, detect system conditions which may need a6,solution With a lead-timfie to operation exceeding five yea rs. Two processes will be used as indicators; to determine* the need for contingency analysis in the longer term horizon. The.first is a review of 'the near-term results to detect.violations that' occur for multiple deliverability areas or multiple or severe violations clustered in a one area of the system. This review may suggest larger projects to.collectively address groups of violations. The second.is a thermal analysis including double circuit tower outages at voltages. exceeding 100 kV performed on the current year plus fifteen system. All of the current year plus fifteen results produced will be PJM ©20080 &

17 Revision 12, Effective Date:-08I08/2008

Manual 144B: PJM Region Transmission Planning Process Section 2: Regional Transmission Expansion Plan Process reviewed to determine if any issues may require longer leadtime solutions, If so such solutions:,will be determined and considered for inclusion: in RTEP.

This. valuation of the. need for longer lead time solutions, considers that the NERO category C results.may employ load shedding'and/or curtailment of firm transactions to ease potential violations. Also this review considers that the current year plus fifteen planning horizon exceeds-the required NERC planning horizon. The main effect of this extension to 15 years is toexamine a load level that is significantly higher than the base forecast.year-ten planning load level. This.year fifteen analysis, therefore, captures the equivalent'(in a 10-year horizon) of a higher load forecast plus weather sensitivity. To the extent that this long term reliability thermal review indicates marginal system conditions-that may-require a longerlead iimessoIlUtion, PJM will under take additional longer term"analyses as may be needed.

The long term deliverability analyses followa similar pattern to the near-term load and generation deliverability analyses.. The long term, however relies solely on. linear DC analysis-whereas all near term violations-result from analysis solutions that rely on the full AC power flow. Theload deliverability case is set up for a 90/10 load level and the, generation deliverability case is'set up.for'a 50/50 load level' Generation dispatchesare determined consistent" with'the'. methods for the near term analyses. The.analysis for the longer term horizon evaluates'all NERC -category A and rB single contingencies, againstthe same normal and emergency thermal ratings criteria used for the near term (subject to any upgrades.that may-be applicable for the.longer'term.)

Reactive Analysis' In addition, the longer term, reviewincludes a curront year pluslO reactive analysis. This focuseson contingencies, involving, facilities above 200 kV in. areas where thepreceding year-15i analysis uncovered thermal violations. Areas experiencing, thermal Violations ýthat also show earlier reactive6deficiencieswill be reviewed for possible accelerat0ionof anyý loniger lead timethermal solUtions'that-were suggested by the year-15 analysis. This analysis, as necessary from yearto year. Will also.consider:.long-term upgrade: sensitivity to key yariables such as load power'factor delivered from.the TrahsmissionSystem orheavy transfers.AIf uncovered violationS a-re insuffiientJt justify acceleration. of upgrades and are!

all amenable. to shorter lead-time upgrades, then the violations will continue to be monitored in future,RTEP analyses.

Stakeholder review of and input to, Reliability Planning RTEPreliability, planning, through the operation of the TEAC and Subregional RTEP Committees,, provides;interested partieswith theopportunity to review and provide meaningful and timely input~to all phases of the reliability planning analyses. This section extends'theSection 1 discussion of theTEAC and Subregional.RTEP Committee process specifically asit relatesltoreliability planning. Exhibit 1 shows the workflow and timing'for the reliability planning process-steps. PJM anticipates at least two Subregional RTEP Committee reliabilityrreviews. Theinitial subregional meeting will present and address reliability study assumptions and parameters. The second meeting will providethe:

opportunity forstakeholder comment and input on criteria violations'and presentations of alternative remedies.to:identified violations. Between the two meetings PJM will provide feedback on interim study progress sufficient to enable stakeholder preparation forthe second set of subregional meetings. Additionalsubregional meetings will be facilitated as PJM ©@2008 18 Revision 12,.Effectiveoate:08/08/2008

Manual 14B: PJM Region Transmission Planning Process Section 2: Regional Transmission Expansion Plan Process PJM: determines is necessary for adequate input and review. The relative timing of the TEAC.Iand,.subregional activities are illustrated, in Exhibit 1..

Subregqional RTEP Committee initial assumptions meetinq This meeting is expected to occur in December of each year in preparation for the upcoming annual RTEP review. Prior to.the meeting PJM will post its anticipated inputs and assufmptions to enable stakeholder review and preparation for the meeting. At the meeting PJM will present the assumptions for discussion and input by all interested parties.

