ohio valley electric corporation...ohio valley electric corporation 2015 transmission plan. 5 ....

OHIO VALLEY ELECTRIC CORPORATION

2015 TRANSMISSION PLAN

Prepared On OVEC’s behalf by:

East Transmission Planning

American Electric Power

November, 2015

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annual plan, completed November 2015

Foreword

American Electric Power (AEP) completed this Transmission Performance Appraisal on

behalf of the Ohio Valley Electric Corporation (OVEC)

Questions and comments regarding this document should be referred to:

Jonathan Riley

Engineer


American Electric Power

700 Morrison Road

Gahanna, Ohio 43230

Phone: (614) 552-1681

Fax: (614) 883-7234

E-mail: [email protected]

Or to Charles M. Blanford

System Operations Supervisor

Ohio Valley Electric Corporation

3932 US Route 23

Piketon, Ohio

(740) 289-7225

Fax: (740) 289-7285

E-mail: [email protected]

Table of Contents

Executive Summary 1

Introduction 1 System Description 1

Review of Recent Operating Conditions and System Changes 4

New Facilities 4

Abnormal conditions 4

Study Base Cases Assumptions 5

2016 Summer Peak Load 5

2020 Summer Peak Load 6

2020 Spring Light Load 7

Sensitivity Studies

– 2020 Summer Peak w/Reduced OVEC Generation 7

Transfer Capability Analysis (FCITC) 8

Steady State Analysis Results TPL-001 conditions 9

TPL-002 conditions 9



Short Circuit Assessment 10 Stability Studies and Results 11 Operating Procedures/Special Protection Systems 11

Appendices

Appendix A – Performance Testing Criteria

Appendix B – Special Procedures & Contingencies

Appendix C – Steady State Simulation Outputs

Appendix D – Short Circuit Assessment

Appendix E– Kyger Creek Stability Assessment

Appendix F- Clifty Creek Stability Assessment

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R2.1.1, R2.1.2, R2.1.4

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While the Table of Contents reflects the "old" contingency categories, the detailed results are labeled with both old and new categories.

Ohio Valley Electric Corporation 2015 Transmission Plan

1

Executive Summary

The Ohio Valley Electric Corporation (OVEC) system in the near-term planning horizon

is projected to meet the requirements of both OVEC planning criteria and the applicable

NERC Transmission Planning Standards.

Steady State studies examined performance of the planned OVEC system at the projected

summer peak load levels and planned systems of 2016 and 2020, and 2020 Spring Light

Load conditions. Transfer analysis examined incremental transfer capabilities for

transfers into, out of, and across the OVEC system. A sensitivity analysis examined 2020

summer peak load performance with a different OVEC dispatch assumption.

Short Circuit studies carried out in 2015, reflecting known changes in the vicinity of the

OVEC system. It was determined that the highest anticipated breaker duties are

approximately 89% of capability, following completion of replacement of the last

antiquated breaker at Kyger Creek coincident with a scheduled spring-2016 unit outage.

Previous studies of the stability performance of the Clifty Creek and Kyger Creek plants

have been determined to still be valid. These studies indicated that performance meets the

requirements of the NERC TPL standards. The previous assessments are provided for

reference in Appendix E for Kyger Creek and Appendix F for Clifty Creek.

In light of the results documented in this 2015 assessment, the existing and planned

OVEC system is expected to meet the NERC TPL standards without any additional

transmission reinforcements or upgrades through 2024.

Introduction This report provides an assessment of the OVEC transmission system as required by the

NERC Transmission Planning Standards. This assessment, and the studies it documents,

is also an integral part of the open planning process instituted in response to FERC Order

890.

System Description

The Ohio Valley Electric Corporation (OVEC) and its subsidiary, Indiana-Kentucky

Electric Corporation (IKEC), were organized and their transmission systems constructed

in the years 1952-1956. OVEC/IKEC was formed by 15 investor-owned electric utility

companies (Sponsors) for the express purpose of supplying the electric power

requirements of a single retail customer, the U.S. Department of Energy's (DOE) uranium

enrichment project (Project) located near Portsmouth, Ohio. Due to the highly critical

nature of the DOE load, stringent design criteria were adopted for planning and

constructing the OVEC/IKEC System.

The entire OVEC/IKEC System is considered to be part of the bulk electric system, as it

is primarily an EHV network. The system map, showing the configuration as presently

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This section and the following diagram describe and illustrate the existing OVEC system to acknowledge R1.1.1

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Overall assessment - R2


2

planned to exist through the end of the 10 year planning horizon, appears below. The

only non-EHV transmission facilities are 138 kV facilities associated with

interconnections to the systems of several Sponsors. The OVEC system is highly

interconnected. Interconnecting facilities consist of eight 345 kV lines, the high-side

connections to four neighboring system 345/138 kV transformers, and three 138 kV lines.

The strong internal EHV network and number of interconnections relative to the size of

the system precludes a need to analyze sub areas within OVEC, or to use more detailed

models than are used in regional studies.

The minimal DOE load today is served from the remaining DOE-owned 345 kV station

(DOE X530) within the Project's boundaries. Two double-circuit tower 345kV lines and

one single-circuit 345 kV line from OVEC/IKEC and Sponsors’ stations supply this

station. A second, similar station (DOE X533) was removed from service in November

2008. Reconnection of the lines (bypassing the former station site) was completed in

December 2010. The OVEC/IKEC System has eleven generating units located at two

plants with a total capacity of about 2200 MW. Prior to September 2001, a portion of the

OVEC generation was delivered to the DOE load based on the demand established in

OVEC/IKEC's contract with DOE, and any remaining generation was sold to the

Sponsors on an ownership participation basis. Since September 2001, all generation,

with the exception of required operating reserves, has been made available to the

Sponsors. Considering the strength of the generation and transmission system compared

with the total load served and the transfers incurred in real time, it is reasonable to

assume that OVEC does not require additional reactive compensation.


3


4

Review of Recent Operating Conditions and System Changes

As outlined in Attachment M of the OVEC Tariff, the following factors are to be

addressed in developing the OVEC transmission plan:

• Review of recent operating conditions, such as NERC Transmission Loading

Relief events or MISO and PJM LMP binding constraints that may indicate

developing reliability concerns on the OVEC system

- Recent congestion has generally been associated with multiple prior

outages of other facilities

• Requests for connection to OVEC facilities

- None

• Requests for service into, out of, or through the OVEC Transmission system

- None

• Projections of future load or generation changes within OVEC

- Minimal

• Projections of OVEC major transmission equipment or systems approaching

end-of-useful life

– One 345 kV Oil Circuit Breaker (OCB) and associated Protection &

Control (P&C) equipment remains in service at Kyger Creek.

New Facilities

Replacement of antiquated circuit breakers and associated relays and controls

at Kyger Creek continues. Replacement of 16 of the 17 original 330/345 kV

Oil Circuit Breakers (Including 1 owned by AEP) has been completed, the

remaining one will be replaced during a scheduled outage of the associated

generating unit in the spring of 2016.

Abnormal Conditions

No extended periods of abnormal conditions are expected on the OVEC system.

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This page summarizes the review of the elements of R1 to be reflected in the models, so that performance is examined under projected system conditions.


5

Study Base Cases

Assumptions

The primary analyses for this assessment were based on a 2020 Summer near term peak

load power flow model developed for studies carried out by the ReliabilityFirst (RF)

Transmission System Performance Subcommittee. This model represents Eastern

Interconnection systems, particularly those of RF members, including OVEC and

adjacent transmission systems, as planned for the 2020 Summer period in early to mid-

2015. This represents the latter portion of the near term (Years 1-6) planning horizon.

Deactivation of several units near the OVEC system were not reflected in the RF study

models. These units were subsequently removed from service in the OVEC study models

prior to completing the assessment documented in this report.

Most of the upgrades needed to maintain reliability after the announced generator

deactivations take place have been identified and are included in the planned system

evaluated in this assessment. However, analysis of system performance with the full

scope of post-retirement transmission upgrades (similar to any other neighboring system

plans not yet finalized at the time the OVEC analysis is performed) will be an ongoing

process as plans in adjacent systems continue to evolve.

Additional analyses were performed to provide context and provide a basis for assessing

other load levels, time periods and generation dispatch. The 2016 Summer model

developed for the ReliabilityFirst (RF) Transmission System Performance Subcommittee

seasonal assessment provides a reference point based on year-one conditions. Additional

base case Models were developed starting from the ERAG/MMWG 2014 library models

representing Light Load conditions for the system projected to exist in the 2020 Spring

period,. As the known system improvements and generator retirements affecting the

OVEC area are represented in the 2020 Summer model, and no emerging issues

involving-OVEC owned facilities appeared in any of the near term analyses, previous

studies of the long term planning period were deemed to still be valid. Based on the

system plans known at this time, performance for the longer term (6-10 year) planning

horizon is anticipated to be similar to that identified in the 2020 analysis.

2016 Summer Peak model

• The initial base case model for the 2016 peak load studies was derived from the

2016 summer peak model contained in the 2014 series ERAG-MMWG library.

RF member systems had the opportunity to review and update this model in the

first half of 2015, for use in the RF summer seasonal assessment. For these OVEC

studies, the [AEP] Mountaineer-Sporn 765/345 kV reinforcement was added, and

several recently retired units at the [DEOK] Beckjord and Miami Ft plants were

removed from the dispatched generation.

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This page and the following 2 pages provide more information about the models for each season and/or sensitivity scenario studied, including documention for R1.1.3

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The review of system changes summarized here, and facility changes listed on the next page, support the determination that the results of the Summer 2020 studies also apply to the 6-10 year period covered by R2.2


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2020 Summer Peak Planning horizon models:

• The initial base case models for the 2020 peak load studies were derived from the

2020 summer peak model contained in the 2014 series ERAG-MMWG library.

RF member systems had the opportunity to review and update this model in the

first half of 2015. Recent and pending generation retirements and major

transmission changes in close proximity to OVEC are tabulated below. Because

the OVEC Transmission system consists entirely of 345 kV and 138 kV facilities,

the OVEC system is fully represented in the MMWG power flow models. There

are no additional OVEC transmission facilities expected to be in service for the

planning horizon that were not represented in the RF models. For OVEC, key

assumptions for all peak load models consist of an area load of 35 MW and a total

generation of 2,000 MW delivered to the OVEC owners. In determining the level

of OVEC interchange to be modeled, it is assumed that the equivalent of one of

the eleven OVEC generators is not available. Because the OVEC generation units

are all of similar size, age, and operating history, the assumption is made that they

will all be dispatched at similar levels.

• The following nearby (within 2-3 buses) units were modeled as unavailable in the

RF 2020 Summer model:

• Duke-Ohio & Kentucky

o Beckjord 4-6

o Beckjord GT 1-4

o Miami Ft 6

Other generating units recently retired in AEP, DEO&K and LGEE were not

represented in the RF 2020 powerflow model.

• The following major nearby transmission facility changes were included in the RF

study model

o AEP

� Add Mountaineer/Sporn 765/345 kV transformer

� Reterminate Kyger-Tristate 345 kV OVEC-AEP tie at

Sporn 345 kV

� Un-six-wire and reconductor/rebuild Sporn-Waterford/Muskingum

345 kV

o LGE

� Add Cane Run 7 CC block

o DEI/NIPSCo

� Add Reynolds-Greentown 765 kV and Reynolds 765/345 kV

transformer

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These generating unit retirements, and the the transmission and generation additions listed here, represent the major transmission changes projected to occur through the 2024 summer period as of the time of the study.


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2020 Light Load Condition

The 2020 ERAG/MMWG Light Load model was reviewed and compared to the 2020

Summer peak model. No major topology differences were identified in the vicinity of

OVEC. Sensitivity Studies

2020 Summer Peak with OVEC generation reduced

Consideration of the recent economics of combined cycle gas facilities vs coal-fired

generation suggests that the historically high utilization of OVEC generation may be

reduced in the future. To examine the possible effects of this change, a sensitivity case

was created with the OVEC generation at reduced output. This sensitivity scenario was

modeled by taking the 2020 Summer peak base model, removing three of the Clifty

Creek units from service, and removing three units from service at Kyger Creek. This

scenario also serves to simulate outage of common facilities associated with the FGD

systems. It is a more severe condition than leaving all units running at reduced output, as

it removes the reactive support of the outaged units. The reduced output from the OVEC

units is offset by proportionally reducing the OVEC interchange with the owners, Due to

limited dispatchable generation not already fully loaded in the base case, particularly in

several of the owning companies closest to the OVEC border, the owner’s end of the

reduced OVEC deliveries were simulated by scaling load down in the corresponding

areas. Flows on most OVEC facilities were either very similar to, or reduced, compared

to those in the peak load model. The only facility with significantly increased loading in

this scenario is a tieline, that is entirely owned by the neighboring system. Based on the

results of this comparison, no further analysis was performed on the reduced generation

scenario.


8

Transfer Capability Analysis (FCITC)

The PTI/Siemens PSS/E and/or MUST analysis tools were used to screen for violations of performance criteria under various outage

conditions. MUST was also used to determine First Contingency Incremental Transfer Capabilities (FCITCs) for 12 different transfer

directions expected to affect flows into, out of or through the OVEC system. These FCITCs are not an indication of the transmission

network capability to accommodate a specific transfer or transmission service request. However, they serve as a surrogate for a

variety of possible operating conditions, and provide a means to evaluate the strength of the system as it is stressed by these varied

conditions. The following transfer directions were studied:

From To 2016

Summer Peak Load

FCITC (MW)

2020 Summer

Peak Load FCITC (MW)

Limit

OVEC Sponsors* 100+ 100+ None

Sponsors* OVEC 1000 1000+ Trimble Co – Clifty Creek 345 kV

LGEE DEO&K 400+ 600+ None

DEO&K LGEE 0+ 0+ None

LGEE AEP 400+ 600+ None

AEP LGEE 2450+ 1900+ None

EKPC DEO&K 100+ 100+ None EKPC DAY 100+ 100+ None TVA ITC 50+ 150+ None

ITC TVA 850+ 800+ None

AMIL DVP 1450+ 1300+ None

DVP AMIL 150+ 200+ None

AMIL PJM 1450+ 1300+ None

+ Not limited by transmission conditions at the value given (Generation Capacity Limit or tested transfer level)

*The deliveries involving the OVEC Sponsoring companies are allocated in the following manner:

AEP 61.47% (Includes Buckeye share) FE 4.85% SIGE 1.5% METC 6.65% (Peninsula share)

AP 3.5% DAY 4.9% LGEE 8.13%

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This Transfer Capability analysis examines N-0 and N-1 (P0 and P1) conditions for a number of different transfer directions (R2.1.4)


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Steady State Analysis Results

NERC Planning Standard TPL-001-1 Category A Conditions (TPL-001-4 P0) (No Contingencies) No OVEC facility loadings exceed the Normal ratings, and voltages are within criteria in

the 2016 Summer Peak model, the 2020 Summer Peak near-term model, the 2020

reduced OVEC generation model, and the 2020 Spring Light Load model.

NERC Planning Standard TPL-002-1b Category B (TPL-001-4 P1) Conditions (Event resulting in the loss of a single element)

Approximately 6500 Category B contingencies were simulated for each season or

scenario studied.

No OVEC facility loadings exceed the Emergency ratings, and voltages are within

criteria in all Category B contingency simulations. There were up to 90 contingencies

(depending on the base case) that indicated possible voltage collapse in the initial

simulations. Review of these contingencies shows that most involve outages of 138 kV

or lower voltage facilities located remote from the OVEC system. Some, particularly

those below 100 kV, may be artifacts of equivalized models. In the case of the 2020 peak

and light load models, it appears that the base cases themselves are ill-conditioned. Some

improvement in convergence was obtained by locking several switched shunts remote

from OVEC. Efforts to confirm that the conditions flagged in the MUST screening did

not involve OVEC performance included additional simulations using PSS/E, which

succeeded in solving most of the other scenarios. None of the results indicated voltage or

flow violations on OVEC facilities. A summary of these events is being provided to the

relevant parties for their consideration.

NERC Planning Standard TPL-003-0a System Performance Following Loss of Two or More Bulk Electric System Elements (Category C) (generally, TPL-001-4 P2, P3, P4 P5, P6 and P7)

More than 12,000 Category C contingencies were simulated for each season studied.

Note that due to the typical OVEC station breaker-and-a-half configuration, there is often

overlap between the Category C and some Category D contingencies in the TPL-003-0a

definitions, and between the listed P categories under the definitions which apply under

TPL-001-4. Many of the contingencies tested may apply under more than one category.

No OVEC-owned facility loadings exceed the Emergency ratings, and voltages are within

criteria in all Category C contingency simulations. One tieline limited by facilities owned

by the connecting company, was found to overload in the 2016 Summer Peak model for

one contingency pair. This overload was not seen in any of the other scenarios studied.

