TRANSMISSION COORDINATION AND PLANNING COMMITTEE · PDF fileTRANSMISSION COORDINATION AND...

2011 LOCAL TRANSMISSION PLAN:

TRANSMISSION COORDINATION AND PLANNING COMMITTEE

ANNUAL TRANSMISSION ASSESSMENT

FOR THE

COMMON USE TRANSMISSION SYSTEM

PREPARED BY

BLACK HILLS CORPORATION

TRANSMISSION PLANNING

April 2, 2012

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Common Use System: Transmission Coordination and Planning Committee

2011 Local Transmission Plan April 2, 2011

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Executive Summary

In December of 2007, the Common Use System (CUS) participants filed with FERC Attachment

K to the Joint Open Access Transmission Tariff (JOATT) to meet the requirements outlined in

FERC Order 890. Through their Attachment K filing, the CUS participants created the

Transmission Coordination and Planning Committee (TCPC) as the forum to conduct long-range

planning studies while promoting stakeholder input and involvement. This report, intended to

serve as the 2011 Local Transmission Plan (LTP), outlines the 2011 study cycle and presents the

findings of the planning study. The report also serves as evidence of compliance with the NERC

TPL Standards.

The 2011 TCPC study consisted of a series of analysis methods to determine the long-term

adequacy of the transmission system. These methods included steady-state power flow, transient

stability, and voltage stability analysis performed on short term and long term scenarios to

provide a comprehensive understanding of expected future transmission system performance.

The 2011 study confirmed the need for several projects that were previously identified and

planned for completion within the 10-year planning horizon, and a new potential reliability

concern at the tail-end of the planning horizon was identified for future consideration. A brief

summary of study results is included below:

The St. Onge substation addition can be delayed until 2018-2022.

The Lookout-Spearfish BEC 69 kV line rebuild can be delayed until 2016.

The Lookout-Sundance Hill #1 69 kV line rebuild should proceed as planned, and the

rating should be increased if possible based on clearance verification in the interim.

The Whitewood-Sundance Hill 69 kV line rating should be increased if possible based on

clearance verification. The ability to obtain an increased rating, along with the

completion of the St. Onge substation, will be the primary drivers for a line rebuild.

Local transmission providers should finalize an agreement for an exemption from the

frequency criteria specified in the WECC Disturbance-Performance Table (Table W-1) of

Allowable Effects on Other Systems.

The TCPC should continue to evaluate the need for additional transformation capacity to

serve the Wyodak 69 kV area in the 2022 time frame.

The TCPC should continue to evaluate the need to replace the 100 MVA transformer at

Lange with a larger unit as load growth requires.

The Teckla-Osage-Lange 230 kV line should proceed as planned.

The Custer-Westhill 69 kV line rebuild should proceed as planned.

The Osage-Newcastle 69 kV line rebuild should proceed as planned.

This report serves as the 2011 Local Transmission Plan and meets the requirements of

Attachment K to the BHBE JOATT, as well as the requirements of the NERC TPL Standards

and WECC System Performance Criteria.

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Table of Contents

1. Introduction ............................................................................................................................... 5

1.1. Common Use Transmission System Background .............................................................. 5

1.2. Stakeholder Participation .................................................................................................... 5

2. Study Methodology ................................................................................................................... 7

2.1. Study Criteria ...................................................................................................................... 7

2.2. Study Area .......................................................................................................................... 8

2.3. Study Case Development .................................................................................................... 9

2.4. Transmission Planning Assumptions ................................................................................ 10

3. Evaluation of the Common Use Transmission System ........................................................ 11

3.1. Steady-State Analysis ....................................................................................................... 11

3.2. Category D Extreme Outage Analysis .............................................................................. 14

3.3. Voltage Stability Analysis ................................................................................................ 15

3.4. Transient Stability Analysis .............................................................................................. 16

3.5. Results Summary .............................................................................................................. 18

4. Transmission System Expansion ........................................................................................... 19

4.1. Previously Identified/Existing Projects ............................................................................ 19

4.2. Recommended Projects ..................................................................................................... 21

5. Conclusions .............................................................................................................................. 21

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Appendices

.................................................................................. A-1 Appendix A: Prior and Forced Outage Lists