Subsequent to.this meeting stakeholders will have additional opportunity to. provide input to PJM.in preparation.for the next TEAC meeting, at which PJM will present the final reliability assumptions-for TEAC review. Although the initial.Subregional assumptions meeting will discuss anticipated assumptions forboth.the reliability and market efficiency phase of the RTEPi The.finalTEAQ. review of each will likely occur at separateJTEAC meeti.ngs,(see also the market efficiency. discussion'folloWing) The TEAC endorsement. offinal RTEP reliability assUmptions'is expected to occur in early January.

PJM development of criteria: violations and :stakeholder participation After the TEAC endorsement of PJM's RTEP analysis assumptions, PJM will finalize its reference:system power flow which is the starting point of its series of reliability analyses.

This power flow is available to stakeholders subject to applicable confidentiality and CEll requirements. PJM will perform its series of detailed RTEP reliability analyses encompassing the 15-year planning horizon. Details of the methods and procedures for the reliabilityanalyses can be found elsewhere in this Manual 14B and its attachments. The five-year:and longer time-frame criteria violations will be posted for~review, evaluation and developmeht of remedy, alternatives by all interested parties. The PJM productionof the reliability..analysis raw results is expected to occur about January through July of each year. Posting of the-results and, statkeholder review and considerationof.altemative rem ediesis expeqted-to occur about February through August of each year. PJM will post TO and other stakeholder alternative upgrade remedies made available throughout this process. Throughout this time~frame, TEAC typically has monthly or more frequent regularly scheduled meetings. PJM will periodically apprise TEAC:of the progress of the violations identification and production of upgrade alternatives. Stakeholders may use these meetings to raise and discuss issues found in their reviews. Depending on the issues raised'and input frombstakeholders PJM may.facilitate Subregional RTEP Committee meetings. insteadof or in addition to ascheduled TEAC meeting. These; subregional meetingsý.areJntended for more ?fojused review of subregional Violations. and alternative. solutions.

Subregional RTEP Committee criteria violations and up-grade alternatiVenmeeting This meeting is.expected to occur, as may be necessary in various subregiolns, inrthe July.I Augusttimeframe each year. If a subregional meeting is unnecessaty, theregularly scheduledTEAC;*meetings will provide the opportunity for that subregion's participants-open discussion:of violations and upgrades. In any event, all regional and subregional projects will be.appropriately presented and reviewed at a TEAC meeting. Prior to a subregional violations and upgrade meeting, PJM willpost the upgradesolutions, that it proposes to remedy the identified criteria violations. At this subregional meeting PJM will present the reliability.upgrades of specificviolationsandalternative upgrades as may be appropriate. By this Subregional RTEP Committee meeting, interested parties will have had the opportunity for ongoing participation in the February through August process of violation review and solution identification alorig'with PJM and Transmission Owners. This subregional criteria PJM &2008...

19 Revision 12, Effective Date: 08/08/2008

Manual 141: PJM Region Transmission Planning Process Sectioh,2:; Regional Transmission Expansion Plan'Process violations and upgrade. meeting is the forum for a final open discussion of thesubregional reviews which have been occurring, priorto, presentation to TEAC.

PJM TEAC Committee IRTEP review PJM expects that about August of each year, the final RTEP upgradeffaciiities will be available'for presentation, r'evieW and endorsement at a scheduled TEAC meeting. PJM will post its recommendations'of RTEP Upgrades for identified Violations as early as possible in the month prior to the TEAC meeting at which the'final RTEP facilities will be reviewed (see RTEPL*.pjm.com.') This posting, will distinguish facilities that are deemed Supplemental RTEP Projects. After the TEAC RTEP review meeting, there will be about a rmionth of additional time for finalwritten comments, on the proposed RTEP facilities, after which the PJM Board will consider the final RTEP plan excluding Supplemental Projects for approval.

RTEP integrates Baseline Assumptions, Reliability Upgrades and Request Evaluations

,PiJMs' robust energy market has' attracted numerous requests from generator and transmission developers for interconnections with-the Transmission System. These generator and transmission Interconnection Requests constitute a significant driver, of regional transmission expansion needs: This subsection discusses this-driver in'the context of the RTEP preparation. Details.of this process are contained in Manual 14A.