Since OVEC does not own the limiting equipment, OVEC will convey these results to the

facility owner for further consideration. The same solution issues encountered in the 2020

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Results for R2.1.1 and R2.1.2 and R2.1.4 P0

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Results for R2.1.3 and R2.1.4 P1

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Steady State results for R3.1 and 3.2


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models in the single contingency simulations applied to the Category C simulations. In

these situations, many involved pairs of outages of large generators. In addition to the

other unidentified convergence issues, the generator outage scenarios are sometimes an

artifact of the simplified simulation used for screening the large number of contingencies.

NERC Planning Standard TPL-004-0 Category D Conditions (Extreme event resulting in two or more (multiple) elements removed or cascading out of service) (TPL-001-4 Table 1 Extreme events)

Because most OVEC stations have fully developed Breaker and half layouts, steady state

simulation of most Category D/Extreme events are already addressed under previous

categories of contingencies . The exceptions that apply to the OVEC system include

Category D contingency sub-types 8 and 9 (Table 1, 2c) which involve loss of one

voltage level at a substation or switching station, including transformation, and subtype

10 (Table 1, 2d) which involves loss of all generating units at a station. Because the

OVEC system now has minimal load within the boundary of the Balancing Authority, the

sub-type 8 or 9 contingencies are expected to be more severe than sub-type 10, which

only involves loss of generation. TPL-001-4 Table 1 Extreme events also reference Wide

area events based on system topology in item 3. At present, the events listed either are not

applicable to the OVEC system, are not well enough defined to conduct specific

simulations at present, or are already addressed by simulations under other categories.

Approximately 45 station outage contingencies were simulated in the 2018 Summer Peak

scenario studies performed in 2013. Eight of these outages were internal to OVEC, the

remainder involve neighboring buses in the adjacent systems. As in the Category C

simulations, several contingencies which resulted in loss of more than one large generator

were flagged for voltage concerns, but not within OVEC. No indication of cascading was

identified in these simulations. Given the lack of problems identified in the 2020

Summer studies, and the limited network changes in or near the OVEC system beyond

the 2018 period known at the time models were under development for the 2015

assessments, the previous 2018 Summer results remain indicative of the performance

presently expected in the Long Term planning period as well.

Short Circuit Assessment Studies performed in 2015 evaluating the expected short circuit interrupting duties

relative to the capability of the planned circuit breakers, following completion of the

Kyger Creek breaker replacements. The one remaining (of the 17 original) 330/345 kV

breakers at Kyger Creek will be replaced during a scheduled outage of the associated

generating unit in the spring of 2016. The studies showed that no OVEC circuit breakers

are expected to be called upon to interrupt fault currents in excess of their capability.

Eighteen breakers were found to have interrupting duties above 80% of their capability,

with the highest at 89.2% of capability. The detailed studies are documented in Appendix

D.

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R2.3 Assessment. Results appear in Appendix D (also bookmarked)

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11

Note that these results are expected to be somewhat conservative (i.e., overstate the actual

fault currents to be reasonably expected going forward.) This is because some retired

generating units in neighboring systems are still modeled as in service. Under the terms

of the applicable tariff, the owner of a unit that has requested deactivation has up to one

year after the actual deactivation date to apply to reuse their connection rights. To prevent

“overselling” connection rights, the impact of the retiring units needs to be included until

those rights have expired. While some of these rights may be re-used, it appears unlikely

that they all will be.

Stability Studies and Results

Studies were performed in late 2011 to evaluate the stability performance of the Clifty

Creek plant during the outages needed to retire the Dearborn CBs DA and DD, and

applying the requirements of the proposed TPL-001-2. The plant performance was found

to meet the requirements of both the OVEC Transmission Testing Criteria and NERC

Reliability Standards. The studies were documented in a separate report, provided as

Appendix F. Analysis of the stability performance of the Kyger Creek plant was

completed in 2010 and remains valid. It is provided for reference as Appendix E.

Operating Procedures/Special Protection Systems

OVEC has no Special Protection Systems. Operating procedures exist to reduce flows

through the Clifty Creek-Carrolton 138 kV tieline between OVEC and KU and the Kyger

Creek-Sporn 345 kV #1 tieline between OVEC and AEP. They are described in Part 5 of

the OVEC response to FERC Form 715, and reproduced in Appendix B of this report.

The Kyger Creek-Sporn procedure will be re-evaluated in the near future, since the

Kyger-Tristate line has been re-terminated at the Sporn station.

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Appendices

A- 1 -

Appendix A – Testing Criteria

(Excerpt from the OVEC response to FERC FORM 715 - ANNUAL TRANSMISSION

PLANNING AND EVALUATION REPORT)

4. TRANSMISSION TESTING CRITERIA

4.1 Steady State Testing Criteria

The planning process for OVEC/IKEC's transmission network embraces two major sets

of testing criteria to ensure reliability. The first set includes all significant single and

double contingencies (NERC Categories B and C.) The second set includes more severe

multiple contingencies (NERC Category D) and is primarily intended to test the potential

for system cascading.

For OVEC/IKEC transmission planning, the testing criteria are deterministic in nature;

these outages serve as surrogates for a broad range of actual operating conditions that the

power system will have to withstand in a reliable fashion. In the OVEC/IKEC

transmission system, thermal and voltage performance standards are usually the most

constraining measures of reliable system performance. Each type of performance

requirement is described in the following discussion. Table 1 below documents the

performance criteria for all transmission facilities under normal and contingency

conditions.

4.1.1 Single and Double Contingencies

Contingencies include the forced or scheduled outage of generating units, transmission

circuits, transformers, or other equipment. In general, a single contingency is defined as

the outage of any one of these facilities. Due to the interconnected nature of power

systems, testing includes outages of facilities in neighboring systems. A single facility is

defined based on the arrangement of automatic protective devices. Generally, double

circuit tower outages, breaker failures, station outages, common right-of-way outages,

and other common-mode failures have substantially lower probabilities of occurrence

than the outage of a single transmission facility and are, therefore, not considered single

contingencies.

Double contingencies, being a more severe test of system performance, are used as a

surrogate for the significant uncertainties that are inherent in the planning process. A

double contingency can be defined as an outage of any two facilities. Double

contingencies can be categorized by industry standards as either N-2 (an overlapping

outage of two facilities with no corrective action following the first contingency) or N-1-

1 (this category allows system adjustments after the initial outage). Double contingency

analyses are also frequently applied in facility planning studies. These tests provide

additional insight regarding the need for transmission system enhancements.

A- 2 -

Operational planning studies may consider up to two key outages in effect prior to the

next (third) contingency. It is assumed that all operator adjustments required for the prior

outages have been implemented. The number of prior outages depends on the strength of

the transmission system and the number of variables to be considered in developing

effective operating guidelines. Clearly, as the number of concurrent contingencies

increases, it will become increasingly difficult to meet the required performance limits

(see Section 3), even with special operating procedures.

The number of outages actually occurring on the system can exceed the number assumed

for study purposes. Operational planning engineers can evaluate those conditions, as

needed.

4.1.2 Extreme Contingencies

The more severe reliability assessment criteria required in NERC Reliability Standards

are primarily intended to prevent uncontrolled area-wide cascading outages under adverse

but credible conditions. OVEC/IKEC, as a member of ReliabilityFirst, plans and

operates its transmission system to meet the criteria. However, new facilities would not

be committed on the basis of local overloads or voltage depressions following the more

severe multiple contingencies unless those resultant conditions were expected to lead to

widespread, uncontrolled outages.

In operational planning studies, the purpose of studying multiple contingencies and/or

high levels of power transfers is to evaluate the strength of the system. Where conditions

are identified that could result in significant equipment damage, uncontrolled area-wide

power interruptions, or danger to human life, IROL operating procedures will be

developed, if possible, to mitigate the adverse effects. It is accepted that the defined

performance limits could be exceeded on a localized basis during the more severe

multiple contingencies, and that there could be resultant minor equipment damage,

increased loss of equipment life, or limited loss of customer load. Normally, operating

procedures to mitigate uncontrolled area-wide power interruptions are only used on an

interim basis until facility additions can be put in place to restore acceptable reliability

levels.

4.2 Stability Testing Criteria

The Appendix B Stability Disturbance Testing Criteria specify the disturbance events for

which stable operation is required of all BES connected generation, including renewable

generation.

The disturbance events specified in testing criteria A through E of Appendix B are

applicable to planning and operational planning studies. These disturbance events

correspond to the NERC Category B2, B3, C3, C7 and C8 contingencies listed in Table 1

of NERC TPL standards 001 through 004. The disturbance events specified in criteria F

A- 3 -

and G of Appendix B may also be applied in operational planning studies when a long-

term facility outage is anticipated. Testing with disturbance events other than those

specified in Appendix B may be performed in planning and operational planning studies

where applicable. Examples of such testing include common-failure mode disturbances

such as double circuit tower faults (NERC Category C5) or bus faults (NERC Category

C9) that result in the outage of multiple facilities at a location. On the OVEC/IKEC

transmission system, NERC Category C1, C2, and C9 contingencies are generally either

of the same or less severity than the A criterion (Appendix B) breaker failure events that

result in tripping the same facilities.

4.3 Power Transfer Testing Criteria

The power transfer capability between two interconnected systems (or sub-systems) with

all facilities in service or with one or two critical components out of service, indicates the

overall strength of the network. Many definitions of power transfer capability are

possible, but uniformity is highly desirable for purposes of comparison. Furthermore,

transfer capability, however defined, is only accurate for the specific set of system

conditions under which it was derived. Therefore, the user of this information needs to

be aware of the conditions under which the transfer capability was determined and those

factors that could significantly influence the capability.

OVEC/IKEC has adopted the definitions of transfer capability, published by NERC in

"Transmission Transfer Capability", dated May 1995. The most frequently used transfer

capability definition is for First Contingency Incremental Transfer Capability (FCITC)

and is quoted below from the referenced NERC publication:

First Contingency Incremental Transfer Capability

"FCITC is the amount of power, incremental above normal base power transfers,

that can be transferred over the transmission network in a reliable manner, based

on the following conditions:

1. For the existing or planned system configuration, and with normal (pre-

contingency) operating procedures in effect, all facility loadings are within

normal ratings and all voltages are within normal limits.

2. The electric systems are capable of absorbing the dynamic power swings,

and remaining stable, following a disturbance that results in the loss of any single

electric system element, such as a transmission line, transformer, or generating

unit, and

3. After the dynamic power swings subside following a disturbance that

results in the loss of any single electric system element as described in 2 above,

and after the operation of any automatic operating systems, but before any post-

A- 4 -

contingency operator-initiated system adjustments are implemented, all

transmission facility loadings are within emergency ratings and all voltages are

within emergency limits."

First Contingency Total Transfer Capability (FCTTC) is similar to FCITC except

that the base power transfers (between the sending and receiving areas) are added

to the incremental transfers to give total transfer capability. ECAR has adopted

guidelines for interpreting and applying the NERC transfer capability definitions,

and OVEC/IKEC uses these guidelines in its internal studies as well.

While the first contingency transfer capabilities are the most frequently used

measure of system strength, transfer capabilities also can be calculated for "no

contingency" and "second contingency" conditions.

Available Transfer Capability

In April 1996 the Federal Energy Regulatory Commission issued two rules -- Orders No.

888 and 889. Two aspects of these rules are "open access" to the transmission systems of

integrated utilities and the posting of available transfer capability. The ability of a

transmission system to permit power transfers is defined by several terms, namely:

Firm Available Transfer Capability (ATC)

Firm Total Transfer Capability (TTC)

Non-firm ATC

Non-firm TTC

Transmission Reliability Margin

Capacity Benefit Margin

The ATC/TTC values provide an indication of the ability of the transmission system to

support transfers. Firm ATC is the level of additional transfer capability remaining in the

physical network for further commercial activity over and above existing commitments

for future time periods. The ATC/TTC values are calculated for transactions in both

directions between OVEC/IKEC and directly connected control areas and for selected

commercially viable through paths across the OVEC/IKEC System. ATC values are the

lesser of network capability or contract path capacity (i.e., the total capability of

interconnections to a neighboring control area). Firm TTC is determined by adding firm

schedules and/or reservations to the ATC values.

Non-firm ATC are calculated in a manner similar to that used to calculate the firm values,

except that both firm and non-firm transactions are included in the calculations.

TRM is the amount of transfer capability which may be reserved to ensure that the

transmission network is secure under a range of uncertainties in operating conditions.

These uncertainties include generation unavailability, load forecast error, load diversity,

unknown outages in neighboring systems, and variations in generation dispatch. The

TRM is applied directly to facility ratings for calculations of firm ATC/TTC by adjusting

A- 5 -

the thermal rating of the critical facility(ies) down to 95% of the seasonal emergency

capability. TRM is applied only to firm ATC calculations.

CBM is the amount of transfer capability reserved by Load Serving Entities to ensure

access to generation from interconnected systems to meet generation reliability

requirements. The total OVEC/IKEC CBM value is based upon generation reserve

requirements. CBM is subtracted as a fixed MW amount from the firm OVEC/IKEC

TTC import capability. The CBM is allocated among OVEC/IKEC’s interfaces and the

amount allocated to individual interfaces is based upon the lowest of: 1) the estimated

long term generation reserve of the adjoining control area, 2) the transmission

interconnection capability with each of the adjoining control areas, and 3) the FCTTC

with each of the adjoining control areas.

At present, the TRM and CBM for the OVEC System have been reduced to zero.

OVEC/IKEC methodologies to calculate these values are consistent with the “NERC

Available Transfer Capability” and the “ECAR TTC/ATC Calculation/Coordination”

documents.

B- 2 -

Appendix B – Special Procedures & Contingencies

(Excerpt from the OVEC response to FERC FORM 715 - ANNUAL TRANSMISSION

PLANNING AND EVALUATION REPORT)

A. SPECIAL PROCEDURES

This section describes operating procedures that have been developed to mitigate

problems identified on the transmission system and special modeling techniques

used in the assessment of OVEC/IKEC system performance. Unless otherwise

stated, these operating procedures are anticipated to be applicable indefinitely. As

a result, they should be modeled in screening studies that evaluate future system

performance. The procedures described herein generally are implemented to

reduce facility loadings to within equipment thermal capabilities or to insure that

adequate voltage levels or steady state stability margins are maintained.

Clifty Creek-Carrolton 138 kV (OVEC-KU)

Past operating experience indicates that the Clifty Creek – Carrolton 138 kV

tieline between OVEC and KU may become heavily loaded anticipating loss of

either Ghent Unit 1 (KU) or Spurlock-N. Clark 345 kV (EKPC). Loading

concerns would likely occur during periods of high north-to-south transactions,

especially if these transfers coincide with high output at Trimble County (KU)

and reduced output at other LGE or KU plants. If necessary, OVEC has agreed to

open the Clifty Creek 345/138 kV transformer T-100A at the request of the PJM

Reliability Coordinator to relieve the loading concerns.

Kyger Creek - Sporn 345 kV (OVEC-AEP) Past operating experience indicates that the Kyger Creek - Sporn 345 kV tieline

between OVEC and AEP may become heavily loaded by high levels of west-to-

east transactions, especially if these transfers coincide with reduced output at any

of several AEP plants east of this tieline. AEP and OVEC have agreed to open the

Kyger Creek - Sporn 345 kV circuit, when necessary. However, opening this

tieline will increase loadings on other OVEC-AEP tielines. Conditions on these

facilities may restrict use of this procedure.

B- 3 -

The areas of concern described above are those identified in the most recent

performance appraisals conducted, based on the best available knowledge of

interconnected system development, and expected operating conditions. The

results of appraisals assuming different system conditions can be considerably

different.

B. CONTINGENCY LIST

The following is a description of the contingencies that have been simulated in

recent appraisals of the OVEC/IKEC system performance, to meet the

requirements of the ECAR Compliance Program. This list is not exhaustive, but is

designed to screen OVEC/IKEC system performance to verify that ECAR

reliability criteria are being met and that OVEC system performance will not

cause widespread cascading of the interconnected network.

Single Contingencies

Each branch within OVEC or the systems of OVEC’s immediate neighbors (AEP,

Duke Energy Ohio & Kentucky, Dayton, and LGEE).

Each OVEC tieline

Each AEP tieline

Each Dayton tieline

Each DEO&K tieline

The OVEC (and DOE-owned stations within the OVEC Balancing Authority

area) are primarily of the “breaker and a half” configuration. Therefore, single

contingencies can generally be represented by individually removing each branch

or generator represented in the powerflow model. Exceptions from this statement

include the following:

• Clifty Creek 345/138 kV transformation – The in-service Clifty Creek

transformer T-100A does not have automatic switching between the

transformer and the 138 kV bus. Forced outages of this transformer also

de-energize the Clifty Creek 138 kV bus, opening the ties to

Carrolton(KU), Northside(LGE) and Miami Fort(DEO&K) until the

transformer low-side disconnect can be manually opened and the bus

restored.