.............................................................................. B-1 Appendix B: Load and Resource Assumptions

List of Tables

Table 1: CUS Interconnection Points ................................................................................................. 9

Table 2: Study Case Naming Convention ......................................................................................... 11

Table 3: 2016HS Category D Outage Summary .............................................................................. 14

Table 4: 2016W Category D Outage Summary ................................................................................ 15

Table 5: Transient Stability Analysis Fault Summary ...................................................................... 17

List of Figures

Figure 1: Common Use Transmission System ................................................................................... 6

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1. Introduction

In December of 2007, the Common Use System (CUS) participants filed with FERC Attachment K

to the Joint Open Access Transmission Tariff (JOATT) to meet the requirements outlined in FERC

Order 890. Through their Attachment K filing, the CUS participants created the Transmission

Coordination and Planning Committee (TCPC) as the forum to conduct long-range planning studies

while promoting stakeholder input and involvement. This report, intended to serve as the 2011

Local Transmission Plan (LTP), will outline the 2011 study cycle and present the findings of the

planning study.

1.1. Common Use Transmission System Background

Black Hills Power, Inc., Basin Electric Power Cooperative and Powder River Energy Corporation

(referred to hereinafter as the Transmission Provider) each own certain transmission facilities with

transmission service pursuant to a FERC-approved Joint Open Access Transmission Tariff

(“JOATT”). The Transmission Provider commonly refers to these facilities as the Common Use

System (“CUS”). A diagram of the CUS is shown in Figure 1.

1.2. Stakeholder Participation

All interested parties were encouraged to participate in the 2011 TCPC study process. An open

stakeholder kick-off meeting was held via webinar on February 16, 2011 to inform stakeholders of

the proposed study plan and to provide an opportunity for suggestions and feedback on the study

process. Requests for data pertaining to the modeling and evaluation of the transmission system

were made by the Transmission Provider. Additional stakeholder meetings were held on August

16, 2011, December 21, 2011, and April 19, 2012. All meeting notices were distributed via email

and posted along with presentation materials in the ‘Transmission Planning’ folder on the Common

Use System/BHBE OASIS page at http://www.oatioasis.com/BHBE.

http://www.oatioasis.com/BHBE

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Common Use System: Transmission Coordination and Planning Committee 2011 Local Transmission Plan April 2, 2012

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Figure 1: Common Use Transmission System

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2. Study Methodology The BHCE transmission system was evaluated with planned system additions for 2016 under both

peak summer and off-peak winter load levels to identify any deficiencies in system performance.

Steady state voltage and thermal analyses, as well as transient stability analysis was performed.

Additional upgrades were identified and modeled as necessary to mitigate any reliability criteria

violations. The analysis was repeated for the 2022 peak summer and 2018 off-peak winter load

scenarios to validate any upgrades identified in the near-term study as well as assess the long-term

integrity of the transmission system. A list of prior and forced outages used in the 2011 LTP

study process was included in Appendix A.

2.1. Study Criteria

The criteria used in this analysis is consistent with the NERC TPL Reliability Standards, WECC

TPL – (001 thru 004) – WECC – 1 – CR ─ System Performance Criteria and Colorado Coordinated

Planning Group’s Voltage Coordination Guide. Pre-existing voltage and thermal loading violations

outside the localized study area were ignored during the evaluation. Worst-case Category D

outages were evaluated in the 2016HS and LW scenarios for risk and consequence.

2.1.1. Steady State Voltage Criteria

Under system intact conditions, steady state bus voltages must remain between 0.95 and 1.05 per

unit. Following a Category B or C contingency, bus voltages must remain between 0.90 and 1.10

per unit.

2.1.2. Steady State Thermal Criteria

All line and transformer loading must be less than 100% of their established continuous rating for

system normal conditions (NERC/WECC Category A). All line and transformer loadings must be

less than 100% of their established continuous or emergency rating under outage conditions

(NERC/WECC Category B and C). BHP utilizes an allowable 30-minute overload on transformers

of up to 153% of the continuous thermal rating for emergency situations, but flags all loading in

excess of the continuous rating for further evaluation.