Requests for Long Term Firm Transmission Service and generator deactivations-are other types of request that are evaluated and incorporated into RTEP.

Demahd Response (DR) tan be a load response solution to the. need for transmission upgrades. DR.solutions enter the PJM process in.the Reliability Pricing Model (RPM)

'throughjthe associated base residualand incremental auctions. The DR cleared in the

'auctioh is included in the assurmptions.for RTEP development and physically modeled in the baseline povwer flows. In this~manner, load can 'mitigate or delay the~need for RTEP upgrades.

'The RTEP process' baseline analyses include previously processed generators and transmission modifications.as starting point assumptions. The current year RTEP evaluations performed on this baseline case are incremental to the baseline: and establish a

.revised" baseline for the yearof the annual RTEP analysis. This revised baseline formsthe starting case for the reviews of new interconnection requests. The hew interconnection request analyses result in system, modifications beyond RTEP upgrades that are caused by each interconnection request. New interconnection request evaluations also include a review of their effects on newly approved RTEP upgrades.that are not yet committed,'t0 construction. If previously identified RTEP upgrades can be delayed because of a new interconnection request, the projects responsible for the upgrade deferrals, will be credited for the benefits' of~the delayed need' for the upgrades.

The RTEP integrates reliability upgrades, interconnection request upgrades and plan modifications and. DR effects into asingle process thatiaccounts for the mutual ihteractior of the various market forces. In thisway, transmission upgrades, interconnection requests and DR receive comparable treatment with respect to their opportunity to-relieve transmission constraints.

Manual 14B: PJM Region Transmission. Planning Process Section 2: Regional Transmission Expansion Plan Process Timing of Long-Term Firm Transmission Service. Requests, and Generation and Transmission Interconnection Requests are based on the business needs of-the party requesting the service. Such Requests, therefore, enter the RTEP planning process throughputlthe RTEP planning year.. Expansion plans that result fromrthese individual project~evaluations aweincorporated into the RTEP after the system impactstudy stage. In addition, if needed,,to satisfy assumed planning reserve requirements for future planning yearanalyses,queue generators in earlier stagesof thequeue process may also be included. Only the queue generators with completed signed lnterconnection Service Agreements, however, are allowed to be used 'to alleviate constraints.

This, manual contains the details regarding the. RTEP reliability planning process:

procedures., Refer to the introductory Manual 14 for references to the detailsassociated with other elements of-RTEP including the request and RPM processes.

RTEP Qost Responsibility; for Required Enhancements The RTEP encompasses.two, types ofenhancements: Network Reinforcements and Direct Connection Attachment Facilities,. ýNetwork Reinforcements can be required, in order to accommodate-the.interconnection of a merchant project (generation or transmission) or to eliminate a Baseline problem asa result of system~changes such as load growth, known transmission owner, facility-additions, etc.:Merchant project driven upgrades are addressed in Manual 14A. The cost.responsibility for each, baseline-revealed Network Reinforcement is borne by transmission'owners based on thecontribution tothe need for the network reinforcement. Suchcosts are recoverable by each transmission owner through FERC-filed transmission serviCe rates. Network reinforcements may also be proposed by PJM to m-itigate unhedgeable c0ngestion.,Allocation procedures for Baseline and Market Efficiency upgrades are discussed in Attachment'A.

Overall,the RTEP is best understood from the perspective of theý studies that revealed the recommended Plan enhancements. To that end, the Baseline Analysis and Impact Studies identify. the, enhancements required to, meet defined NERC and app!icable regional reliability

.council (Reliability First or VACAR/SERG) standards, Nuclear Plant Licensee requirements and PJM reliability standads,.

RTEP Market EfficiencyPlanning Market efficiency analysis is-performed as partoftheoverall PJM Regional Transmission Expansion Planning (RTEP) process to, accomplish the following two objectives:

1. Determine-which reliability upgrades, if any, have an economic benefit if accelerated.

I2 dentify new transmission, upgrades that may'result in economic benefits.

PJM, Will perform a market-efficiencyý analysis each' year, following the aVailability of the appropriate updated RTEP power flow resulting from thei reliability analysis process. As a result;, there is a mechanism ihn place for regularly identifying transmis0sion enhancements,0r expansionsý that will relievetransmission reliability violations that also have an, economic impact. Constraints that have an economic impact include, 'but are not limited to, constraints that cause: (1) significant historicallgross congestion; (2) significant historical unhedgeable congestion; (3) pro-ration of Stage 1B ARR; or (4) significant future congestion as forecast in the market effiCiency:analysis.