• Dearborn(OVEC)-Tanners Creek(AEP) 345 kV bus extension – The 345

kV tie between these adjacent OVEC and AEP stations is protected as a

bus extension rather than a transmission line. Normal clearing of a fault

on the tie or the #1 Tanners Creek bus will also trap the Tanners Creek

B- 4 -

(AEP) – East Bend (DEO&K) tie, as well as the Dearborn-Clifty Creek #1

and Dearborn – Pierce circuits.

The OVEC/IKEC generators are cross-compound machines. Future modeling

refinements to increase compatibility between steady state and dynamics models

will have each shaft represented individually. Representing a change in dispatch

or status of a single unit will require changes to both HP and LP machines in the

model.

One additional outage scenario that does not directly correspond to any of the

contingencies required by the NERC TPL Reliability Standards should be

included in contingency simulations testing the OVEC/IKEC transmission

system:

• FGD systems at both Clifty Creek and Kyger Creek plants create the

possibility that some common-mode FGD equipment trips could remove

up to 3 units at either plant. This exposure does not match any of the

contingencies required by the NERC TPL Standards, therefore OVEC

does not consider that issues identified for these outages would require

mitigation. However, performance for such outages should be evaluated

for risks and consequences.

Multiple Contingencies

All combinations of branches connected to any OVEC bus, or two layers out from

any OVEC bus, augmented by any branches identified in the Single Contingency

analysis above. Similar to the discussion in the Single contingency section, the

“breaker and a half” configuration present at most OVEC stations means that

(neglecting, for screening purposes, the manual system adjustments allowed

between the individual “Category B” contingencies in NERC Category C3

contingencies) most types of NERC Category C or D contingencies for OVEC

studies can be simulated by simply removing individual branches two at a time.

NERC Category D contingencies resulting in complete station outages are also

regularly tested. Most common power system analysis tools provide options to

easily simulate these outages.

C-- 1 -

Appendix C

Results

C-- 2 -

Appendix C

C-- 3 -

Category A (P0) Results - 2016 Summer Peak

s744241

loading % of Normal rating and voltage highlighted

s744241

C-- 4 -

Appendix C Category A (P0) Results – 2020 Near-Term Summer Peak

s744241

C-- 5 -

Category A (P0) Results – 2020 Near-Term Summer Peak – reduced OVEC generation

s744241

C-- 6 -

Category A (P0) Results – 2020 Light Load model

s744241

C-- 7 -

Appendix C – Category B (P1, P2) results 2016 Summer Category B Results Contingency Violation Summary

PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- SUN, NOV 29 2015 6:16

<COV000.0>

2014 SERIES, ERAG/MMWG BASE CASE LIBRARY (CEII)

2016 S PK LD CASE, FINAL, RF '15 STUDY, +UPDATES FOR OVEC

Case.File C:\Users\s744241\Downloads\OVEC working\OVEC 2015 assessment 2016 S Peak_post RF

updates_v33.sav

Subsys.File U:\JHR_02-20-2013\JHR\OVEC\2015\other input data\ovec_15compl_inertia_2.sub

Monit.File U:\JHR_02-20-2013\JHR\OVEC\2015\other input data\OVEC combo 2015.mon

Contin.File U:\JHR_02-20-2013\JHR\OVEC\2015\other input data\ovec+adjacent_singles_15 assess_inertia.con

Exclud.File none

*** Statistics on monitored constraints:

Monitored Branches: 30

Monitored Voltages: 8

Contingencies : 6568

*** Summary on Constraint Violations ***

*** Violations with flow changes less 0.00 MVA or voltage change less 0.000 % ignored

No System problems have been identified

*** Contingency Results Summary. ***

Total No. tested = 6532 Total LF iterations 29196

Converged = 6503

Voltage Collapse = 29

Not Converged = 0

s744241

Initial Screening using MUST

C-- 8 -

Appendix C – Category B (P1, P2) results 2016 Summer Category B Results - continued PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- SUN, NOV 29 2015 6:17 <COL003.0>



Case.File C:\Users\s744241\Downloads\OVEC working\OVEC 2015 assessment 2016 S Peak_post RF updates_v33.sav



Contin.File U:\JHR_02-20-2013\JHR\OVEC\2015\other input data\ovec+adjacent_singles_15 assess_inertia.con

Exclud.File none

******* List of 29 user selected contingencies. Total 6568. *******

Contingency

Events

Ncon Contingency

Outage

Flow Open Close Bus Dispatch

# of

Island

Nbus

Island

Island

Load

Island

Generatn

Num

Viol

Ov

Se

188 242563 05BOXWD 138 242603 05CLIFFR 138 1 56.1 1 0 0 0

189 242563 05BOXWD 138 242765 05REUSEN 138 1 -109.0 1 0 0 0

359 242637 05FLATWO 138 242783 05RUTLED 138 1 -63.4 1 0 0 0

379 242648 05GARDEC 138 242801 05SKEGGB 138 1 -119.4 1 0 0 0

427 242670 05HOLST2 138 242819 05SULVN 138 1 -5.2 1 0 0 0

446 242680 05ITMANN 138 242727 05MULLEN 138 1 84.1 1 0 0 0

452 242683 05J.EARL 138 242755 05PIPERS 138 1 -14.3 1 0 0 0

512 242717 05MILTON 138 244722 05MILTON * 69.0 1 17.5 1 0 0 0

689 242876 05MONROE A 69.0 242882 05REUSENS 69.0 1 -24.3 1 0 0 0

961 243020 05HILLVI 138 243156 05WNPHIL 138 1 115.6 1 0 0 0

1037 243056 05NEWCOM 138 243144 05WCAMBR 138 1 -79.5 1 0 0 0

1056 243062 05NMUSKG 138 245431 05N MUSKNG 69.0 1 14.4 1 0 0 0

1231 243174 05MOULTO 69.0 243182 05WAPAKONE 69.0 1 19.3 1 0 0 0

2100 243739 05MAYKING 69.0 243752 05WHITSBRG 69.0 1 20.9 1 0 0 0

2321 244166 05GALAX1 69.0 244182 05GALAX2 69.0 1 -15.7 1 0 0 0

2437 244428 05MCCLUNG 69.0 244429 05MC ROSS 69.0 1 10.0 1 0 0 0

2814 245247 05SCIO 69.0 247459 05ADOBE SS 69.0 1 -2.0 1 0 0 0

2883 245392 05CROOKS 1 69.0 245401 05MCLUNEYS 69.0 1 33.2 1 0 0 0

s744241

Contingencies that MUST couldn't solve listed - identified as 138 and 69 kV facilities remote from OVEC.

C-- 9 -

2897 245405 05NEW LEXN 69.0 245419 05OXFORDMN 69.0 1 -29.9 1 0 0 0

2912 245430 05N MCNLSV 69.0 245434 05S ROKEBY 69.0 1 -2.3 1 0 0 0

2914 245431 05N MUSKNG 69.0 245432 05NELYSVIL 69.0 1 13.7 1 0 0 0

3130 245692 05DUNKIRK 69.0 245695 05FOREST 69.0 1 9.7 1 0 0 0

3380 246424 05BANGOR 69.0 246457 05HARTFORD 69.0 1 -16.1 1 0 0 0

3389 246437 05COLOMA Y 69.0 246454 05HAGAR 69.0 1 -22.0 1 0 0 0

3739 242792 05SCOTSV 138 314746 4BREMO 138 1 26.6 1 0 0 0

3811 246971 05THELM2 69.0 342343 2THELMA 69.0 1 35.2 1 0 0 0

5559 324268 4KNOB C 138 324284 4MILLCRK 138 1 -30.1 1 0 0 0

5560 324268 4KNOB C 138 324300 4POND C 138 1 15.2 1 0 0 0

5601 324300 4POND C 138 324311 4TIPTOP 138 1 15.1 1 0 0 0

C-- 10 -

Appendix C – Category B (P1, P2) results 2020 Summer Peak Category B

PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- SUN, NOV 29 2015 8:51 <COV000.0>


2020 SUMMER PEAK LOAD CASE, RF STUDY TRIAL 3

Case.File C:\Users\s744241\Downloads\OVEC working\OVEC 2015 assessment 2020 S Pk w DEOK gen updates+locked shunts_v33.sav

Subsys.File C:\Users\s744241\Downloads\OVEC working\other input data\ovec_15compl_inertia_2.sub

Monit.File C:\Users\s744241\Downloads\OVEC working\other input data\OVEC combo 2015.mon

Contin.File C:\Users\s744241\Downloads\OVEC working\other input data\ovec+adjacent_singles_15_2020 assess_inertia.con

Exclud.File none










Converged = 6535


Not Converged = 0

PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- SUN, NOV 29 2015 8:51 <BRV003.0>







Exclud.File none

s744241

Initial screening using MUST

C-- 11 -

2020 Summer Peak Category B – Continued PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- SUN, NOV 29 2015 8:58 <ACC003.0>




Subsys.File C:\Users\s744241\Downloads\OVEC working\other input

data\ovec_15compl_inertia_2.sub

Monit.File C:\Users\s744241\Downloads\OVEC working\other input data\OVEC combo

2015.mon


Exclud.File none


Contingency

Index Contingency OutageFl

LFStatu

s

Nite

r

Ovrl

d

Sev

Volt

g

Sev

WorstMis

m

150 242543 05AUSTIN 138 242859 05WYTHE2 138 1 -15.9 NotC_ND 0 498.00

191 242563 05BOXWD 138 242603 05CLIFFR 138 1 26.5 NotC_ND 0 498.00

359 242637 05FLATWO 138 242783 05RUTLED 138 1 -66.3 NotC_ND 0 498.00

426 242670 05HOLST2 138 242819 05SULVN 138 1 -8.4 NotC_ND 0 498.00

452 242683 05J.EARL 138 242755 05PIPERS 138 1 -13.7 NotC_ND 0 498.00

526 242727 05MULLEN 138 247113 05PIERSS 138 1 78.0 NotC_ND 0 498.00

632 242825 05TAMSM2 138 247113 05PIERSS 138 1 -77.7 NotC_ND 0 498.00

665 242858 05WYTHE1 138 244179 05WYTHE1EQ 999 1 34.5 NotC_ND 0 498.00

834 242964 05BOLIVA 138 243092 05SCANTO 138 1 -2.6 NotC_ND 0 498.00

1038 243056 05NEWCOM 138 243144 05WCAMBR 138 1 -68.6 NotC_ND 0 498.00

1058 243062 05NMUSKG 138 245431 05N MUSKNG 69.0 1 14.3 NotC_ND 0 498.00

2329 244166 05GALAX1 69.0 244182 05GALAX2 69.0 1 -16.0 NotC_ND 0 498.00

2331 244176 05WYTHE 1 69.0 244179 05WYTHE1EQ 999 1 -34.5 NotC_ND 0 498.00

2427 244420 05LAYLAND 69.0 244442 05PRINCE 69.0 1 -12.6 NotC_ND 0 498.00

2905 245430 05N MCNLSV 69.0 245434 05S ROKEBY 69.0 1 -3.1 NotC_ND 0 498.00

2907 245431 05N MUSKNG 69.0 245432 05NELYSVIL 69.0 1 13.5 NotC_ND 0 498.00

3103 245660 05E WILLAR 69.0 245679 05WILLARD 69.0 1 -0.5 NotC_ND 0 498.00

3104 245660 05E WILLAR 69.0 247465 05CONWAVE SS69.0 1 -6.9 NotC_ND 0 498.00

3112 245669 05N WILLAR 69.0 247465 05CONWAVE SS69.0 1 6.9 NotC_ND 0 498.00

s744241

Contingencies that MUST couldn't solve listed - identified as 138 and 69 kV facilities remote from OVEC

C-- 12 -

3140 245708 05N WALDO 69.0 245716 05WALDO 69.0 1 13.1 NotC_ND 0 498.00

3311 246141 05MCKINLEY 69.0 246146 05MCKIN5EQ 999 1 -19.2 NotC_ND 0 498.00

3423 246489 05SO.HAVEN 69.0 246498 05PHOENIXZ 69.0 1 -1.1 NotC_ND 0 498.00

3605 247015 05DESERTSS 69.0 247129 05CRIMMRD 69.0 1 24.1 NotC_ND 0 498.00

3734 242792 05SCOTSV 138 314746 4BREMO 138 1 -7.9 NotC_ND 0 498.00

3751 246971 05THELM2 69.0 342343 2THELMA 69.0 1 40.4 NotC_ND 0 498.00

4965 253070 09SIDNEY 69.0 253130 09CISCO 69.0 1 78.1 NotC_ND 0 498.00

5116 238623 02CLARK 138 253085 09URBANA 138 1 -59.7 NotC_ND 0 498.00

C-- 13 -

2020 Spring Light Load -- Category B

PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- FRI, NOV 27 2015 7:38 <COS000.0>

OVEC 2015 ASSESSMENT--2020 S LL MODEL, BASED ON 2014 SERIES

ERAG/MMWG SPR LL FINAL CASE+REM RET DEOK GENS+LK TOGLN SHNTS

Case.File C:\Users\s744241\Downloads\OVEC working\OVEC 2015 assessment 2020 Spr LL w DEOK gen rets+locked

shunts_v33.sav




Exclud.File none

Statistics on specified contingencies

Total specified contingencies: 6521

Total events : 6642

Total dispatch/move events : 1047

Active contingencies : 6484

Single Bran.Open - no islands: 0

Complex contingencies : 6484

Involving load adjustments : 0

Involving generat adjustments: 21

Causing separations : 1685

Imbalanced contingencies : 10

!!! There are no contingencies with violations

With violations (Pre or post): 0

Disabled due to data errors : 37

User excluded contingencies : 0

Contingency violations in the Initial case : 0

s744241

Initial screening using MUST

C-- 14 -

2020 Spring Light Load - Category B – continued PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- SUN, NOV 29 2015 13:03 <ACC003.0>



Case.File C:\Users\s744241\Downloads\OVEC working\OVEC 2015 assessment 2020 Spr LL w DEOK gen rets+locked shunts_v33.sav




Exclud.File none


Contingency

Index Contingency OutageFl LFStatus Niter

Ovrld

Sev

Voltg

Sev WorstMism

19 248000 06CLIFTY 345 324114 7TRIMBLE 345 1 -547.4 NotC_ND 2 618.82

56 242508 05AMOS 765 242893 05AMG3 26.0 3 -1013.2 NotC_ND 2 618.99

75 242514 05J.FERR 765 242520 05J.FERR 500 1 -302.3 NotC_ND 2 618.79

79 242516 05MOUNTN 765 242894 05MTG1 26.0 1 -1021.5 NotC_ND 2 619.01

159 242546 05BAILS1 138 242742 05PADFOR 138 1 44.0 NotC_ND 2 618.82

205 242566 05BROADF 138 242600 05CLAYPL 138 1 81.4 NotC_ND 2 618.82

282 242600 05CLAYPL 138 242766 05RICHLA 138 1 79.6 NotC_ND 2 618.82

289 242605 05CLNCHR 138 242606 05CLNLFD 138 1 62.0 NotC_ND 2 618.83

298 242606 05CLNLFD 138 242639 05FLETCH 138 1 48.0 NotC_ND 2 618.83

299 242606 05CLNLFD 138 242868 05CLNCHFLD 69.0 1 13.9 NotC_ND 2 618.82

367 242639 05FLETCH 138 242801 05SKEGGB 138 1 47.4 NotC_ND 2 618.83

415 242662 05HALES2 138 242804 05SOURWO 138 1 -41.5 NotC_ND 2 618.82

534 242729 05NAGEL 138 242849 05WKINGP 138 1 62.9 NotC_ND 2 618.83

544 242742 05PADFOR 138 247290 05HARMON 138 1 42.7 NotC_ND 2 618.82

594 242794 05SHACKM 138 247149 05WHITWD 138 1 -10.9 NotC_ND 2 618.82

605 242804 05SOURWO 138 247290 05HARMON 138 1 -41.8 NotC_ND 2 618.82

710 242922 05FLTLCK 765 242923 05GAVIN 765 1 -585.3 NotC_ND 2 618.63

711 242922 05FLTLCK 765 242928 05MARYSV 765 1 585.3 NotC_ND 2 618.62

s744241

contingencies MUST had solution issues. output from PSS/e run of these contingencies starts on p.41.