2.1.3. Transient Voltage and Frequency Criteria

NERC Standards require that the system remain stable and within applicable thermal ratings and

voltage limits for Category A, B, and C disturbances. The WECC Disturbance – Performance

Table of Allowable Effects on Other Systems states the following requirements:

Category B: Any transient voltage dip must not exceed 25% at load buses or 30% at non-

load buses. The dip also must not exceed 20% for more than 20 cycles at load buses.

Frequency must not drop below 59.6 Hz for 6 or more cycles at a load bus, including

generation station service load.

Category C: Any transient voltage dip must not exceed 30% at load buses or 30% at non-

load buses. The dip also must not exceed 20% for more than 40 cycles at load buses.

Frequency must not drop below 59.0 Hz for 6 or more cycles at a load bus, including station

service load.

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Based in part on the NERC/WECC requirements, the following criteria were used to determine

acceptable transient system performance:

All machines in the system shall remain in synchronism as demonstrated by their relative

rotor angles.

System stability is evaluated based on the damping of the relative rotor angles and the

damping of the voltage magnitude swings.

For central, northern and eastern Wyoming and western South Dakota, the following

dynamic stability guidelines have been established: Following a single contingency

disturbance with normal fault clearing, the bus voltage transient swing on all buses should

not be lower than 0.70 per unit, and the system should exhibit positive damping.

The frequency criteria specified in Table W-1 of the WECC Disturbance-Performance

Table of Allowable Effects on Other Systems was utilized for the analysis. However, CUS

transmission providers and neighboring transmission providers may adopt a less stringent

requirement than the NERC/WECC Planning Standard. See Section 4.1.8 for details

regarding this proposed change.

2.1.4. Voltage Stability

The established WECC voltage stability criteria are as follows: For load areas, post-transient

voltage stability is required for the area modeled at a minimum of 105% of reference load for

Category A and B contingencies, and 102.5% of reference load for Category C contingencies.

Category D events require a 0% real power margin and should be evaluated for risk and

consequence.

2.1.5. Cascading

NERC Standards require that the system remain stable and no Cascading occurs for Category A, B,

and C disturbances. Cascading is defined in the NERC Glossary as “The uncontrolled successive

loss of system elements triggered by an incident at any location. Cascading…… cannot be

restrained from sequentially spreading beyond an area predetermined by studies.” A potential

triggering event for Cascading will be investigated upon one of the following results:

A generator pulls out of synchronism in transient stability simulations. Loss of synchronism

occurs when a rotor angle swing is greater than 180 degrees. Rotor angle swings greater

than 180 degrees may also be the result of a generator becoming disconnected from the

BES; or

A transmission element experiences thermal overload and the minimum transmission relay

loadability threshold is exceeded. Thermal overloads of greater than 150% will be further

investigated to determine the risk of Cascading by manually removing those facilities in

sequence until the outage is contained or Cascading is confirmed.

Negative margin occurs in voltage stability simulations.

2.2. Study Area

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The 2011 LTP study area will include all CUS transmission equipment as well as neighboring

transmission system elements bound by TOT4B to the northwest, TOT4A to the southwest, Dave

Johnston and Stegall to the south, and Rapid City to the east. Points of interconnection between the

CUS and neighboring utilities are shown in Table 1.

Table 1: CUS Interconnection Points

Interconnection Name Interconnecting Utility1

Sheridan City of Sheridan, PAC

Carr Draw PAC

Wyodak PAC

Antelope PAC

Windstar PAC

Dave Johnston WAPA-RMR, PAC

Stegall WAPA-RMR, MBPP

Rapid City DC Tie WAPA-UGPR

2.3. Study Case Development

The baseline cases for the 2011 LTP Study were chosen based upon availability of updated

regional study cases, planned transmission system and resource upgrades, and previously

completed planning studies. A complete list of individual case changes for each scenario is

available upon request.

2.3.1. 2016 Heavy Summer and Light Winter Study Cases

The 2016 heavy summer scenario was chosen for the near-term analysis for several reasons. The

summer demand levels have historically been the most critical of the seasonal load patterns in the

study area. The case originated as the 16HS2 WECC base case approved in late 2010. The

approval date coincided with the beginning of the 2011 TCPC study cycle, allowing for the use of a

current starting case.