Manual 14B: PJM Region Transmission Planning Process Section 2:- Regional Transmission Expansion Plan Process In the marketefficiency analysis, PJM will.compare the costsand benefits of the economic-based transmission improvements. To calculate the benefits of.these potential economic-based enhancements;, PJM will perform and compare market simulations with and without the proposed'accelerated reliability-based enhancements..or the newly proposed economic-based enhancementsfor selected future years within the planning horizon of the RTEP., The relative benefits and costs of the economic-basedenhancement or expansion must meet the benefit/cost ratio threshold test to be included in the RTEP recommendelto-the PJIM Board of Managers for approval (This testand its implementation is described in detail in Attachment E.) PJM will also consider potential individual plans meeting: objectives 1 or 2 resulting from the analyses of the posted congestion data by all stakeholders. PJM will present'al 1the RTEP market efficiency enhancements to the TEAC Committee for review, comment andendorsement. Subsequent to TEAC review, PJM will address the.TEAC review and present the final, RTEP market efficiency plan to the PJM Board, along with the advice, comments'i and recommendations of the TEAC Committee, for Board, approval.

Market Efficiency Analysis and Stakeholder Process PJMs market efficiency analysis involves several phases. The process begins with the, determination Of the congestion driversthat maysignal market inefficiencies. PJM will collect and publicly post relevant drivers. These metrics will be reviewed by PJM and all stakeholders to assess the system areas that are most likely candidates for market efficienicy upgrades. In addition, PJM will perform market simulations to determine projections of future market congestion based on the anticipated RTEP upgraded system.

This process facilitates concurrent'PFM and stakeholder review of the same information considered by PJM in preparationmfor PJM' ssolicitation of stakeholder inputfor upgrades that may-economically alleviate, market inefficiencies. This s0licitati6n:of-inputwill be to the.

appropriate TEACor Subregional RTEP. Committee. Following the-evaluation of congestion drivers and solicitation of:remedies, PJM will initiate an analysis phase which'first examines*

the-potential economic costs and benefits-that may be asspciated'with any upgrades specified during the reliability analysis. After this'assessment, PJM will evaluate the economic costs and benefits of any identified new potential upgrades targetspecifically atý economic"efficiency. The following information looks at each of thesephasesin more detail.

Determination and evaluation of historical congestion drivers All PJM metrics of historical congestion drivers will be posted monthly throughout the year, except that AAR information will be posted as specified by the AAR auction process. This information can be found at:

(http:I/www:pim~com/pianninci/epis.html)

PJM will cal*clate-and rost.gross congestion ýcosts by constraint for each constraint causing real-time off-cost oper'ations. Gross congestion will be calculated as the product-of the constraint;shadow price'times the load MWs at each load bus in the affected-area.times the load bus dfax where the affected area is defined as any-buswith a dfax of 3% or greater.

PJM will calculate and post the-Unhedgeabie congestion cost statistics and associated con'straints. Unhedgeable congestion costs will be calculated by taking the sum of load MWs at-each load bus in the affected area times the relevant load bus dfax minus the sum-of

,economicgeneration MWs at each-generator bus in the affected area times the relevant generatorbus dfaxrminus the sum of FTR MWs, and multiplying the resulting MW by the PJM @20081ý 22 Revision 12, Effective, Dat: 08/08/2008

Manual 14B:. PJM Region Transmission Planning Process Section 2: RegionalTransmission Expansion Plan Process constraint shadowprice; Economic generation is generation which is available and on-line and which, at its current level of output, has a bid price no greater than the PJM system marginal price. Self-scheduled generation',is assigneda bid-price of zero in the determination of economic generation MW.

Congestion causing a pro-ration of Stage 1IA ARR requests will be determined and recommended for inclusion in the RTEP with a recommended in-service date based on the 10-year Stage IA simultaneous. feasibility analysis results. This recommendation will also, include a highlevel analysis of the cost and economic benefits of the upgrade as additional information but such upgrades will not be subject to. market efficiency cost/benefit, analysis.

More information on the ARRallocation auction process can be found in Manual 6titled PJM Capacity Market.