C-- 15 -

717 242923 05GAVIN 765 243186 05GVG1 26.0 1 -1029.4 NotC_ND 2 619.00

724 242925 05KAMMER 765 243188 05MLG1 26.0 1 -299.7 NotC_ND 2 618.94

725 242925 05KAMMER 765 246751 05VASSEL 765 1 125.0 NotC_ND 2 618.74

730 242928 05MARYSV 765 242939 05MARYSV 345 2 399.5 NotC_ND 2 618.76

734 242931 05BEVERL 345 242940 05MUSKNG 345 1 459.9 NotC_ND 2 618.66

736 242931 05BEVERL 345 247202 05WSHG1A 18.0 A -174.7 NotC_ND 2 618.86

775 242940 05MUSKNG 345 242941 05OHIOCT 345 1 250.3 NotC_ND 2 618.76

792 242946 05TIDD 345 243185 05CDG3 26.0 3 -349.6 NotC_ND 2 619.00

927 243008 05FREMCT 138 243009 05FRMNT 138 1 -129.1 NotC_ND 2 618.85


1173 243139 05WAGENH 138 243773 05LTV1 138 1 203.4 NotC_ND 2 618.74

1254 243205 05COOK 765 243215 05COOK 345 4 231.5 NotC_ND 2 618.76

1255 243205 05COOK 765 243441 05CKG2 26.0 2 -1059.0 NotC_ND 2 619.16

1256 243206 05DUMONT 765 243207 05GRNTWN 765 1 -164.7 NotC_ND 2 618.78

1260 243207 05GRNTWN 765 243208 05JEFRSO 765 1 -421.0 NotC_ND 2 618.64

1262 243209 05ROCKPT 765 243210 05SULLVA 765 1 94.1 NotC_ND 2 618.81

1265 243209 05ROCKPT 765 243442 05RKG1 26.0 1 -1013.4 NotC_ND 2 618.62

1275 243212 05BENTON 345 243215 05COOK 345 1 -240.3 NotC_ND 2 618.74

1283 243214 05COLNGW 345 243784 05S.BTLR 345 1 305.2 NotC_ND 2 618.97

1288 243215 05COOK 345 243440 05CKG1 26.0 1 -999.0 NotC_ND 2 619.06

1293 243217 05DEQUIN 345 246754 05FOWLER 345 1 -149.6 NotC_ND 2 618.77

1313 243226 05LAWBG1 345 243233 05TANNER 345 1 -279.7 NotC_ND 2 618.78

1326 243231 05ROB PK 345 243232 05SORENS 345 1 -254.9 NotC_ND 2 618.79

1330 243232 05SORENS 345 246999 05SORENS 765 1 -383.0 NotC_ND 2 618.74

2018 243671 05BEAVR1 138 243698 05MORGFK 138 1 14.8 NotC_ND 2 618.82

2891 245430 05N MCNLSV 69.0 245436 05W MALTA 69.0 1 -2.1 NotC_ND 2 618.82


2894 245432 05NELYSVIL 69.0 245436 05W MALTA 69.0 1 2.6 NotC_ND 2 618.82

3286 246182 05AUBURN 69.0 246201 05PROSSER 69.0 1 8.9 NotC_ND 2 618.82

3470 246751 05VASSEL 765 246752 05VASSEL 345 1 338.2 NotC_ND 2 618.79

3473 246754 05FOWLER 345 246756 05FRCS-2 345 1 -109.8 NotC_ND 2 618.78

3525 246929 05MADDOX 345 246930 05BLUECK 345 Z1 -68.8 NotC_ND 2 618.79

3526 246930 05BLUECK 345 246931 05BLUECK 115 1 -68.8 NotC_ND 2 618.79

3527 246931 05BLUECK 115 246932 05BLCKCS 115 1 -68.8 NotC_ND 2 618.79

C-- 16 -

3681 239070 02RICHLD 138 243029 05LCKWRD 138 1 28.5 NotC_ND 2 618.84

3685 239154 02W.FREM 138 243009 05FRMNT 138 1 174.0 NotC_ND 2 618.87

3700 242520 05J.FERR 500 306719 8ANTIOCH 500 1 -302.3 NotC_ND 2 618.79

3734 243212 05BENTON 345 256019 18PALISD 345 1 147.4 NotC_ND 2 618.76

3738 243215 05COOK 345 256019 18PALISD 345 2 211.2 NotC_ND 2 618.74

3755 243234 05TWIN B 345 256000 18ARGNTA 345 1 187.0 NotC_ND 2 618.69

3802 249565 08EBEND 345 251947 08EBND2 20.0 2 -509.3 NotC_ND 2 618.75

3833 249577 08ZIMER 345 249580 08ZIMERG 345 Z1 -1091.8 NotC_ND 2 618.73

3836 249580 08ZIMERG 345 251968 08ZIMRHP 26.0 1H -861.9 NotC_ND 2 618.75

5106 324018 1GHNT 2 22.0 324105 7GHENT 345 1 -389.5 NotC_ND 2 618.78

5216 324106 7HARDIN 345 324261 4HARDN 138 1 179.9 NotC_ND 2 618.83

6380 u|05AMOS 765 - 3 N/A NotC_ND 2 618.82

6381 u|05GAVIN 765 - 1 N/A NotC_ND 2 618.83

6382 u|05MOUNTN 765 - 1 N/A NotC_ND 2 618.83

6383 u|01PLEAS126.0 - 1 N/A NotC_ND 2 618.83

6384 u|1SPLK G2 22.0 - 2 N/A NotC_ND 2 618.82

6387 u|11MILC 422.0 - 4 N/A NotC_ND 2 618.82

6388 u|11SMTH 222.0 - 2 N/A NotC_ND 2 618.82

6389 u|11GHNT 118.0 - 1 N/A NotC_ND 2 618.82

6390 u|1CANERUN 718.0 - 7 CC N/A NotC_ND 2 618.82

6391 u|1CANERUN 718.0 - 7 STM only N/A NotC_ND 2 618.82

6392 u|08ZIMMER 1 N/A NotC_ND 2 618.82

6393 u|1TRIM 122.0 - 1 N/A NotC_ND 2 618.82

6394 u|1TRIM 220.9 - 1 N/A NotC_ND 2 618.82

6395 u|09KILLEN 345 - 2 N/A NotC_ND 2 618.82

6397 u|06CLIFTY 345 - 1 N/A NotC_ND 2 618.82

6398 u|06KYGER 345FGD N/A NotC_ND 2 618.82

6399 u|06CLIFTY 345FGD123 N/A NotC_ND 2 618.82


6408 05DUMONT 765 - 05GRNTWN 765 - 1 -164.7 NotC_ND 2 618.78

6412 05FLTLCK 765 - 05GAVIN 765 - 1 -585.3 NotC_ND 2 618.63

6413 05FLTLCK 765 - 05MARYSV 765 - 1 585.3 NotC_ND 2 618.62

6415 05GRNTWN 765 - 05JEFRSO 765 - 1 -421.0 NotC_ND 2 618.64

6418 05KAMMER 765 - 05VASSEL 765 - 1 125.0 NotC_ND 2 618.74

C-- 17 -

6422 05BEVERL 345 - 05MUSKNG 345 - 1 459.9 NotC_ND 2 618.66

6440 05TANNER-06DEARB1-06CLIFTY-06PIERCE-345 N/A NotC_ND 2 618.78

6474 06CLIFTY 345 - 7TRIMBLE 345 - 1 -547.4 NotC_ND 2 618.82

6488 05MARYSV-02TANGY-765-345 N/A NotC_ND 2 618.76

C-- 18 -

2020 Spring Light Load - Category B – continued PSS/E activity ACCC used to check MUST “NotC_ND” results ACCC OVERLOAD REPORT: MONITORED BRANCHES AND INTERFACES LOADED ABOVE 100.0 % OF RATING SET A (BASE CASE) OR B (CONTINGENCY CASES) % LOADING VALUES ARE % MVA FOR TRANSFORMERS AND % CURRENT FOR NON-TRANSFORMER BRANCHES CONTINGENCY CASE LOADING NOT CHECKED UNLESS IT DIFFERS FROM ITS BASE CASE LOADING BY 2.0 MVA (MW FOR INTERFACES) ACCC VOLTAGE REPORT: VOLTAGE BAND CHECK IN CONTINGENCY CASES SKIPPED FOR ANY BUS WITHIN 0.03000 OF ITS BASE CASE VOLTAGE MAGNITUDE VOLTAGE LIMITS USE NORMAL (BASE CASE) OR EMERGENCY (CONTINGENCY CASES) AC CONTINGENCY RESULTS FILE: U:\JHR_02-20-2013\JHR\OVEC\2015\OVEC working\2020 Spr LL MUST V collapse confirmation in PSS.acc DISTRIBUTION FACTOR FILE: U:\JHR_02-20-2013\JHR\OVEC\2015\OVEC working\other input data\2020Spr LL.dfx SUBSYSTEM DESCRIPTION FILE: U:\JHR_02-20-2013\JHR\OVEC\2015\OVEC working\other input data\ovec_15compl_inertia_2.sub MONITORED ELEMENT FILE: U:\JHR_02-20-2013\JHR\OVEC\2015\OVEC working\other input data\OVEC combo 2015.mon CONTINGENCY DESCRIPTION FILE: U:\JHR_02-20-2013\JHR\OVEC\2015\OVEC working\other input data\OVEC 2015 assessment 2020 Spr LL - v collapse singles.con **PERCENT LOADING UNITS** %MVA FOR TRANSFORMERS % I FOR NON-TRANSFORMER BRANCHES **OPTIONS USED IN CONTINGENCY ANALYSIS** Solution engine: Fixed slope decoupled Newton-Raphson (FDNS) Solution options Tap adjustment: Lock taps Area interchange control: Disable

s744241

PSS/E used to check contingencies MUST couldn't solve

C-- 19 -

Phase shift adjustment: Disable Dc tap adjustment: Enable Switch shunt adjustment: Enable all Induction motor treatment: Stall Induction machine failure: Treat contingency as non-converged Non diverge: Disable Mismatch tolerance (MW ): 0.5 Dispatch mode: Disable <----------------- MONITORED BRANCH -----------------> <----- CONTINGENCY LABEL ------> RATING FLOW % MONITORED VOLTAGE REPORT: SYSTEM <----- CONTINGENCY LABEL ------> <-------- B U S --------> V-CONT V-INIT V-MAX V-MIN MONITORED VOLTAGE LIMIT REPORT: <-------- B U S --------> <----- CONTINGENCY LABEL ------> V-CONT V-INIT V-MAX V-MIN LOSS OF LOAD REPORT: <-------- B U S --------> <----- CONTINGENCY LABEL ------> LOAD(MW) <----- CONTINGENCY LABEL ------><----- POST-CONTINGENCY SOLUTION -----> <TERMINATION STATE> FLOW# VOLT# LOAD BASE CASE Met convergence to 0 0 0.0 248000 06CLIFTY 345 324114 7 Met convergence to 0 0 0.0 242508 05AMOS 765 242893 0 Iteration limit ex -- -- -- 242514 05J.FERR 765 242520 0 Met convergence to 0 0 0.0 242516 05MOUNTN 765 242894 0 Met convergence to 0 0 0.0 242546 05BAILS1 138 242742 0 Met convergence to 0 0 0.0 242566 05BROADF 138 242600 0 Met convergence to 0 0 0.0 242600 05CLAYPL 138 242766 0 Met convergence to 0 0 0.0 242605 05CLNCHR 138 242606 0 Iteration limit ex -- -- --

C-- 20 -

242606 05CLNLFD 138 242639 0 Met convergence to 0 0 0.0 242606 05CLNLFD 138 242868 0 Iteration limit ex -- -- -- 242639 05FLETCH 138 242801 0 Met convergence to 0 0 0.0 242662 05HALES2 138 242804 0 Met convergence to 0 0 0.0 242729 05NAGEL 138 242849 0 Iteration limit ex -- -- -- 242742 05PADFOR 138 247290 0 Met convergence to 0 0 0.0 242794 05SHACKM 138 247149 0 Met convergence to 0 0 0.0 242804 05SOURWO 138 247290 0 Met convergence to 0 0 0.0 242922 05FLTLCK 765 242923 0 Iteration limit ex -- -- -- 242922 05FLTLCK 765 242928 0 Iteration limit ex -- -- -- 242923 05GAVIN 765 243186 0 Met convergence to 0 0 0.0 242925 05KAMMER 765 243188 0 Met convergence to 0 0 0.0 242925 05KAMMER 765 246751 0 Met convergence to 0 0 0.0 242928 05MARYSV 765 242939 0 Met convergence to 0 0 0.0 242931 05BEVERL 345 242940 0 Met convergence to 0 0 0.0 242931 05BEVERL 345 247202 0 Iteration limit ex -- -- -- 242940 05MUSKNG 345 242941 0 Met convergence to 0 0 0.0 242946 05TIDD 345 243185 0 Iteration limit ex -- -- -- 243008 05FREMCT 138 243009 0 Met convergence to 0 0 0.0 243062 05NMUSKG 138 245431 0 Iteration limit ex -- -- -- 243139 05WAGENH 138 243773 0 Met convergence to 0 0 203.2 243205 05COOK 765 243215 0 Met convergence to 0 0 0.0 243205 05COOK 765 243441 0 Iteration limit ex -- -- -- 243206 05DUMONT 765 243207 0 Met convergence to 0 0 0.0 243207 05GRNTWN 765 243208 0 Met convergence to 0 0 0.0 243209 05ROCKPT 765 243210 0 Met convergence to 0 0 0.0 243209 05ROCKPT 765 243442 0 Iteration limit ex -- -- -- 243212 05BENTON 345 243215 0 Met convergence to 0 0 0.0 243214 05COLNGW 345 243784 0 Met convergence to 0 0 304.8 243215 05COOK 345 243440 0 Iteration limit ex -- -- -- 243217 05DEQUIN 345 246754 0 Met convergence to 0 0 0.0 243226 05LAWBG1 345 243233 0 Iteration limit ex -- -- --

C-- 21 -

243231 05ROB PK 345 243232 0 Met convergence to 0 0 0.0 243232 05SORENS 345 246999 0 Met convergence to 0 0 0.0 243671 05BEAVR1 138 243698 0 Iteration limit ex -- -- -- 245430 05N MCNLSV 69.0 245436 0 Iteration limit ex -- -- -- 245431 05N MUSKNG 69.0 245432 0 Iteration limit ex -- -- -- 245432 05NELYSVIL 69.0 245436 0 Iteration limit ex -- -- -- 246182 05AUBURN 69.0 246201 0 Iteration limit ex -- -- -- 246751 05VASSEL 765 246752 0 Met convergence to 0 0 0.0 246754 05FOWLER 345 246756 0 Met convergence to 0 0 0.0 246929 05MADDOX 345 246930 0 Met convergence to 0 0 0.0 246930 05BLUECK 345 246931 0 Met convergence to 0 0 0.0 246931 05BLUECK 115 246932 0 Met convergence to 0 0 0.0 239070 02RICHLD 138 243029 0 Iteration limit ex -- -- -- 239154 02W.FREM 138 243009 0 Iteration limit ex -- -- -- 242520 05J.FERR 500 306719 8 Met convergence to 0 0 0.0 243212 05BENTON 345 256019 1 Met convergence to 0 0 0.0 243215 05COOK 345 256019 1 Met convergence to 0 0 0.0 243234 05TWIN B 345 256000 1 Met convergence to 0 0 0.0 249565 08EBEND 345 251947 0 Iteration limit ex -- -- -- 249577 08ZIMER 345 249580 0 Iteration limit ex -- -- -- 249580 08ZIMERG 345 251968 0 Iteration limit ex -- -- -- 324018 1GHNT 2 22.0 324105 7 Iteration limit ex -- -- -- 324106 7HARDIN 345 324261 4 Met convergence to 0 0 0.0 U|05AMOS 765 - 3 Iteration limit ex -- -- -- U|05GAVIN 765 - 1 Iteration limit ex -- -- -- U|05MOUNTN 765 - 1 Iteration limit ex -- -- -- U|01PLEAS126.0 - 1 Met convergence to 0 0 0.0 U|1SPLK G2 22.0 - 2 Met convergence to 0 0 0.0 U|11MILC 422.0 - 4 Met convergence to 0 0 0.0 U|11GHNT 118.0 - 1 Met convergence to 0 0 0.0 U|1CANERUN 718.0 - 7 CC Met convergence to 0 0 0.0 U|1CANERUN 718.0 - 7 STM ONLY Met convergence to 0 0 0.0