The 2016 light winter time scenario was chosen to allow for an assessment of the ‘bookends’ of

demand levels within the CUS at the latter end of the near-term study time frame. The starting case

was the WECC 16HW2 base case approved in January 2011.

Updates to the case loads, resources, and topology were solicited from TCPC members as well as

neighboring systems and applied to the models.

Significant changes to the existing 2011 Common Use transmission system to create the 2016

models included:

1 PAC means PacifiCorp; WAPA means Western Area Power Administration; MBPP means Missouri Basin Power

Project

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the addition of the planned Teckla-Osage-Lange 230 kV line

the addition of the Minnekhata 230/69 kV substation

the retirement of the Osage power plant2

2.3.2. 2018 Light Winter Study Case

The 2018 light winter time scenario was chosen to allow for an assessment of the ‘bookends’ of

demand levels within the CUS in the far-term study time frame. The starting case was the WECC

18HW1 base case approved in October 2010. As with the 2016 cases, current load and resource

forecasts were modeled, as well as expected system topology for that time frame. There were no

major transmission system projects modeled in addition to those included in the 2016 scenarios.

2.3.3. 2022 Heavy Summer Study Case

The 2022 case was created by the Colorado Coordinated Planning Group (“CCPG”) members for

the Douglas, Elbert, El Paso, And Pueblo (“DEEP”) sub-committee study. As with the 2016 cases,

current load and resource forecasts were modeled, as well as expected system topology for that

time frame. There were no major transmission system projects modeled in addition to those

included in the 2016 scenarios.

2.4. Transmission Planning Assumptions

The 2011 LTP study was performed for both the 5 and 10-year time frames with the following

assumptions:

All existing and planned facilities and the effects of control devices and protection systems

were accurately represented in the system model.

Projected firm transfers were represented per load and resource updates from each

stakeholder.

Existing and planned reactive power resources were modeled to ensure adequate system

performance.

There were no specific planned outages identified for the 2016, 2018, and 2022 study

periods. A series of prior and forced outages on facilities deemed to be most critical by the

transmission planner was simulated to identify potential risks associated with such outages

in the study time frame. A list of the evaluated prior and forced outages is included in

Appendix A.

For system intact solutions, transformer taps and switched shunts were allowed to adjust.

Following a contingency, adjustment of these devices was disabled unless designed to allow

such operation. For all solutions, area interchange control and phase shifter adjustments

were disabled, while DC tap adjustment was enabled. A fixed slope decoupled Newton

solution method was utilized through the analysis.

System load and generation dispatch assumptions are included in Appendix B.

2 The operation of the Osage plant was under suspension at the time of the study. Plans to retire the plant, along with

NSS1 and Ben French were announced following the completion of the analysis. Study assumptions include the

retirement of Osage, but not NSS1 or Ben French.

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3. Evaluation of the Common Use Transmission System

3.1. Steady-State Analysis

The steady-state analysis was performed with several case options for each load scenario. The first

option allowed for various prior outages to be applied to the study case. The second option altered

the flow across the Rapid City DC Tie to reflect maximum bi-directional transfers as well as the

zero-transfer condition. The third option modeled the planned St. Onge 230/69 kV substation and

150 MVA, 230/69 kV transformer as a sensitivity to evaluate the continuing need for the project.

The fourth option changed the status of the normal-open points on the Black Hills 69 kV system

from open to closed, including an option to reconfigure the normal-open points for scenarios

including the St. Onge substation. This was done to represent the existing operating practice of

closing the normal-open points for certain prior outages. Study case designations were formatted

according to the selected options as shown in Table 2.

Table 2: Study Case Naming Convention

Prior Outage_RCDC Tie_St. Onge Sub_69kV Configuration

Prior Outages: See Appendix A

RCDC Tie Transfers: 0E-W RCDC Tie blocked 200E-W 200 MW east-to-west

200W-E 200 MW west-to-east

St. Onge Substation: NOSTONGE St. Onge 230/69 sub. not included STONGE St. Onge 230/69 sub. included

69 kV Configuration: NC No Change

RADIAL Black Hills N.O. Points Open

STORADIAL Black Hills N.O. Points Open w/St. Onge

69TIED Black Hills N.O. Points Closed

Additionally, the RCDC Tie transfers were included as variations of the baseline case to provide

additional insight to the impacts of the St. Onge substation addition. This LTP study was not

performed to define RCDC RAS Runback procedures, and any violations mitigated through

operation of the existing RAS were not included in the results summary.