Congestion, causing.pro-ration of Stage 1 BARR requests willbe addressed using. the "With and without" analysis and the.benefit/cost ratio threshold described previously in this market efficiency material.

Determinationof projected congestion drivers and potential remedies PJM Will provide all stakeholders with ;estimates of the projected congestion by performing annual hourly market simulations offuture years using a commercially available market.

analysis software modeling tool (see.assumptions.and criteria material in Section 1.) This simulation Wil!.,produce and PJM will post projected binding constraints, binding hours, average economic impact of binding constraints, and cumulative economic impact of binding constraints..for the four RTEP market efficiency analyses (current year plus 1, current year plus 4, current year plus 7 and current year plu.s 12.)

This analysis is expected to be completed about the thirdquarter of the RTEP cycle year.

At Ithis time PJM.willalso facilitate a TEAC or.Subregional RTEP Committee meeting, as appropriate, to review congestion'and solicit feedback from'the stakeholders' review of the projected congestion data as well as the historical congestion data. All stakeholders can provide.input to PJM's consideration of the congestion data and potential upgrades to be considered for market efficiency solutions to identified, economic issues, The timing. ofthis meeting will depend, to some extent, on the complexity of the analysis, however, it is anticipated thatthis meeting will/occur during the third quarter of each year.

At this.meeting, PJM Will provide a summary of theanalysis results and a description of any congested areasthat will be analyzed using Market Effidiency analysis. PJM will also provide a high-level estimate of the transmission upgrades then being'Iconsidered. Atthe completion of this stakeholder reviewi any meinmbervof the:TEACcan provide additional written. comments within sixty (60) days of this meeting.

StakeholderWritten Comments these:written comments will consist of three (3) sections:

e Introduction, which Will describe the party submitting the comments and their reason for submitting these.comments o Summary, which will consist of no more than 3 pages summarizing the positions described in the written comments Discussion, which will consist Of no more than 20 pages describing in detail

23 Revision, 12, Effective,Date: 08/,08/08

Manual 14B: PJM Region Transmission Planning Process.

Section 2: Regional Transmission Expansion Plan 'Process Parties wishing formally to-submitialternative proposalsofltheir own-are encouraged to do so separately,, as described further, below.

TheOffice of the Interconnection will have the responsibility of compiling comments from TEAC participants. All written comments will be posted to the PJM web site and provided to the PJM Board of Managers together with a PJM staff summary that will focus on conveying the following: (1) theissues; (2) the parties raising the issues; and, (3) as may be appropriate, PJM's discussion of ramifications of the issues, Communication to the Board of Managers will not include results ofany voting.

Evaluation-of costl benefit of advancing reliability projects PJM will per-form:annual market, simulations and produce cost / benefit analysis of advancing reliability projects. An initial set of simulations will' be conducted for each of the four'years (current year plus 1, current year plus 4, :current yearplus.7 and current year plus

10) -Using the "as is",tran'smissionnetwork topology without modeling future RTEP upgrades.

A seconid set 0f:simulationswill be conducted for each of the. four years using the as planned"RTEP upgrades. Acornparison of the "as is' and, "as planned" simulations will identify constraints which have:caused significant historical or simulated congestion costs but for which an as-planned upgrade will eliminate or relieve the 'congestion costs to the point' that the constraint is no.longer an economic concern. A comparison of these simulations will also reveal if a particular'RTEP upgrade is a candidate for acceleration or expansion. Forexample, if a constraint causes, significant congestion in year 7 but not in year 10 then the upgrade whi cheliminates this congestion in the year 1'0 simulation may be a candidate for'acceleration. The benefit.of accelerating this upgrade would then be compared to'the'rcost of, acceleration as described belowbefore recommendation for acc1eeration is made.

When the, reliability-project'economic acceleration analyses haVebeen completed, PM will schedule a TEAC or SubregiOnal Committee meeting, as appropriate, to review the.results.

The timing of this meeting will depend, to some extent; on the amount and complexity of analysis that mustr be performed. However, it is anticipated that this meeting will take place during the fOurth quarter of each year. At this meeting PJM will provide a summary of the analysis results; including an-update.,of the Market Efficiency analysis and a description of any recommendationsfor accelerating reliability projects based on economic considerations.