C-- 22 -

U|08ZIMMER 1 Iteration limit ex -- -- -- U|1TRIM 122.0 - 1 Met convergence to 0 0 0.0 U|1TRIM 220.9 - 1 Met convergence to 0 0 0.0 U|09KILLEN 345 - 2 Met convergence to 0 0 0.0 U|06CLIFTY 345 - 1 Met convergence to 0 0 0.0 U|06KYGER 345FGD Met convergence to 0 0 0.0 U|06CLIFTY 345FGD123 Met convergence to 0 0 0.0 U|06CLIFTY 345FGD456 Met convergence to 0 0 0.0 05TANNER-06DEARB1-06CLIFTY-06PIE Met convergence to 0 0 0.0 05MARYSV-02TANGY-765-345 Met convergence to 0 0 0.0 CONTINGENCY LEGEND: <----- CONTINGENCY LABEL ------> EVENTS 243139 05WAGENH 138 243773 0: OPEN BRANCH FROM BUS 243139 [05WAGENH 138.00] TO BUS 243773 [05LTV1 138.00] CKT 1 243214 05COLNGW 345 243784 0: OPEN BRANCH FROM BUS 243214 [05COLNGW 345.00] TO BUS 243784 [05S.BTLR 345.00] CKT 1 Appendix C – Category C (P3 – P7) results 2016 Summer Peak Category C Results PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- TUE, NOV 24 2015 8:13

<COV000.0>



Case.File C:\Users\s744241\Downloads\OVEC working\OVEC 2015 assessment 2016 S Peak_post RF

updates_v33.sav



Contin.File U:\JHR_02-20-2013\JHR\OVEC\2015\other input data\subdblcont_15 v1 assessment.con

Exclud.File none


s744241

Initial MUST screening

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PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- TUE, NOV 24 2015 8:14 <BRV003.0>







Exclud.File none

************** Report on violations

********************






I Initial Violations I

I Base Case I Contingency cases I

Constraint I Numb. Worst I Numb. Worst Contin I

Type I Viol Viol I Viol Viol Number I

MVA flow I - --- 1 0.3 1067 I

Number of contingencies with violations: 1


Total No. tested =12481 Total LF iterations 68880

Converged =12478


Not Converged = 0

2016 Summer Peak Category C Results - Continued

C-- 24 -

Branches with MVA flow more than 100.0 % of nominal rating

** From bus ** ** To bus ** CKT Type ContMVA BaseFlow Rating Loading% Ncon Contingency Descri

248009 06CLIFTY 138 250057 08M.FORT 138 1 LN 129.3 82.3 129.0 100.2 1067 D:05TANNER-08M.FTHS1 +08EBE

2016 Summer Peak Category C Results - Continued PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- TUE, NOV 24 2015 7:51 <ACC003.0>







Exclud.File none


s744241

identification of contingencies MUST had problems solving - outages of large generators, appears to be related to conditions near slack bus, not OVEC

C-- 25 -

Contingency


Ovrld

Sev

Voltg

Sev WorstMism

2964 D:05MOUNTN-05MTG1 1 +05GAVIN -05GVG1 1 N/A NotC_ND 0 6969601 939.61

2965 D:05MOUNTN-05MTG1 1 +05GAVIN -05GVG2 2 N/A NotC_ND 0 6864401 928.51

5260 D:05GAVIN -05GVG1 1 +05GAVIN -05GVG2 2 N/A NotC_ND 0 6864401 928.93

Appendix C 2020 Summer Peak Category C Results

PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- SUN, NOV 29 2015 9:43 <COV000.0>






Contin.File C:\Users\s744241\Downloads\OVEC working\other input data\subdblcont_15 v1 assessment_2020 S.con

Exclud.File none






Total No. tested =12397 Total LF iterations 80261

Converged =12394


Not Converged = 0

s744241


C-- 26 -

Appendix C 2020 Summer Peak Category C Results - Continued PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- SUN, NOV 29 2015 9:45 <ACC003.0>






Contin.File C:\Users\s744241\Downloads\OVEC working\other input data\subdblcont_15 v1 assessment_2020 S.con

Exclud.File none


Contingency


Ovrld

Sev

Voltg

Sev WorstMism

7099 D:05MOUNTN-05MTG1 1 +05GAVIN -05GVG1 1 N/A NotC_ND 0 6969601 1 6.65

12380 d|08COLMBU-08GALAGH-08PUMPCT-230 N/A NotC_ND 0 437.61

12381 d|08COLMBU-08GALAGH-08PUMPCT-230n2 N/A NotC_ND 0 437.62

s744241

Identification of contingencies MUST had difficulty solving - pair of large generator outages and pair of 230 kV outages some distance from OVEC. No problems created on OVEC facilities.

C-- 27 -

2020 Spring Light Load Category C Results

PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- FRI, NOV 27 2015 7:30 <COV000.0>



Case.File C:\Users\s744241\Downloads\OVEC working\OVEC 2015 assessment 2020 Spr LL w DEOK gen rets+locked

shunts_v33.sav




Exclud.File none










Converged = 6394


Not Converged = 0

s744241


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2020 Spring Light Load - Category C Results – Continued PSS(R)MUST 11.2.2 -- Managing and Utilizing System Transmission -- SUN, NOV 29 2015 13:03 <ACC003.0>



Case.File C:\Users\s744241\Downloads\OVEC working\OVEC 2015 assessment 2020 Spr LL w DEOK gen rets+locked shunts_v33.sav




Exclud.File none


Contingency


Ovrld

Sev

Voltg

Sev WorstMism

19 248000 06CLIFTY 345 324114 7TRIMBLE 345 1 -547.4 NotC_ND 2 618.82

56 242508 05AMOS 765 242893 05AMG3 26.0 3 -1013.2 NotC_ND 2 618.99

75 242514 05J.FERR 765 242520 05J.FERR 500 1 -302.3 NotC_ND 2 618.79

79 242516 05MOUNTN 765 242894 05MTG1 26.0 1 -1021.5 NotC_ND 2 619.01

159 242546 05BAILS1 138 242742 05PADFOR 138 1 44.0 NotC_ND 2 618.82

205 242566 05BROADF 138 242600 05CLAYPL 138 1 81.4 NotC_ND 2 618.82

282 242600 05CLAYPL 138 242766 05RICHLA 138 1 79.6 NotC_ND 2 618.82

289 242605 05CLNCHR 138 242606 05CLNLFD 138 1 62.0 NotC_ND 2 618.83

298 242606 05CLNLFD 138 242639 05FLETCH 138 1 48.0 NotC_ND 2 618.83

299 242606 05CLNLFD 138 242868 05CLNCHFLD 69.0 1 13.9 NotC_ND 2 618.82

367 242639 05FLETCH 138 242801 05SKEGGB 138 1 47.4 NotC_ND 2 618.83

415 242662 05HALES2 138 242804 05SOURWO 138 1 -41.5 NotC_ND 2 618.82

534 242729 05NAGEL 138 242849 05WKINGP 138 1 62.9 NotC_ND 2 618.83

544 242742 05PADFOR 138 247290 05HARMON 138 1 42.7 NotC_ND 2 618.82

594 242794 05SHACKM 138 247149 05WHITWD 138 1 -10.9 NotC_ND 2 618.82

605 242804 05SOURWO 138 247290 05HARMON 138 1 -41.8 NotC_ND 2 618.82

710 242922 05FLTLCK 765 242923 05GAVIN 765 1 -585.3 NotC_ND 2 618.63

711 242922 05FLTLCK 765 242928 05MARYSV 765 1 585.3 NotC_ND 2 618.62

717 242923 05GAVIN 765 243186 05GVG1 26.0 1 -1029.4 NotC_ND 2 619.00

s744241

identification of contingencies MUST had trouble solving

C-- 29 -

724 242925 05KAMMER 765 243188 05MLG1 26.0 1 -299.7 NotC_ND 2 618.94

725 242925 05KAMMER 765 246751 05VASSEL 765 1 125.0 NotC_ND 2 618.74

730 242928 05MARYSV 765 242939 05MARYSV 345 2 399.5 NotC_ND 2 618.76

734 242931 05BEVERL 345 242940 05MUSKNG 345 1 459.9 NotC_ND 2 618.66

736 242931 05BEVERL 345 247202 05WSHG1A 18.0 A -174.7 NotC_ND 2 618.86

775 242940 05MUSKNG 345 242941 05OHIOCT 345 1 250.3 NotC_ND 2 618.76

792 242946 05TIDD 345 243185 05CDG3 26.0 3 -349.6 NotC_ND 2 619.00

927 243008 05FREMCT 138 243009 05FRMNT 138 1 -129.1 NotC_ND 2 618.85


1173 243139 05WAGENH 138 243773 05LTV1 138 1 203.4 NotC_ND 2 618.74

1254 243205 05COOK 765 243215 05COOK 345 4 231.5 NotC_ND 2 618.76

1255 243205 05COOK 765 243441 05CKG2 26.0 2 -1059.0 NotC_ND 2 619.16

1256 243206 05DUMONT 765 243207 05GRNTWN 765 1 -164.7 NotC_ND 2 618.78

1260 243207 05GRNTWN 765 243208 05JEFRSO 765 1 -421.0 NotC_ND 2 618.64

1262 243209 05ROCKPT 765 243210 05SULLVA 765 1 94.1 NotC_ND 2 618.81

1265 243209 05ROCKPT 765 243442 05RKG1 26.0 1 -1013.4 NotC_ND 2 618.62

1275 243212 05BENTON 345 243215 05COOK 345 1 -240.3 NotC_ND 2 618.74

1283 243214 05COLNGW 345 243784 05S.BTLR 345 1 305.2 NotC_ND 2 618.97

1288 243215 05COOK 345 243440 05CKG1 26.0 1 -999.0 NotC_ND 2 619.06

1293 243217 05DEQUIN 345 246754 05FOWLER 345 1 -149.6 NotC_ND 2 618.77

1313 243226 05LAWBG1 345 243233 05TANNER 345 1 -279.7 NotC_ND 2 618.78

1326 243231 05ROB PK 345 243232 05SORENS 345 1 -254.9 NotC_ND 2 618.79

1330 243232 05SORENS 345 246999 05SORENS 765 1 -383.0 NotC_ND 2 618.74

2018 243671 05BEAVR1 138 243698 05MORGFK 138 1 14.8 NotC_ND 2 618.82

2891 245430 05N MCNLSV 69.0 245436 05W MALTA 69.0 1 -2.1 NotC_ND 2 618.82


2894 245432 05NELYSVIL 69.0 245436 05W MALTA 69.0 1 2.6 NotC_ND 2 618.82

3286 246182 05AUBURN 69.0 246201 05PROSSER 69.0 1 8.9 NotC_ND 2 618.82

3470 246751 05VASSEL 765 246752 05VASSEL 345 1 338.2 NotC_ND 2 618.79

3473 246754 05FOWLER 345 246756 05FRCS-2 345 1 -109.8 NotC_ND 2 618.78

3525 246929 05MADDOX 345 246930 05BLUECK 345 Z1 -68.8 NotC_ND 2 618.79

3526 246930 05BLUECK 345 246931 05BLUECK 115 1 -68.8 NotC_ND 2 618.79

3527 246931 05BLUECK 115 246932 05BLCKCS 115 1 -68.8 NotC_ND 2 618.79

3681 239070 02RICHLD 138 243029 05LCKWRD 138 1 28.5 NotC_ND 2 618.84

C-- 30 -

3685 239154 02W.FREM 138 243009 05FRMNT 138 1 174.0 NotC_ND 2 618.87

3700 242520 05J.FERR 500 306719 8ANTIOCH 500 1 -302.3 NotC_ND 2 618.79

3734 243212 05BENTON 345 256019 18PALISD 345 1 147.4 NotC_ND 2 618.76

3738 243215 05COOK 345 256019 18PALISD 345 2 211.2 NotC_ND 2 618.74

3755 243234 05TWIN B 345 256000 18ARGNTA 345 1 187.0 NotC_ND 2 618.69

3802 249565 08EBEND 345 251947 08EBND2 20.0 2 -509.3 NotC_ND 2 618.75

3833 249577 08ZIMER 345 249580 08ZIMERG 345 Z1 -1091.8 NotC_ND 2 618.73

3836 249580 08ZIMERG 345 251968 08ZIMRHP 26.0 1H -861.9 NotC_ND 2 618.75

5106 324018 1GHNT 2 22.0 324105 7GHENT 345 1 -389.5 NotC_ND 2 618.78

5216 324106 7HARDIN 345 324261 4HARDN 138 1 179.9 NotC_ND 2 618.83

6380 u|05AMOS 765 - 3 N/A NotC_ND 2 618.82

6381 u|05GAVIN 765 - 1 N/A NotC_ND 2 618.83

6382 u|05MOUNTN 765 - 1 N/A NotC_ND 2 618.83

6383 u|01PLEAS126.0 - 1 N/A NotC_ND 2 618.83

6384 u|1SPLK G2 22.0 - 2 N/A NotC_ND 2 618.82

6387 u|11MILC 422.0 - 4 N/A NotC_ND 2 618.82

6388 u|11SMTH 222.0 - 2 N/A NotC_ND 2 618.82

6389 u|11GHNT 118.0 - 1 N/A NotC_ND 2 618.82

6390 u|1CANERUN 718.0 - 7 CC N/A NotC_ND 2 618.82

6391 u|1CANERUN 718.0 - 7 STM only N/A NotC_ND 2 618.82

6392 u|08ZIMMER 1 N/A NotC_ND 2 618.82

6393 u|1TRIM 122.0 - 1 N/A NotC_ND 2 618.82

6394 u|1TRIM 220.9 - 1 N/A NotC_ND 2 618.82

6395 u|09KILLEN 345 - 2 N/A NotC_ND 2 618.82

6397 u|06CLIFTY 345 - 1 N/A NotC_ND 2 618.82

6398 u|06KYGER 345FGD N/A NotC_ND 2 618.82



6408 05DUMONT 765 - 05GRNTWN 765 - 1 -164.7 NotC_ND 2 618.78

6412 05FLTLCK 765 - 05GAVIN 765 - 1 -585.3 NotC_ND 2 618.63

6413 05FLTLCK 765 - 05MARYSV 765 - 1 585.3 NotC_ND 2 618.62

6415 05GRNTWN 765 - 05JEFRSO 765 - 1 -421.0 NotC_ND 2 618.64

6418 05KAMMER 765 - 05VASSEL 765 - 1 125.0 NotC_ND 2 618.74

6422 05BEVERL 345 - 05MUSKNG 345 - 1 459.9 NotC_ND 2 618.66

C-- 31 -

6440 05TANNER-06DEARB1-06CLIFTY-06PIERCE-345 N/A NotC_ND 2 618.78

6474 06CLIFTY 345 - 7TRIMBLE 345 - 1 -547.4 NotC_ND 2 618.82

6488 05MARYSV-02TANGY-765-345 N/A NotC_ND 2 618.76

C-- 32 -

2020 Spring Light Load - Category C Results – Continued PSS/E activity ACCC used to check MUST “NotC_ND” results

Label Converged Maximum Bus Mismatch System Mismatch Solution termination state Flow Violations # Flow Violations Largest % Low Range Violations # Low Range Violations Largest High Range Violations # High Range Violations Largest Deviation Violations # Deviation Violations Largest # Disconnect Island Buses Seq # BASE CASE 1 0.26 0.78 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 0 1 D:06CLIFTY-06CLIFTX1A+ B$1658 MILL CRK 5 1 0.25 0.64 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 2 D:06CLIFTY-06CLIFTX1A+ B$1659 MILL CRK 6 1 0.25 0.64 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 3 D:06CLIFTX-06CLIFTYSR+ B$1659 MILL CRK 6 1 0.25 0.63 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 4 D:05BAKER -05CULLOD1 +05GAVIN -05GVG1 1 0 19.30 22.04 ITERATION LIMIT EXCEEDED 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 5 D:05CULLOD-05GAVIN 1 +06PIERCE-08PRCE1818 1 0.02 0.17 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 0 6 D:05MOUNTN-05MTG1 1 +05GAVIN -05GVG1 1 1 0.44 1.69 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 7 D:05MOUNTN-05MTG1 1 +05MALIS -05MARYSV1 1 0.38 2.63 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 8 D:05MOUNTN-05MTG1 1 +05BEVERL-05HOLLOW1 1 0.39 2.64 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 9 D:05MOUNTN-05MTG1 1 +05MARYSV-09DAYMRY1 1 0.39 2.63 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 10 D:05MOUNTN-05MTG1 1 +05LAWBG1-05TANNER1 1 0.44 2.84 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 4 11 D:05MOUNTN-05MTG1 1 +05TANNER-16HANNA 1 1 0.40 2.67 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 12

s744241

PSS/e used to examine contingencies MUST had problems solving

C-- 33 -

D:05MOUNTN-05MTG1 1 +08EBEND -08EBND2 2 1 0.34 2.22 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 13 D:05MOUNTN-05MTG1 1 +1TRIM 1 -7TRIMBLE1 1 0.35 2.52 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 14 D:05MOUNTN-05MTG1 1 +1TRIM 2 -7TRIMBLE1 1 0.44 2.68 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 15 D:05SPORN -05TRISTA1 + B$1658 MILL CRK 5 1 0.22 0.60 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 16 D:05SPORN -05TRISTA1 + B$1659 MILL CRK 6 1 0.22 0.60 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 17 D:05GAVIN -05GVG1 1 +05HANG R-05JEFRSO1 1 0.38 2.60 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 18 D:05GAVIN -05GVG1 1 +05BEVERL-05HOLLOW1 1 0.40 2.71 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 19 D:05GAVIN -05GVG1 1 +05KAMMER-05MUSKNG1 1 0.40 2.71 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 20 D:05GAVIN -05GVG1 1 +05MARYSV-09DAYMRY1 1 0.40 2.71 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 21 D:05GAVIN -05GVG1 1 +05LAWBG1-05TANNER1 1 0.41 2.50 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 4 22 D:05GAVIN -05GVG1 1 +06CLIFTY-4CARROLT1 1 0.40 2.70 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 23 D:05GAVIN -05GVG1 1 +08EBEND -08EBND2 2 1 0.40 2.02 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 24 D:05GAVIN -05GVG1 1 + B$0631 BKJ GT21 21 1 0.40 2.70 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 25 D:05GAVIN -05GVG1 1 +1TRIM 1 -7TRIMBLE1 1 0.42 2.08 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 26 D:05GAVIN -05GVG1 1 +1TRIM 2 -7TRIMBLE1 1 0.44 1.66 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 27