3.1.1. 2016HS Steady-State Results

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The largest thermal overload in the 2016HS scenario occurred following the loss of the Lange #2

230/69 kV transformer (150 MVA) followed by the loss of the South Rapid City 230/69 kV

transformer (150 MVA). The remaining Lange transformer loaded to 149% of the continuous

rating, which is within the allowable 30-minute emergency rating of 153%. This loading assumed

the 69 kV system was operated in a radial configuration. By closing the 69 kV normal-open points,

the loading was reduced to 110%, and dispatching Must Run generation in Rapid City (RC Gen4)

reduced the loading to 90%. The addition of St. Onge reduced loading in this scenario by an

additional 8%.

The Wyodak 230/69 kV transformer loaded to 102% of the 100 MVA continuous rating following

the N-1-1 loss of the other 100 MVA Wyodak 230/69 kV transformer and the NSS2 plant. The

overload was mitigated by dispatching gas-fired generation at NSS2.

There was no significant need identified for adding St. Onge in the 2016 time frame other than

reducing Rapid City generation for the outage combination mentioned above, or potentially

reducing the complexity of the RCDC Tie RAS, but not eliminating it.

3.1.2. 2016LW Steady-State Results

The 2016LW scenario resulted in system performance similar to the 2016HS scenario, but

improved significantly. The worst-case Lange transformer overload in the HS scenario was

approximately 110% in the LW scenario, which is under the 2-hour emergency rating of 120%.

Closing the normal-open points on the 69 kV system reduced the loading to below 100%.


the N-1-1 loss of the other 100 MVA Wyodak 230/69 kV transformer and the NSS2 plant. The

overload was mitigated by dispatching gas-fired generation at NSS2.

There was no significant need identified for the St. Onge substation in the 2016 time frame as a

result of the 2016LW steady-state analysis.

One performance issue identified on the Osage 69 kV system followed the prior outage of the

Osage 230/69 kV transformer. The Osage-area load was fed radial from Hughes. In this off-peak

load scenario, the first 10 MVAR capacitor on the 69 kV bus was not sufficient to prevent voltage

sag. The second 10 MVAR capacitor resulted in voltages on the 69 kV system in excess of the

1.05 p.u. limit. One potential option to mitigate the issue is to manually reduce the size of the

connected capacitor while the planned transformer outage is in effect. This issue is operational in

nature and will require further analysis outside of the TCPC process.

3.1.3. 2018LW Steady-State Results

One performance issue identified on the Osage 69 kV system followed the prior outage of the

Osage 230/69 kV transformer. The Osage-area load was fed radial from Hughes. In this off-peak

load scenario, the first 10 MVAR capacitor on the 69 kV bus was not sufficient to prevent voltage

sag. The second 10 MVAR capacitor resulted in voltages on the 69 kV system in excess of the

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1.05 p.u. limit. As mentioned in Section 3.1.2, this issue is operational in nature and will require

further analysis outside of the TCPC process.

There was no significant need identified for the St. Onge substation in the 2018 time frame as a

result of the 2018LW steady-state analysis.

3.1.4. 2022HS Steady-State Results

All scenarios that did not include the St. Onge substation exhibited overloads on the Lookout-

Sundance Hill #1 69 kV line following the loss of the Lookout-Sundance Hill #2 69 kV line. The

largest overload encountered was approximately 103% of the 43 MVA rating. Per the BHP

Facility Rating Methodology, the line rating may potentially be increased to 58 MVA by verifying

the clearances of the line. Loading on the line will continue to be monitored as anticipated load

growth on the Sundance Hill-Belle Creek 69 kV line materializes. The line is currently scheduled

to be rebuilt in the 2013-2014 time-frame. The addition of the St. Onge substation mitigated the

overload.

Several 230/69 kV transformer overloads were encountered following the N-1-1 loss of two

transformers in the Black Hills area. The Yellowcreek transformer loading reached the 2-hour

emergency rating of 120% following the loss of both Lookout transformers. Additional generation

in Rapid City did not mitigate the overload. The addition of St. Onge reduced the loading to 73%.