Determination and evaluation.of cost / benefit of potential RTEP projects specifically targeted for economic efficiency PJM will perform annual market simulations and 'produce cost / benefit analysis of projects specifically targeted.for econpmic efficiency. 'The net present value of arnual benefits will~be calculaied for thefirst 15year, of upgrade life and compared to the net present value of the upgrade revenue requirement for the same-5'year period..

An initial set of simulations will be conducted for each of four years (current'year plus 1, current:year plus 4, current year plus 7 and-current year plus'10)using the as planned transmission network.topology as defined by the most recent RTEP. A secondsetof simulations will be-conducted for each of the fouryears using the as planned transmission network:topology plus the, upgrade being:studied. Theupgrade will be included in each of the four simulation years regardless of the actual anticipated in-service date of the upgrade.

AXcomparison ofthese'simulations.will-identify the benefit of the upgrade inmeach of the four PJM 0 2008 24 Revision 12,ý.

Effective Date: 08/08/2008

ManUal 14B: PJMRegion Transmission Planning Process Section:2:' Regional Transmission Expansion Plan Process years analyzed. Annual benefits withinthe 10-year time frame for years which were not simulated would.be interpolated using these simulation results. A forecast of annual benefits for years' beyond the 10-year simulation-ttimeframe-would be based on an extrapolation of' the market simulation results from the: studied years. A-higher-level annual market.

simulation will be'made for future year 15,Jto validate the extrapolation results and the extrapolation of annual benefits for years beyond'the 10-year simulation time frame may be adjusted accordingly. This high level simulation of future.year 15 may require a less detailed model of the transmission system below the 500 kV level.

An. extrapolation of the simulation results will provide a forecast of annual upgrade -benefits for each of the anticipated first 15 years of upgrade life, beginning from the projects anticipated in-service, date. The present value of annualbenefits projected for'the first" 15 years of upgrade life will be compared to the present value of the upgrade revenue; requirement for the same 15 year period to determine if the upgrade'is cost beneficial and recommended for inclusion in'the PJM RTEP. If the ratio.of the present value of: benefits to the present valueof costs exceeds 1.25 thenhthe upgrade is recommended for inclusion in the RTEP.

For each upgradewhich is.'ecommended forinclusion in the RTEP, PJM will provide the level of new generation or DSM per region that would eliminate the need for the transmission-upgrade.

When the 'economic efficiency project evaluations, have been' completed, PJM will schedule a TEAC or Subregional Committee meeting, as appropriate, to..review the results., The timing of this' meeting may depend on the, amount and complexity of analysis that must be performed. It is, however, anticipated that this meeting will take place by April of the.

calendar year that begins the. subsequent RTEP planning cycle. At this meeting PJM will provide a'summary of theanalysis results,:including an update of the Market Efficiency analysis, and a description of any recomnmendations-for economic, efficiency projects..

Determination of final RTEP market efficiency upgrades PJM will perform a combined. review of. the accelerated' reliability projects and new market.

efficiency projects that passed the economic screening tests to determine if there are potential upgrades with,:electrical similarities. Thismay result in new projects to replace the original projects to form a moreefficient overall market solution. Stakeholders may also suggest.'suph potential syrergies. PJM will evaluate'the.:cost:/ benefits of any such-resulting "hybrid" projects3. The final list of reliability projects-and market efficiency projects,.including any "hybrid" I projects will be presented and discussed at a secohd quarter (April) TEAC meetingAt this TEAC.meeting PJM will.review all theMarket efficiency, plans resulting'from this cycle of market efficiency studies. Recommended projects will be taken to the PJM Board for endorsement,.and will either beincluded in subsequent RTEP analysis. if there is a "volunteer" to build the project, or:a report will be filed with:FERC in accordance with:

Schedule 6;of the PJM OperatingAgreement. As part of this request for endorsement, PJM 3 Hybrid transmission upgrades include proposed solutionswhich encompass modification to reliability-basedenhancements already included in RTEP that when modified would relieve one'or moreeconomic constraints. Such hybrid upgrades resolve reliability issues butare-intentionally designed in a more robustmanner to provide economic benefits in addition to 'resolvinrg those reliability'issues.

Manual 14B: PJM Region Transmission Planning Process Section 2: Regional Transmission Expansion.Plan Process will provide the written comments submitted by the paoies, andwill discuss these written

.comments with the PJM Board.

Within the limits-of confidential, market'sensitive, trade secret, and proprietary.information,.