C-- 34 -

D:05MARYSV-09DAYMRY1 +1TRIM 2 -7TRIMBLE1 0 8.71 9.98 ITERATION LIMIT EXCEEDED 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 28 D:05BIXBY -05BIXBY 1 +08BUFTN1-BUFTON 21 1 0.25 0.99 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 29 D:05BIXBY -05BIXBY 1 +08BUFTN1-BUFTON 77 1 0.25 0.99 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 30 D:05BIXBY -05BIXBY 2 +08BUFTN1-BUFTON 21 1 0.25 0.97 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 31 D:05BIXBY -05BIXBY 2 +08BUFTN1-BUFTON 77 1 0.25 0.98 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 32 D:06PIERCE-08PIERCE17+08BUFTN1-08BUFTN22 0 2.45 14.20 ITERATION LIMIT EXCEEDED 0 0.00 0 0.0000 0 0.0000 0 0.0000 0 33 D:08FOSTER-08TDHNTR1 +08BUFTN1-BUFTON 21 1 0.26 0.68 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 34 D:08FOSTER-08TDHNTR1 +08BUFTN1-BUFTON 77 1 0.26 0.68 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 35 D:08TERMNL-08TRMNL21 +08BUFTN1-BUFTON 77 1 0.25 0.96 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 36 D:08BKJ135-08PIERCE1 +08BUFTN1-08BUFTN22 0 0.63 11.95 ITERATION LIMIT EXCEEDED 0 0.00 0 0.0000 0 0.0000 0 0.0000 0 37 D:08BUFTN1-08EKPWEB1 +08BUFTN1-08BUFTN22 0 0.74 12.55 ITERATION LIMIT EXCEEDED 0 0.00 0 0.0000 0 0.0000 0 0.0000 0 38 D:08BUFTN1-BUFTON 21 +7GHENT -7NAS 1 1 0.25 0.66 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 39 D:08BUFTN1-BUFTON 77 +7GHENT -7NAS 1 1 0.25 0.66 MET CONVERGENCE TOLERANCE 0 0.00 0 0.0000 0 0.0000 0 0.0000 1 40

Appendix D


2014 Short Circuit Assessment


November 2015

2015 OVEC Short Circuit Study (continued)

D-2

The 2015 OVEC Short Circuit Assessment

The OVEC short circuit assessment is based on studies conducted in 2015. Those studies were performed using

v12.4 of the Aspen OneLinerTM program including the ASPEN Breaker Rating ModuleTM. The study was based on

the latest available AEP/PJM model at the time the study was conducted with the OVEC circuit breaker data* added.

The results of the study are summarized in the tables included as Attachment A. Due to recent and imminent

generation retirements, the previous studies performed in 2013 are judged to be both sufficient and conservative

measures of the expected short circuit interrupting duties relative to the capability of the planned circuit breakers.

Those studies show that no OVEC circuit breakers are expected to be called upon to interrupt fault currents in excess

of their capability. Twenty-seven breakers were found to have interrupting duties above 80% of their capability, with

the highest at 87.5% of capability. The lowest margins were found at Pierce.

Note that these results are expected to be somewhat conservative (i.e., overstate the actual fault currents to be

reasonably expected in 2019.) This is because some of the generating units already retired or expected to be retired

in neighboring systems may still be modeled as in service. Under the terms of the applicable tariff, the owner of a

unit that has requested deactivation has up to one year from the actual date of deactivation to apply to reuse their

connection rights. To prevent “overselling” connection rights, the impact of the retiring units needs to be included

until those rights have expired. While some of these rights may be re-used, it appears unlikely that they all will be.

*Breaker characteristics utilized for Circuit Breakers located within the OVEC Balancing Authority Area, but owned

by others, reflect the best information available at the time of this study. Results documented here are provided for

the benefit of the equipment owner to make their own determination as to the adequacy of the breaker interrupting

capabilities. The equipment owner bears ultimate responsibility to ensure that the equipment continues to be

suitable for the application, including any applicable NERC Reliability Standard Compliance requirements.


BUS BREAKER

DUTY

%

DUTY

MPS

BREAKER

CAPABILITY

MOMENTARY

DUTY %

MOMENTARY

DUTY AMPS

MOMENTARY

BREAKER

CAPABILITY ISC X/R

06CLIFTY 138.kV AC 41.9 16764.3 40000 23.9 24835 104000 15057.5 41.7

06CLIFTY 138.kV AD 38.2 15289.6 40000 21.6 22459.2 104000 13567.8 45.1

06CLIFTY 138.kV AE 43.4 17358.6 40000 24.8 25831 104000 15692.1 40.1

06CLIFTY 345.kV A 83.5 53435.1 64000 49.4 82161.8 166400 49025.5 27.5

06CLIFTY 345.kV B 83.5 53435.1 64000 48 79849.8 166400 49025.5 27.5

06CLIFTY 345.kV C 79.9 51106.7 64000 49.4 82161.8 166400 51106.7 27

06CLIFTY 345.kV D 83.5 53435.1 64000 49.4 82161.8 166400 49025.5 27.5

06CLIFTY 345.kV DL 89.2 51106.9 57300 55.1 82162.1 148980 51106.9 27

06CLIFTY 345.kV DL1 89.2 51106.9 57300 55.1 82162.1 148980 51106.9 27

06CLIFTY 345.kV DL2 89.2 51106.7 57300 55.1 82161.8 148980 51106.7 27

06CLIFTY 345.kV E 83.5 53435.1 64000 48 79849.8 166400 49025.5 27.5

06CLIFTY 345.kV F 79.9 51106.7 64000 49.4 82161.8 166400 51106.7 27

06CLIFTY 345.kV G 83.3 53297.7 64000 49.4 82161.8 166400 48883.3 27.6

06CLIFTY 345.kV H 83.3 53297.7 64000 47.9 79688.6 166400 48883.3 27.6

06CLIFTY 345.kV I 79.9 51106.7 64000 49.4 82161.8 166400 51106.7 27

06CLIFTY 345.kV J 79.9 51106.7 64000 49.4 82161.8 166400 51106.7 27

06CLIFTY 345.kV K 79.3 50776.6 64000 48 79830.4 166400 46332.6 28.4

06CLIFTY 345.kV L 79.9 51106.7 64000 49.4 82161.8 166400 51106.7 27

06CLIFTY 345.kV M 79.9 51106.7 64000 49.4 82161.8 166400 51106.7 27

06CLIFTY 345.kV N 77.8 49813.4 64000 48.2 80175.6 166400 49813.4 27.4

06CLIFTY 345.kV O 79.9 51106.7 64000 49.4 82161.8 166400 51106.7 27

06CLIFTY 345.kV P 79.9 51106.7 64000 49.4 82161.8 166400 51106.7 27

06CLIFTY 345.kV Q 79.9 51106.7 64000 49.4 82161.8 166400 51106.7 27

06CLIFTY 345.kV R 81.1 51106.7 63000 50.2 82161.8 163800 51106.7 27

06CLIFTY 345.kV S 81.1 51106.9 63000 50.2 82162.1 163800 51106.9 27

06CLIFTY 345.kV T 81.1 51106.9 63000 50.2 82162.1 163800 51106.9 27

06DEARBN 345.kV DB 85.6 42796.2 50000 50.9 66158.7 130000 42577.6 18.1

s744241


D-4

06DEARBN 345.kV DC 85.4 42707.6 50000 50.8 66035.8 130000 42506.6 18.1

06DOE530 345.kV 212 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 215 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 218 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 222 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 225 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 228 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 242 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 245 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 248 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 252 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 255 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 258 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 262 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 265 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 268 76.7 30488.9 39762 44.9 38649.2 86164 23693.6 33.8

06DOE530 345.kV 272 61 31698 52000 37.2 38649.2 104000 23693.6 33.8

06DOE530 345.kV 275 61 31698 52000 37.2 38649.2 104000 23693.6 33.8

06DOE530 345.kV 278 61 31698 52000 37.2 38649.2 104000 23693.6 33.8

06DOE530 345.kV 282 61 31698 52000 37.2 38649.2 104000 23693.6 33.8

06DOE530 345.kV 285 61 31698 52000 37.2 38649.2 104000 23693.6 33.8

06KYGER 345.kV A 79.1 39552.1 50000 48.5 63113.8 130000 39552.1 24.4

06KYGER 345.kV AA 79.1 39552.1 50000 48.5 63113.8 130000 39552.1 24.4

06KYGER 345.kV B 75.8 37917 50000 46.5 60504.6 130000 37917 23.4

06KYGER 345.kV BB 79.1 39552.1 50000 48.5 63113.8 130000 39552.1 24.4

06KYGER 345.kV C 79.1 39552.1 50000 48.5 63113.8 130000 39552.1 24.4

06KYGER 345.kV D 80.9 40426.8 50000 48.5 63113.8 130000 37883 24.4

06KYGER 345.kV E 80.9 40426.8 50000 46.8 60794.5 130000 37883 24.4

06KYGER 345.kV F 79.1 39552.1 50000 48.5 63113.8 130000 39552.1 24.4

06KYGER 345.kV G 80.9 40426.8 50000 48.5 63113.8 130000 37883 24.4

06KYGER 345.kV H 80.9 40426.8 50000 46.8 60794.5 130000 37883 24.4

06KYGER 345.kV I 79.1 39552.1 50000 48.5 63113.8 130000 39552.1 24.4

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D-5

06KYGER 345.kV J 79.1 39552.1 50000 48.5 63113.8 130000 39552.1 24.4

06KYGER 345.kV K 79.1 39552.1 50000 48.5 63113.8 130000 39552.1 24.4

06KYGER 345.kV L 79.1 39552.1 50000 48.5 63113.8 130000 39552.1 24.4

06KYGER 345.kV M 79.8 39878.2 50000 48.5 63113.8 130000 37182.6 25.1

06KYGER 345.kV N 79.8 39878.2 50000 46.8 60834.2 130000 37182.6 25.1

06KYGER 345.kV O 79.1 39552.1 50000 48.5 63113.8 130000 39552.1 24.4

06KYGER 345.kV P 79.1 39552.3 50000 38.5 63114.1 163800 39552.3 24.4

06KYGER 345.kV Q 79.1 39552.3 50000 38.5 63114.1 163800 39552.3 24.4

06PIERCE 345.kV 1424 77.8 38896.3 50000 46.6 60626.5 130000 38896.3 18.7

06PIERCE 345.kV A 77.8 38896.3 50000 46.6 60626.5 130000 38896.3 18.7

06PIERCE 345.kV C 73.6 36790.7 50000 43.2 56129.4 130000 36790.7 14.5

06PIERCE 345.kV D 73.6 36790.7 50000 43.2 56129.4 130000 36790.7 14.5

06PIERCE 345.kV E 74.3 37126.3 50000 44.2 57433 130000 37126.3 17.4

06PIERCE 345.kV F 74.1 37070.7 50000 43.8 57000.3 130000 36511.6 19

06PIERCE 345.kV G 73.6 36790.7 50000 43.2 56129.4 130000 36790.7 14.5

06PIERCE 345.kV H 74.9 37445.9 50000 44.4 57679 130000 37002.7 18.7

06PIERCE 345.kV I 74.9 37445.9 50000 44.4 57679 130000 37002.7 18.7

06PIERCE 345.kV J 73.9 36938.6 50000 43.7 56808.3 130000 36394.8 19

06PIERCE 345.kV K 74.2 37114.9 50000 44 57169.1 130000 36675.6 18.7

06PIERCE 345.kV L 74.2 37114.9 50000 44 57169.1 130000 36675.6 18.7

06PIERCE 345.kV M 73.2 36612.1 50000 43.3 56306.1 130000 36073 19

06PIERCE 345.kV P 74.3 37126.3 50000 44.2 57433 130000 37126.3 17.4

06PIERCE 345.kV Q 62.5 31250.4 50000 36.7 47760.8 130000 30438.2 20.1

06PIERCE 345.kV R 71.5 35774.4 50000 42 54578.9 130000 35774.4 14.5

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D-6

Appendix E

Ohio Valley Electric Corporation Stability Assessment Template Indiana-Kentucky Electric Corporation TPL-001-0.1, TPL-002-0, TPL-003-0, TPL-004-0

Electrical Operations – Record

A stability study of an existing generating plant connected to the OVEC system is not needed unless the answer to at

least one of the following statements is “YES”:

1. The impedance or configuration of the transmission network in the vicinity of a generating plant

connected to the OVEC system has been modified by addition, removal, or other change so as to

weaken the transmission system in the vicinity of the generating plant.

YES NO X

2. Changes have been made to the steady-state or stability modeling or MW capability of any generating

unit(s) so as to decrease the stability of the unit(s).

Is a stability study needed based on 1 or 2 above?

YES NO X

YES NO X

This assessment was completed for the period listed and completed the individual named below.

2015 - 2020

Dates covering this assessment

Robert J. O’Keefe

Name

November 25, 2015

Date of assessment


D-7

Revision Date: 11/25/15 Version: 1.1 Page 1

Effective Date: 11/25/15 Author: J. H. Riley

D-8

Stability Assessment Template

TPL-001-0.1, TPL-002-0, TPL-003-0, TPL-004-0

Version History

REVISION DATE REVISED/REVIEWED BY PURPOSE

1.0 08/30/10 JHR, GWB, RJM, SRC, JAD

Original Issue

1.1 11/25/15 RJO, JHR, SRC Clarifying text added to items 1&2

D-9

Revision Date: 11/25/15 Version: 1.1 Page 2

Effective Date: 11/25/15 Author: J. H. Rile

F- 1 -


Kyger Creek Plant

Stability Performance Study

Of Final DOE Station Configurations

Advanced Transmission Studies and Technologies

September 2010

1. INTRODUCTION

This study was undertaken to evaluate the stability performance of Ohio Valley Electric

Corporation’s (OVEC) Kyger Creek Plant following permanent changes to transmission

F- 2 -

interconnections at the Department of Energy’s (DOE) X530 and X533 345 kV Stations.

These changes are expected to be placed in service during the 4th

quarter of 2010.

2. OVERVIEW OF GENERATION/TRANSMISSION FACILITIES

The generation capability at the Kyger Creek Plant is 1,025 MW winter net and is the

sum of five similar units each rated at 205 MW winter net.

The final transmission configuration in the vicinity of DOE’s X530 and X533 345 kV

stations that was the subject of this study is as follows: Kyger Creek – X533 circuit 1 of

the 345 kV double circuit tower (DCT) line is now routed directly to Marquis 345 kV

from the X533 site (also utilizing the former X533-Marquis line, but without the series

reactor) and Kyger Creek – X533 circuit 2 now connects to X533 – Pierce DCT line as a

6-wire DCT line from the X533 site to Pierce 345 kV Station. The X530 345 kV Station

has been returned to the configuration that existed prior to the start of construction at

Marquis and the 2008 interim reconfigurations.

The final configuration is also shown in Figure 1. The X533 Station no longer exists as a

station and the entire DOE load of approximately 35 MW is now served from the X530

Station.