The Lookout #1 230/69 kV transformer reached 111% of the 100 MVA continuous rating

following the N-1-1 loss of the Yellowcreek (100 MVA) and Lookout #2 (150 MVA) transformers.

The overload was not mitigated by dispatching additional Rapid City generation. The addition of

St. Onge reduced the loading to 71%.

The Lange #1 230/69 kV transformer (100 MVA) became loaded to 131% following the N-1-1 loss

of the South Rapid City and Lange #2 230/69 kV transformers. The overload was mitigated by

dispatching all Rapid City gas-fired generation, assuming Ben French was unavailable due to

retirement of the unit. The transformer also loaded to 110% following the N-1-1 loss of the South

Rapid City-Lange 230 kV line and the Lange #2 transformer. This overload was mitigated by

dispatching Rapid City gas-fired generation. The addition of the St. Onge substation and

transformer had no significant impact on the Lange transformer overloads. It is suggested that the

unit be replaced with a 150 MVA transformer in the event of a failure, or as Rapid City load

growth requires. The loading on the Lange #1 transformer will continue to be monitored in future

studies.


the N-1-1 loss of the other 100 MVA Wyodak 230/69 kV transformer and the NSS2 plant. All gas-

fired generation at NSS2 was online for this scenario. It is expected that the overload will be

exacerbated by the potential retirement of the 16 MW (net) NSS1 plant in 2014. Load projections

for the Wyodak 69kV area should be reviewed and further analysis performed to evaluate potential

mitigation options for this circumstance.

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The N-1-1 loss of the Yellowcreek 230/69 kV transformer and the Lookout-Kirk 69 kV line

resulted in the Lookout-Spearfish BEC 69 kV line loading to 112% of the 43 MVA rating and the

Spearfish BEC-Hillsview 69 kV line loading to 100% of the 43 MVA rating. The addition of the

St. Onge substation and transformer reduced the loading on these lines to 96% and 84%,

respectively. It is recommended that the Lookout-Spearfish BEC 69 kV line be rebuilt prior to the

2022 time frame or as future load growth projections require.

3.2. Category D Extreme Outage Analysis

Several significant Category D outages were selected to identify the impacts of each outage on the

transmission system. The outages were selected from all valid Category D events based on past

study results and working understanding of the criticality of the associated system elements. Bus

outages were simulated by disconnecting the bus and all associated network elements at the each of

the non-radial CUS 230 kV substations. The steady-state analysis was performed for scenarios

with and without St. Onge. A summary of consequential load and generation loss for each outage

in the 2016HS scenario is shown in Table 3 and a summary for the 2016LW scenario is shown in

Table 4. The scenario without St. Onge and with the 69 kV system normal-open points closed was

summarized below since it minimized the amount of consequential load loss over a radial system

configuration.

Table 3: 2016HS Category D Outage Summary

2016HS (SYSINT_200E-W_NOSTONGE_69TIED)

Bus Outage Consequential Load Loss Consequential Gen Loss

1_Lange 230 Bus - -

2_Lookout 230 Bus - -

3_St. Onge 230 Bus - -

4_S Rapid City 230 Bus - RCDC Tie Transfer

5_Westhill 230 Bus - -

6_Minnekhata 230 Bus - -

7_Yellowcreek 230 Bus - -

8_Osage 230 Bus - -

9_Hughes 230 Bus - -

10_Wyodak 230 Bus 36 MW (Station Service) 377 MW

11_Dry Fork 230 Bus 35 MW (Station Service) 420 MW

12_Donkey Creek 230 Bus 34.8 MW (Station Service) 400 MW

13_Carr Draw 230 Bus 9.9 MW -

14_Barber Creek 230 Bus 60.5 MW -

15_Pumpkin Buttes 230 Bus 29 MW -

16_Teckla 230 Bus 80.1 MW -

17_Reno 230 Bus 91.8 MW -

18_Leiter Tap 230 Bus 3.2 MW -

19_Tongue River 230 Bus .9 MW -

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Table 4: 2016LW Category D Outage Summary