PJM will make all of the information used to develop the Market Efficiency recommendations available to market participants-to use in their own, independent analyses.

For each enhancement which is analyzed, PJM will calculate and post on its website changes in the following metricswon a zonal and systenii-wide-basis: (i) total energy production costs (fuel costs,-variable O&M costs-and emissions costs); (ii) total load energy payments (zonal load MW times zonal load Locational Marginal Price); (iii) total generator revenue from energy production (generator MW times generator.Locational Marginal Price)ý (iv) Financial Transmission Right credits(as measured using currently allocated Auction Reyenue Rights plus additional Auction Revenue Rights made available bythe~proposed acceleration or modification of a planned reliability-based enhancement or expansion or new economic-based enhancement or expansion); (v) marginal loss surplus credit; and (vi) total capacity costs and load capacityi payments under the Reliability Pricing Model construct.

For each marketefficiency project proposed for RTEP, PJM will also post, as soon as practical, the'following:

a. Anticipated high-evel project schedule and. milestone dates

b. Final commitment dateafter which any change to inputfactors or drivers-will rnot result in transmission project deferral or cancellation.

After this TEAC meeting, any member of the TEAC canmprovide written comments within

ýsixty (60) days of this meeting. Thesewritten comments williconsist of three (3) sections:

Introduction which-will describe the party submitting the comments and their reason for-submitting these comments S Summary, which will consist of no more than 3 pages summarizing the positions described in the writtencomments Discussion, which will consist of no: more than 20. pages describing in detail the:positions taken, by -the. party Submitting Alternative Proposals Any TEAC member or.other entity- (consistent with PJM Operating Agreement Schedule 6 provisions), may formally submit alternative proposals for evaluation under the Market Efficiency analysis at any time, but no later than December 3 1st of each year RTEP cycle year in order to be considered in-the then-current planning cycle (the RTEP market efficiency planning analysis carries over from the R.TEP cycle year into the first quarter of the-following RTEP planning cycle'year.) These alternatives Will be posted on the PJM Website. PJM will consider.these alternatives, and establish the final set of proposals to be included in market. efficiency anal-ysis. The process of formally submitting proposals-is not limited to.transmission solutions. bbut may also include generation solutions via PJM's

.established interconnection queue process; or,. demand side management and load management-proposals as well. Alternatively, marke t projects to relieve congestion Can be submitted by marketparticipants-through.the queue process at any-time. PJM will evaluate these projects under the thencurrent business rules contained in the PJM Tariff and Operating - Agreement.

26 Revision 12,- Effe*ctive Date:'08108/2008

Manual 148. PJM Region Transmission Planning Process Section 2: Regional Transmission Expansion Plan Process Regardless of all proposals considered - whether proposed by PJM or other parties - PJM will establish a "go/no-go' decision-point deadline (or final commitment date) after Which existing RTEP transmission components will not be *deferred or cancelled. Thiswill provide cedaintylto-developers; owners and investors.

Ongoing Review, of ProjectCosts To assure that projects selected'by the PJM Board for Market. Efficiency continue to be economically beneficial, both the costs and -benefits of theseprojects*will periodically be reviewed, nominally on an annual basis. Substantive changes in the costs and/or benefits of these projects will be-reviewed with the TEAC at a subsequent meeting to determine if.these projects continue to provide measurable economicbenefit andshould remain in the RTEP.,

For projects with a total cost exceeding $50 million;.an independent review ofpeoject costs

,and benefits will be performed to assureý both consistency of estimating practices across PJM'and that.the scope of the projectis consistent with the project as proposed in the

,Market.Efficiency analysis.

Evaluation: of Operational Performance Issues As per Schedule 6, section 1'.5 ofthe PJM Operating Agreement, PJM is required to address operational performance issues and include system enhancements, as may be appropriate, to adequately address identified problems. To fulfill thisobligation, PJM Transmission Planning staff and Operations Planning staff annually review-actual operating results to assess the need for transmission upgrades-that would address identified issues.

Typical operating areas. of interest in theserreviews include Transmission Loading Relief (TLR) and Post'Contingency Local Load Relief Warning (PCLLRW) events.