Figure 1 DOE X533 Retirement – Final Configuration*

INDIANA

OHIO

KENTUCKY

WEST

VIRGINIA

Dearborn

Kyger

Pierce

Clifty

345kV

138kV

G

(AEP, Dayton, Duke) 400MW

G 6 x

205MW

G 5 x

205MW

*Expected In-service 4th Qtr 2010

To Marquis (AEP)

DOE

X530

F- 3 -

3. TESTING CRITERIA

AEP / OVEC transient stability criteria for 345 kV connected generation facilities shown

in Table 1 below specify the conditions and events for which stable operation is required

(see OVEC FERC Form 715 filing, Part 4). In addition, satisfactory damping of

generator post-disturbance power oscillations is required.

These testing criteria are applied in time domain simulations to evaluate the stability

performance of a generation facility. For each disturbance, the resulting transmission

system response is simulated and then analyzed to assess the impact of the disturbance

scenarios on the proposed generators and the surrounding system. A one cycle margin to

instability is present in the stability results designated as acceptable reported in this study.

Although beyond the scope of the AEP / OVEC stability testing criteria, a double circuit

tower (DCT) line outage was considered in this study as a valid and credible fault

disturbance scenario.

TABLE 1

AEP / OVEC Stability Testing Criteria for 345 kV Connected Generation

Prefault System Condition Fault Disturbance Scenario

All Transmission Facilities in Service 2A Permanent single phase to ground fault

with breaker failure. Fault clearing by

backup breakers.

2B Permanent three phase to ground fault

with unsuccessful HSR if applicable.

Fault cleared by primary breakers.

2C Three phase line opening without fault.

One Transmission Facility Out 2D Permanent three phase to ground fault

with unsuccessful HSR, if applicable.

Fault cleared by primary breakers.

2E Three phase line opening without fault.

Two Transmission Facilities Out 2F Temporary three phase to ground fault

with successful HSR, if applicable.

2G Three phase line opening without fault.

Where, Criteria 2A = NERC TPL Table 1 Category C6-9

Criteria 2B = NERC TPL Table 1 Category B1-3

Criteria 2C = NERC TPL Table 1 Category B1-3

Criteria 2D = NERC TPL Table 1 Category C3

Criteria 2E = NERC TPL Table 1 Category C3

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F- 4 -

The DCT line outages simulated in this study may be considered as a combination of

NERC Category C3 and C5 contingencies. In this study, a prior outage of a DCT line is

followed by another DCT line outage. The other NERC TPL category contingencies are

either not applicable or would be less severe.

4. STUDY SCOPE and DATA

With reference to the above stability testing criteria, and in consideration of double

circuit tower (DCT) faults and outages, the cases to be simulated were determined and

are listed in Table 2 below. These cases all involved three-phase primary cleared faults

or non-fault initiated tripping. Phase-to-ground delayed clearing faults were not

simulated due to the station configuration at Kyger Creek 345 kV which is such that

outage of further transmission elements does not occur, thus making these disturbance

scenarios less severe.

Unsuccessful high speed reclosing (HSR) of faulted transmission lines was simulated in

all three-phase fault cases. All primary fault clearing was assumed to be 3.5 cycles from

fault initiation. The Kyger Creek Plant was dispatched at its winter net capacity of 1,025

MW unless otherwise indicated. The AEP 2009 series BCD 2015 Summer ERAG /

MMWG base case was used in this study.

5. STUDY RESULTS

The study results for each stability simulation case are indicated in Table 2 below.

Each case consists of a prior double circuit tower (DCT) outage out of the Kyger Creek

345 kV Station followed by three-phase fault and trip, or non-fault initiated trip, of a

second DCT. The Kyger Creek Plant is thus connected by one remaining DCT post-

contingency in each case. Each of these cases is beyond the severity of the stated

stability criteria in Section 3 above. The acceptable stability results from these cases

indicate that less severe cases consistent with the criteria would also have acceptable

stability.

Plots of the dynamic simulation cases with three-phase faults are attached below.

6. CONCLUSION

The Kyger Creek Plant exhibits acceptable stability with the final configuration at DOE’s

X530 and X533 345 kV stations for Criteria 2A through 2E without a need for

curtailment.

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OVEC Stability Performance Study – American Electric Power

Of Final DOE Station Configurations September 2010

F5

TABLE 2

Case

Number

Prior Outage Outaged Line MW Fault Type Result

Case 1 Kyger Ck – X533 345 kV DCT Kyger Ck – Sporn / Tristate 345 kV DCT 1025 3 Phase w/ HSR Stable

Case 2 Kyger Ck – X533 345 kV DCT Kyger Ck – Sporn / Tristate 345 kV DCT 1025 No Fault Stable

Case 3 Kyger Ck – X530 345 kV DCT Kyger Ck – Sporn / Tristate 345 kV DCT 1025 3 Phase w/ HSR Stable

Case 4 Kyger Ck – X530 345 kV DCT Kyger Ck – Sporn / Tristate 345 kV DCT 1025 No Fault Stable

Case 5 Kyger Ck – X530 345 kV DCT Kyger Ck – X533 345 kV DCT 1025 3 Phase w/ HSR Stable

Case 6 Kyger Ck – X530 345 kV DCT Kyger Ck – X533 345 kV DCT 1025 No Fault Stable

s744241

OVEC Stability Performance Study –


F- 6 -

Kyger Creek Plant Per Unit Speeds

Case 1 – Prior outage of Kyger Creek – X533 345 kV DCT. Fault and trip Kyger Creek

– Sporn/Tristate 345 kV DCT with unsuccessful HSR.



F- 7 -






F- 8 -

Per Unit Station Voltages





F- 9 -






F- 10 -






F- 11 -






F- 12 -



– X533 345 kV DCT with unsuccessful HSR.



F- 13 -






F- 14 -




Appendix F


Clifty Creek Plant

Stability Performance Study

Advanced Transmission Studies and Technologies

December 2011


Clifty Creek Plant December 2011

16

7. INTRODUCTION

This study was undertaken to evaluate the stability performance of Ohio Valley Electric

Corporation’s (OVEC) Clifty Creek Plant. The study was conducted in accordance with

the August 2011 NERC Board approved NERC TPL-001-2 standard.

8. OVERVIEW OF GENERATION/TRANSMISSION FACILITIES

The generation capability at the Clifty Creek Plant is 1,230 MW winter net and is the sum

of six similar units each rated at 205 MW winter net. This study considered the planned

temporary outages of Clifty Creek – Dearborn – Buffington 345 kV line sections in late

2011 through early 2012 that were necessary for removal of Dearborn circuit breakers

DA and DD, though this outage is not within the planning horizon.

9. TESTING CRITERIA

NERC TPL-001-2 Table 1 specifies the system conditions and disturbance events for

which stable operation is required. In addition, satisfactory damping of generator post-

disturbance power oscillations is required.

The Table 1 testing criteria are applied in time domain simulations to evaluate the

stability performance of a generation facility. For each disturbance, the resulting

transmission system response is simulated and then analyzed to assess the impact of the

disturbance scenario on the proposed generators and the surrounding system. A

minimum one cycle margin to instability is present in the stability results designated as

acceptable reported in this study.

Some of the NERC TPL-001-2 Table 1 category contingencies are either not applicable

or would be less severe and are omitted from this study. Specifically, P1 contingencies

are less severe than P6 contingencies (P6 is the same as P1 under a prior outage

condition) which, if stable, demonstrate compliance with P1. Due to the configuration of

Clifty Creek 345 kV Station, P2 bus section and circuit breaker faults are equivalent in

severity to line faults because these disturbance scenarios would not remove any more

transmission facilities than would P1 contingencies and may remove a generating unit.

P3 prior generation outages would be less severe due to the fact that stability studies test

the ability of the transmission system under contingency outages to absorb generation and

a condition of less generation would be more stable. P4 stuck breaker contingencies with

backup fault clearing are less severe than P6 three-phase fault cases under a prior outage

condition because, also due to the configuration of Clifty Creek 345 kV Station, these

disturbance scenarios would result only in the removal of one transmission facility.

s744241



17

P6 and P7 criteria are combined in this study by simulating the three-phase fault and

tripping of double circuit tower lines on top of the prior outage of another transmission

facility. These are the type of disturbance scenarios that produce the most severe stability

tests on the Clifty Creek Plant due to the most severe fault type (3-phase) and the most

transmission facilities removed. The prior outage cases are not followed by any system

adjustments and so also qualify as Type 1 stability extreme disturbances in TPL-001-2

Table 1.

For the purposes of post-fault transient voltage criteria required by TPL-001-2 R5, this

study assumes that transient voltage dips at the transmission station above 40 percent

voltage for 2.5 seconds are acceptable. The magnitude and duration of post-fault

transient voltage dips is closely associated with proximity to instability of conventional

generation and transient voltage dips that do not lead to instability are acceptable for

conventional generating plants and should not otherwise result in tripping of the

generator or plant auxiliary load. Therefore, where instability of the subject generating

plant is approached in any of the cases included in this study, either a clearing time

margin or a MW dispatch margin is applied instead.

10. STUDY SCOPE and DATA

With reference to the above stability testing criteria, and in consideration of double

circuit tower (DCT) faults and outages, the cases to be simulated were determined and

are listed in Table 1 below. These cases involved three-phase primary cleared faults or

non-fault initiated tripping. Phase-to-ground delayed clearing faults at Clifty Creek 345

kV Station were not simulated due to the station configuration that is such that outage of

further transmission elements does not occur, thus making these disturbance scenarios

less severe. Phase-to-ground delayed clearing faults were considered at remote ends of

lines emanating from Clifty Creek Station.

Base cases applied in this study were the 2010 series ERAG / MMWG 2012 Summer

Peak Load and 2016 Light Load cases in accordance with TPL-001-2 R2.4.1 and R2.4.2,

respectively. All ERAG / MMWG dynamic base cases include modeling of automatic

dynamic control devices relevant to the Clifty Creek area in accordance with TPL-001-2

R4.3.2. The 2012 Summer Peak Load case was studied with Clifty Creek – Dearborn #2

– Buffington 345 kV line sections out of service due to the Dearborn Bus 2 bypass

project, though this is not a planning horizon condition for TPL purposes.

Dynamic load representation, in accordance with TPL-001-2 R2.4.1, was applied as a

sensitivity variable in the 2012 Summer Peak case. The PSS/E CLODAR model was

applied to the study area (OVEC, AEP, LGEE, HE, DEM areas) with the following

percentages:

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s744241

R5 Transient voltage

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18

Large motor 20 percent

Small motor 40

Transformer exciting current 3

Discharge lighting 5

Constant power 2

Constant current 30

Distribution equivalent R + jX 4

percent on load MW per unit base

The Clifty Creek Plant was dispatched at its winter net capacity of 1,230 MW unless

otherwise indicated. Other nearby generating plants at Trimble County (LGEE) and

Buckner (IPP) were also dispatched at their winter net MW capacities.

Unsuccessful high speed reclosing (HSR) of faulted transmission lines was simulated in

three-phase fault cases inclusive to the OVEC system in accordance with TPL-001-2

R4.3.1.1. All primary fault clearing was assumed to be 3.5 cycles from fault initiation

and backup or delayed clearing was assumed to be 15.0 cycles from fault initiation.

Failure of a primary protection system(s) may cause up to a 30-cycle delayed fault

clearing at the remote end of a line.

In all stability simulations in this study, the PSS/E simulation option “Scan circuits

against generic relay zones” was turned on in accordance with TPL-001-2 R4.3.1.3.

Sensitivity conditions as required by TPL-001-2 R2.4.3 for both peak load and light load

base cases considered the redispatch of generation on or in the vicinity of the OVEC

system. Specifically, the Kyger Creek and Sporn generating plants were turned off and

Tanners Creek and Lawrenceburg generating plants (one station away from Dearborn)

were turned on and dispatched to their winter net MW capability.

11. STUDY RESULTS

The study results for each stability simulation case are indicated in Table 1 below. The

results of cases simulated on peak load and light load conditions, as well as the sensitivity

variable cases and non-fault initiated outage cases, are all the same as far as the their

stability is concerned. The acceptable stability results from these cases in recognition of

TPL-001-2 R4.1.1, 4.1.2, and 4.1.3 indicate that less severe cases consistent with TPL-

001-2 criteria would also have acceptable stability.

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19

No generic relay scan alarms were observed on any non-faulted lines in any of the cases

included in this study (TPL-001-2 R 4.3.1.3). No generators are expected to trip during

faults due to lack of low voltage ride-through capability (TPL-001-2 R4.3.1.2).

Plots of a representative sample of the dynamic simulation cases involving three-phase

and phase-to-ground faults are attached below.

12. CONCLUSION

The Clifty Creek Plant exhibits acceptable stability performance under all credible

contingencies consistent with NERC TPL-001-2 without a need for generation

curtailment.

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20

Table 1 – Clifty Creek Plant Stability Study Cases

Prior Outage * Outaged Facility NERC Category

Fault Type ** Result

Case 1 Clifty Creek – Jefferson 345 kV Clifty Creek – Pierce 345 kV DCT P6-P7

3 Phase w/

unsuccessful

HSR

Stable

Case 2 Clifty Creek – Jefferson 345 kV Clifty Creek – Dearborn 345 kV DCT P6-P7

3 Phase w/

unsuccessful

HSR

Stable

Case 3 Clifty Creek – Jefferson 345 kV Clifty Creek – Trimble Co 345 kV P6 3 Phase

No HSR Stable

Case 4 Clifty Creek – Jefferson 345 kV Buckner – Middletown 345 kV DCT P6-P7 3 Phase

No HSR Stable

Case 5 Clifty Creek – Trimble Co 345

kV Clifty Creek – Pierce 345 kV DCT P6-P7

3 Phase w/

unsuccessful

HSR

Stable

Case 6 Buckner – Middleton 345 kV Clifty Creek – Pierce 345 kV DCT P6-P7

3 Phase w/

unsuccessful

HSR

Stable

Case 7 None Dearborn – Clifty Creek 345 kV #1

Remote End Fault @ Dearborn P5

1 Phase-to-

ground w/ relay

failure

Stable



21

Case 8 None Clifty Creek 345 kV Station Bus 1 or 2 Extreme

Event

3 Phase w/ 3

Phase delayed

Unstable,

No

Cascading

* The prior outage cases listed above (1 through 6) are not followed by any system adjustments and so also qualify as Type 1 stability extreme disturbances in

TPL-001-2 Table 1.

** A representative sample of non-fault initiated outages was also considered per TPL-001-2 P2.1.

- 1 -

Clifty Creek Plant LP Generator Speeds

Case 1: Prior outage of Clifty Creek – Jefferson 345 kV. Fault and trip Clifty Creek –

Pierce 345 kV DCT with unsuccessful HSR.

2012S Base Case

- 2 -

Clifty Creek Plant HP Generator Speeds



2012S Base Case

- 3 -

Clifty Creek, Dearborn, Trimble County, Jefferson, Pierce Station Voltages



2012S Base Case

- 4 -



Dearborn 345 kV DCT with unsuccessful HSR.

2016LL Base Case

- 5 -




2016LL Base Case

- 6 -




2016LL Base Case

- 7 -


Case 7: No prior outage. Remote end phase-to-ground fault, relay failure, and delayed

trip of Clifty Creek – Dearborn 345 kV #1.

2012S Base Case

- 8 -




2012S Base Case

- 9 -

Tanners Creek 3 and 4 Generator Speeds



2012S Base Case

- 10 -




2012S Base Case

- 11 -




2016LL Base Case with generation dispatch sensitivity

- 12 -





- 13 -





1

OHIO VALLEY ELECTRIC CORPORATION - 2016 FILING

FERC FORM 715 - ANNUAL TRANSMISSION PLANNING

AND EVALUATION REPORT

PART 4 -- TRANSMISSION PLANNING RELIABILITY CRITERIA

The Ohio Valley Electric Corporation (OVEC) and its subsidiary, Indiana-Kentucky Electric

Corporation (IKEC), were organized and their transmission systems initially constructed in the

years 1952-1956. OVEC/IKEC was formed by investor-owned utilities furnishing electric

service in the Ohio River Valley area and their parent holding companies (Sponsors) for the

express purpose of supplying the electric power requirements of the U.S. Department of Energy's

(DOE) uranium enrichment project (Project) then under construction near Portsmouth, Ohio.

Due to the highly critical nature of the DOE load, stringent design criteria were adopted for

planning and constructing the OVEC/IKEC System.

The OVEC/IKEC System is primarily an EHV network, and is entirely part of the Bulk Electric

System (BES). The 138 kV facilities in the OVEC/IKEC System are all associated with

interconnections to its Sponsors. In addition to those at the 138 kV class, OVEC/IKEC-Sponsor

interconnections include EHV facilities. The DOE load was originally served from two 345 kV

stations within the Project's boundaries -- owned, operated, and maintained by DOE. One of

these stations remains. The OVEC/IKEC System has eleven generating units located at two

plants with a total capacity of about 2200 MW net. All OVEC/IKEC generation, with the

exception of required operating reserves, is committed to the Sponsors.