The first poperational performance.issue.to be addressed through the RTEP was an upgrade of the Wylie Ridge 500/345 kV transformation. The metric applied to-designate Wylie Ridge an operationalVperformance issue. was~the TLR metric...This same metric is applied

'consistent!yacross -the.PJM footprint In addition, PJM has also develope6 and initiateduse of a tool for Probabilistic Risk Assessment (PRA) of transmission infrastructure. PJM's 500/230 kV transformer infrastructure has been i dentified as particularly suited for assessment using this tool. PRA is further discussed in following sections..

Operational Performance Metrics Events and metrics, considered in the annual operational performance reviews are.not limited to a specifically defined list and will be reSPonsive to events and Conditions that may arise, In addition, PJM'stakeholders may raise operational issues to PJM's attention for consideraiionmduring'the. RTEP:process.-through interactions with the.Planning TEAC or Subregional RTEP Committees.

'ThePJM TLR metric identifies facilitiesthatresult in over 1,000 hours0 days 0 hours 0 weeks 0 months or 100 occurrences of TLR level 3Ior higher on an annual.basis. These facilities will be evaluated through the RTEP process for system enhancement.

For PCLLRW events, PJM will review all such events after the conclusion of the peak season: The' initiating facilities will be determined and the expected impacts of planned PJM ©02008 27 Revision 12, Effective Date- 08/08/2008

Manual 14B: PJM Region Transmission Planning process.

,Section 2: Regional Transmission Expansion Plan Process RTEP upgrades will be-reviewed and the need for additional planned upgrades will be evaluated.

.PRA evaluation uses an economic analysisof thecost of the investmnentthat, mitigates a risk-and the dollar-value of the avoided risk. The mitigation strategy cost, prime rate, and payback period are used to determine ifthe strategy cost is less.than the value of risk:

Projects with lower: cost' than risk,are,candidates for,.the RTEP.

Probabilistic Risk Assessment of PJM 500/230 kV Transformers One significant element of PJM's operational performance reviews involves a riskevaluation aimed at anticipating significant transmission loss events. PJM integrates aging infrastructuredecisions into the.ongoi ng RTEP process: analysis, plan development, stakeholder review, PJM Board approval, and implementation, over PJM's entire footprint.

Thus, the aging infrastructure initiative implements a proactive; PJM-wide approach to assess-the risk of transmission facility loss and to mitigate operational and market impacts of such losses.

PRA's.sinitial implementation atPJM isa risk management tool employed to reduce the potential economic and reliability consequences oftransmission system equipment losses.

In collaboration with academia, vendors and member TOs, PJM integrated various input drivers into a transformer PRA initiative to manage 500/230 kV transformer risk. In'the case of th'e,500/230 kV transformers, risk is theproduct of the probability ofincurring a loss and the economic consequence of the loss. Probability of loss is,determined based on the-individual.transformer :unit's 6ondition':assessments and Vintage history. Economicloss impacti.s based uponthe duration of the loss and the accumulation'of unhedgeable congestion costs, or the increased cost ofrunning out of merit'generation to' meet load requirements after a&transformer loss. If.lead times for.500/.230 kVtransformer units'are as.

greatas 'eighteen months, then outage-durations canobe long if adequate: loss mitigation is

not inplace. The PRA outputs the annual risk to the PJM systerm Iof each transformIer unit in termsof dollars. The annual risk dollars are then used to justify rriitigating solutions such as redundant':bank deployment; proactive replacement or adding spares. The deployment stratejgy chosen will depend on the level. of risk.mitigation, and reliability benefit.

,While'initially developed for aging 500/230 kytransformers, the PRA tool is capable 'of assessingother equipment types and other transformer voltage classes. The PRA tool is commercially available software.

PJMW. 2008 28 Revision 12, Effective Date: 08/08/2008

v t e Letter Sequence Response to RAI
TAC:MD9554, (Open)
Initiation Request Acceptance Administration Withholding Request Acceptance Questions 3 October 2008 15 October 2008 4 November 2008 17 November 2008 24 March 2009 24 March 2009 Answers 3 December 2008 29 December 2008 29 December 2008 17 February 2009 18 February 2009 30 December 2008 7 May 2009 Results Approval... Other: ML083430012, ML090130145, ML091660290, ML091820366, ML091880236
MONTHYEAR2008-09-24 [Table View]

ML090020382

Text

SUBJECT:

REFERENCES:

Attachment:

RAI 1

RAI 2

RAI 3

RAI 4

SUBJECT:

REFERENCES:

SUBJECT:

REFERENCES:

Navigation menu

Search