As a result of the stringent criteria used in its initial system design and predictable load at the

DOE facility, it has been unnecessary to regularly carry out extensive facility planning studies

for OVEC/IKEC. Various assessments of OVEC/IKEC system performance, however, are made

regularly, including those made as part of the ReliabilityFirst (RF) seasonal, near-term and long-

term appraisals, and any others needed to demonstrate compliance with NERC Reliability

Standards or the requirements of FERC Order 890. In addition, the OVEC/IKEC system

performance is assessed as part of system impact studies carried out at the request of independent

power producers seeking to connect to the OVEC/IKEC transmission system. In carrying out the

future appraisals, system impact studies, or similar transmission studies, OVEC/IKEC relies on

the services of the American Electric Power Service Corporation (AEPSC) East Transmission

Planning group to conduct these assessments.

2

Ohio Valley Electric Corporation/Indiana-Kentucky Electric Corporation

Transmission Planning Criteria and Assessment Practices

Introduction

The following sections present an overview of the criteria that OVEC/IKEC uses for planning a

reliable transmission system. This material supplements the NERC Reliability Standards. The

first section describes the principles underlying the planning criteria and discusses the planning

process. The following three sections provide details of modeling assumptions, performance

expectations, and testing criteria, respectively, for OVEC/IKEC's transmission system. Specific

application of these criteria on a case-by-case basis must employ sound engineering judgment.

The transmission planner conducting each study should always evaluate these criteria and apply

them in such a manner to account for special considerations applicable to the area under study.

1. UNDERLYING PRINCIPLES AND THE PLANNING PROCESS

1.1 Underlying Principles

It is impossible to anticipate or test for all possible conditions that could adversely affect the

OVEC/IKEC transmission system because of the large number of individual elements that

comprise the system and the fact that power flows and load levels are continually changing.

Therefore, the planning criteria and related contingency tests outlined in this report do not

represent an exhaustive set of system operating conditions, transfer levels, and specific

contingencies; instead, they constitute an effective and practical means to stress the OVEC/IKEC

transmission system, testing its ability to survive the entire spectrum of possible contingencies,

and identifying potential weaknesses and problems.

The OVEC/IKEC criteria described herein are consistent with: 1) the North American Electric

Reliability Council (NERC) Reliability Standards; 2) the ReliabilityFirst (RF) Standards and 3)

other external documents. A listing of those external documents is provided in Appendix A. The

application of the NERC and RF criteria to any particular utility system, including OVEC/IKEC,

must be adapted to the specific characteristics of that utility. Each utility's transmission system is

configured in a way that is specific to the geographic region it serves as well as the electrical

facilities that are installed to meet customer requirements. There are also various ways of

achieving reliability objectives. Therefore, differences can exist among the specific planning

criteria employed by various systems. Compatibility among different systems' criteria and

guidelines are achieved, however, by adopting fundamentally sound planning principles and

practices.

3

This report presents an overview of OVEC/IKEC's transmission planning criteria and assessment

practices. Specific application of these criteria and practices on a case-by-case basis must employ

sound engineering judgment. The transmission planner conducting each study should always

evaluate these criteria and apply them in a manner to account for special considerations

applicable to the area under study.

Due to inherent uncertainties associated with long range forecasts, new technological

developments, equipment costs, and changing social, economic and political conditions, it is

prudent to develop long range transmission plans based on a range of assumed scenarios.

Sensitivity analysis is also useful in making these judgments. By their very nature, long-range

plans must be reevaluated and modified periodically to reflect the persistent changes in the

variety of factors that influence future system performance. While current planning criteria are

inherently deterministic, qualitative distinctions about the likelihood of various scenarios and

contingencies are recognized.

More likely events require higher levels of system performance; lower system performance

standards (greater negative impacts) are acceptable for events that are less likely to happen.

Deterministic reliability criteria that are sufficiently stringent to ferret out potential system

problems may also result in specific design consequences, which are impractical or too

expensive in relation to the benefits realized or the risks mitigated. In these cases, prudent

exceptions to the criteria can be made, or other less expensive control schemes employed.

1.2 Planning Process

The planning process provides the focus for establishing an appropriate level of system

reliability. It includes assessments of system performance in the year 1 or 2 as well as longer-

term periods. The process typically begins with a deterministic appraisal of transmission system

performance. When such appraisals identify potential problems, detailed studies are conducted to

evaluate the severity of the problem and to develop an optimal plan to remove or mitigate the

deficiency.

Seasonal assessments, also referred to as operational planning assessments, typically have a

horizon of up to one year. A seasonal assessment, or similar assessment of years 1 or 2, verify

that the transmission system, as planned and built based on long-term predictions and

assumptions, is adequate to meet the actual requirements that emerge for the approaching peak

load periods. Delays in transmission reinforcements, and changing power flow patterns or

performance expectations also influence the need for short-term appraisals. These appraisals may

also provide a warning of future system reinforcement needs.

Near-term (years 1 to 5) and Long-term (year 5 or later) facility planning appraisals analyze

anticipated system conditions within the specified time period. Near-term and Long-term

planning of the transmission system allows adequate time to identify emerging trends and

anticipated system deficiencies and then to plan and build needed transmission reinforcements,

including time for potentially lengthy regulatory approval processes.

4

In addition, various appraisal studies are conducted jointly with neighboring utilities as part of

RF and Eastern Interconnection Reliability Assessment Group (ERAG) agreements. These joint

appraisals focus on measuring the strength of the interconnected network and on assuring

coordination of facility planning and operational planning efforts. OVEC/IKEC is represented on

the teams that conduct these joint appraisals. Where such assessments uncover deficiencies, the

problems are referred to the appropriate company or companies to develop solutions as part of

their normal planning process.

This document does not directly address regional and interregional appraisal criteria except to

note that OVEC/IKEC's criteria comply with those in RF and NERC Reliability Standards. Also,

OVEC/IKEC uses regional and interregional transfer capability measures that are consistent with

the NERC definitions, to assess the strength of its transmission system.

2. KEY MODELING ASSUMPTIONS

The computer models used in transmission planning studies necessarily differ widely in

dimensions and details to suit the scope of each study. Power flow models are developed to

represent system operation during highly stressed periods such as peak load conditions and

heavy power transfers. System dynamics and short circuit computer models are also used,

depending on the specific analysis, to complement the power flow models. Using these computer

models, transmission system performance is assessed by simulating disturbances to identify

system strengths and weaknesses. In general, the following assumptions are used in conducting

various types of transmission planning studies.

The OVEC/IKEC system is used primarily by OVEC for bulk power sales of OVEC generated

power to the OVEC owners. A single internal load customer, the DOE, is served by off system

generation. OVEC/IKEC System active load (MW) forecasts are based on projections developed

by the DOE; and are assumed to be the same for typical peak and off-peak study scenarios. DOE

loads are projected to be minimal (compared to the original Project capability) for the

foreseeable future. Reactive power (MVAR) loads are based on the customer’s calculated power

factors for the projected loads and/or recent historical data. Power transfer levels modeled in

base cases for analysis of the OVEC/IKEC System vary from one study to another depending on

the particular focus of the study. The ERAG Multi-Regional Modeling Working Group

(MMWG) load flow base cases generally model only committed firm power transfers.

ReliabilityFirst cases, which are derivatives of the MMWG cases, may be modified to include

other scenarios. Base cases used in OVEC/IKEC's studies are derived from these regional

models. Additional sensitivity cases may be used to assure that potential system bottlenecks are

identified. The sensitivities most commonly studied involve alternative assumptions about the

status or operating level of generation at electrically nearby generating plants, and high levels of

transfers, used to simulate parallel flow conditions reflecting recent experience.

All of the OVEC/IKEC generating units are generally dispatched, except for those out of service

for maintenance, since all or most of their generation is usually required for sales to Sponsors.

The modeled generation output of each of OVEC/IKEC’s two power plants is based on the

plant’s capacity relative to the total OVEC/IKEC generation capacity.

5

Base cases model all transmission facilities in service except for known scheduled maintenance,

long-term construction outages, or long-term forced outages. Thus, an interconnection study

involving the bulk transfer of power between two power systems not only would require

sufficient detail of the bulk transmission in each participating system, but also would include

sufficient detail and/or equivalent representation of other interconnected systems to assure proper

analysis of critical elements.

Sufficient modeling of neighboring systems is essential in any study of the OVEC/IKEC

transmission system. Neighboring company information is obtained from the latest regional or

interregional study group models, the RF base cases, the ERAG MMWG load flow library, or the

Sponsors themselves. Sufficient detail is retained to simulate all outages and changes in

generation dispatch that are contemplated in the particular study.

With the power flow base cases described above, the study engineer develops scenarios, which

are surrogates for a wide range of possible conditions. Numerous facility outages and power

transfers occur daily in the interconnected network. It would be impractical to simulate all such

possible conditions in planning studies. To establish a manageable set of base case scenarios,

historical data and experience are employed. Although history is not a perfect indicator of the

future, it provides valuable information to benchmark the base case models. For future power

flow base cases, further adjustments are made to reflect forecasted load levels, expected facility

changes, and projected power transfers, as well as emerging trends that will affect historical

power flow patterns.

The power flow models described above are the most frequently used models for transmission

planning studies. Transient stability and short circuit studies are also used to evaluate the system

performance during and immediately following fault conditions on the transmission system. The

network configurations used in the load flow models also provide a starting point for transient

stability and short circuit studies. In addition, for transient stability studies, additional impedance

data and electro-mechanical detail of generators and their controls are included.

3. PERFORMANCE STANDARDS

Performance Standards establish the basis for determining whether system response to

contingency analysis is acceptable. Depending on the nature of the study, one or more of the

following performance standards will be assessed: thermal, voltage, relay, stability, and short

circuit.

In general, system response to contingencies evolves over a period of several seconds or more.

Steady state conditions can be simulated using a power flow computer program. A short circuit

program can provide an estimate of the large magnitude currents, due to a disturbance, that must

be detected by protective relays and interrupted by devices such as circuit breakers. A stability

program simulates the power and voltage swings that occur as a result of a disturbance, which

could lead to undesirable generator/relay tripping or cascading outages. Finally, a post-

contingency power flow study can be used to determine the voltages and line loading conditions

following the removal of faulted facilities and any other facilities that trip as a result of the initial

disturbance. For the OVEC/IKEC System, thermal performance standards are usually the most

constraining measure of reliable system performance. Each type of performance standard is

described in the following discussion.

6

3.1 Thermal Limits

Thermal ratings define transmission facility loading limits. Normal ratings are generally based

upon no abnormal loss of facility life or equipment damage. Emergency ratings accept some loss

of life or strength, over a defined time limit for operation at the rated loading level. The thermal

rating for a transmission line is defined by the most limiting condition, be it conductor capability,

sag clearance, or terminal equipment rating. When a line is terminated with multiple circuit

breakers, as in a ring bus or "breaker and a half" configuration, it is assumed that the line flow

splits equally through the terminal equipment unless one breaker is open. Ratings in power flow

simulations normally assume all breakers are in service.

Most thermal ratings are defined in amperes. However, transmission planning studies use ratings

expressed in MVA, based on the ampere rating at nominal voltage. When voltages during

testing deviate considerably from nominal, the MVA loading is adjusted for the voltage deviation

from nominal to permit an appropriate comparison to the MVA rating.

3.2 Voltage Limits

Voltages at transmission stations should be above the values listed in Table 1 in subsection 4.1 to

reduce the risk of system collapse and/or equipment problems. In addition, voltages at generating

stations below minimum acceptable levels established for each station must be avoided to

prevent tripping of the generating units. High voltage limits are specific to particular pieces of

equipment, but are typically 105% of nominal. Post-contingency voltage drop limits are utilized

to prevent voltage instability, which could result in system voltage collapse. OVEC will

investigate any potential voltage drop that exceeds 6% for voltage instability. Voltage drops

exceeding 10% are considered violations of OVEC’s criteria and should be avoided.

3.3 Relay Trip Limits

BES facilities are designed to comply with NERC PRC Reliability Standard requirements.

7

3.5 Short Circuit Limits

Short circuit limits are also an important aspect of system performance, since the extremely high,

short duration currents that accompany system faults will impose considerable stresses on

network elements. Circuit breakers must be capable of interrupting the anticipated fault currents

in the shortest possible time. Failure to interrupt these currents may lead to catastrophic

equipment damage and endanger human life. Short circuit levels increase as network

reinforcements are implemented or new generating units are added to the system. Therefore,

short circuit levels must be reviewed periodically so that inadequate equipment can be replaced

or upgraded, or a mitigation procedure developed.



The planning process for OVEC/IKEC's transmission network embraces conditions with all

facilities in service (NERC Category P0) as well as two major sets of contingency testing criteria

to ensure reliability. The first set includes single and multiple contingencies contained in NERC

Categories P1 through P7. The second set includes more severe multiple contingencies (NERC

Extreme Events) and is primarily intended to test the potential for system cascading.

For OVEC/IKEC transmission planning, the testing criteria are deterministic in nature; these

outages serve as surrogates for a broad range of possible operating conditions that the power

system will have to withstand in a reliable fashion. In the OVEC/IKEC transmission system,

thermal and voltage performance standards are usually the most constraining measures of

reliable system performance. Each type of performance requirement is described in the

following discussion. Table 1 below documents the performance criteria for all transmission

facilities under normal and contingency conditions.

8

Table 1 OVEC/IKEC Transmission Planning Criteria

(Steady State System Performance)

Transmission System Condition

Maximum Facility

Loading (Rating)

Minimum

Bus Voltage (Delta

V < 10%)

EHV

138 kV

All facilities in service

(NERC Category P0)

Normal

95%

95%


(NERC Categories P1 and P2)

Emergency

93%

92%


(NERC Categories P3 through

P7 & Extreme Events)**

Emergency

93%

92%

* Because the OVEC stations are primarily of “breaker and ½” configuration,

steady state simulation of the more likely Extreme Events is identical to one or

more Category P3 through P7 contingencies. Where simulation of Extreme

Events differ from Categories P3 – P7 events, performance is reviewed for risks

and consequences. Issues identified may not require mitigation, but may be

considered when evaluating possible solutions to violations from Category P1

through P7 contingencies.

4.1.1 Planning Contingencies

Planning Contingencies include those defined in NERC Reliability Standard TPL-001-4. A

single event is defined based on the arrangement of automatic protective devices.

4.1.2 Extreme Events

The more severe reliability assessment criteria required in NERC Reliability Standard TPL-001-

4 are primarily intended to prevent uncontrolled area-wide cascading outages under adverse but

credible conditions. OVEC/IKEC, as a member of ReliabilityFirst, plans and operates its

transmission system to meet the criteria. However, new facilities would not be committed based

on local overloads or voltage depressions following the more severe multiple contingencies

unless those resultant conditions were expected to lead to widespread, uncontrolled outages.

In operational planning studies, the purpose of studying multiple contingencies and/or high

levels of power transfers is to evaluate the strength of the system. Where conditions are

9

identified that could result in significant equipment damage, uncontrolled area-wide power

interruptions, or danger to human life, IROL operating procedures will be developed, if possible,

to mitigate the adverse effects. It is accepted that the defined performance limits could be

exceeded on a localized basis during the Extreme Events, and that there could be resultant minor

equipment damage, increased loss of equipment life, or limited loss of customer load.


OVEC/IKEC transmission system stability testing is performed in accordance with the

contingency scenarios defined in NERC TPL-001-4.


The power transfer capability between two interconnected systems (or sub-systems) with all

facilities in service or with one or two significant components out of service, indicates the overall

strength of the network. Many definitions of power transfer capability are possible, but

uniformity of definition is highly desirable for purposes of comparison. Furthermore, transfer

capability, however defined, is only accurate for the specific set of system conditions under

which it was derived. Therefore, the user of this information needs to be aware of the conditions

under which the transfer capability was determined and those factors, which could significantly

influence the capability.


"Transmission Transfer Capability,” dated May 1995. The most frequently used transfer

capability definition is for First Contingency Incremental Transfer Capability (FCITC) and is

quoted below from the referenced NERC publication:

10


"FCITC is the amount of power, incremental above normal base power transfers






2. The electric systems are capable of absorbing the dynamic power swings, and

remaining stable, following a disturbance that results in the loss of any single


unit, and

3. After the dynamic power swings subside following a disturbance that results in

the loss of any single electric system element as described in 2 above, and after

the operation of any automatic operating systems, but before any post-




First Contingency Total Transfer Capability (FCTTC) is similar to FCITC except that the base

power transfers (between the sending and receiving areas) are added to the incremental transfers

to give total transfer capability.

While the first contingency transfer capabilities are the most frequently used measure of system

strength, transfer capabilities also can be calculated for "no contingency" and "second

contingency" conditions.