2016LW (SYSINT_200E-W_NOSTONGE_69TIED)

Bus Outage Consequential Load Loss Consequential Gen Loss

1_Lange 230 Bus - -

2_Lookout 230 Bus - -

3_St. Onge 230 Bus - -

4_S Rapid City 230 Bus - RCDC Tie Transfer

5_Westhill 230 Bus - -

6_Minnekhata 230 Bus - -

7_Yellowcreek 230 Bus - -

8_Osage 230 Bus - -

9_Hughes 230 Bus - -

10_Wyodak 230 Bus 36 MW (Station Service) 377 MW

11_Dry Fork 230 Bus 35 MW (Station Service) 420 MW

12_Donkey Creek 230 Bus 32.2 MW (Station Service) 286 MW

13_Carr Draw 230 Bus 10.1 MW -

14_Barber Creek 230 Bus 56.7 MW -

15_Pumpkin Buttes 230 Bus 26.4 MW -

16_Teckla 230 Bus 55.2 MW -

17_Reno 230 Bus 70.7 MW -

18_Leiter Tap 230 Bus 2.5 MW -

19_Tongue River 230 Bus 1 MW -

The dynamic analysis was performed only for the 2016HS and LW scenarios that did not include

St. Onge and had RCDC Tie transfers of 200 MW E-W. The Category D events listed in Table 3

and Table 4 were evaluated by modeling a 3-phase 5-cycle fault at the appropriate bus before

clearing that bus and running the simulation for 5 seconds. There was no evidence of cascading or

system instability in any of the scenarios in the steady-state or transient 2016HS Category D outage

analysis.

3.3. Voltage Stability Analysis

The voltage stability analysis consisted of a PV analysis of the 230, 69, and generator terminal

buses within the CUS. Load within the CUS area was scaled up, area generation was held constant,

and power was imported into the area in order to determine the collapse point. The voltage stability

margin is calculated by comparing the CUS area load in the initial base case to the scaled area load

determined at the collapse point. The NERC Category A, B, and D forced outages, as listed in

Appendix A, were analyzed for the 2016HS scenario with St. Onge in service. The established

WECC voltage stability criteria for acceptable real power (MW) margins are as follows: 5% for

Category A and B outages, 2.5% for Category C, and 0% for Category D outages.

Category A outage results indicated a 79% margin, Category B results indicated a 60% margin, and

Category D results indicated a 12% margin. Detailed results are available on request. The PV

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analysis indicated that adequate real power margin existed on the CUS for all evaluated

contingencies. These results were consistent with a separate reactive power margin analysis

performed for the CUS in 2011, which also indicated there were no voltage stability concerns on

the CUS.

3.4. Transient Stability Analysis

Transient analysis was performed to evaluate the dynamic characteristics of the transmission

system in proximity to the CUS footprint following various disturbances. With the exception of

Powder River Energy Corp. loads, system loads were modeled using the WECC generic motor load

penetration of 20 percent, with the under voltage load shedding function disabled to provide a

worst-case representation of system performance. The non-coal bed methane (CBM) PRECorp

loads were modeled as 30 percent motor load and the CBM loads were modeled as 80 percent

motor load.

The 2016HS and LW scenarios that were evaluated included RCDC Tie transfers of 200 MW

EW, no St. Onge project, and the 69 kV normal-open points were closed. The 2018LW and

2022HS scenarios that were evaluated included RCDC Tie transfers of 200 MW EW, no St.

Onge project, and the 69 kV normal-open points were open, except for a small number of 230/69

kV transformer prior outages. The critical outage combinations evaluated in the transient analysis

were selected based on significance with respect to proximity to local generation, clearing of a

CUS tie line, or performance during steady state analysis. The 3-phase faults listed in Table 5 were

simulated for the 2016, 2018, and 2022 system intact and prior outage scenarios.

For each five second simulation, plots including bus voltages and generator rotor angles at various

points on the transmission system were created, as well as simulation summary reports. Due to the

large quantity of files created, they are not included in this report but are available upon request.

It should be noted that in all evaluated scenarios, the N-1-1 outage combination of the Dryfork-

Hughes and Dryfork-Carr Draw 230 kV lines resulted in angular instability and voltage dip

violations. These results were invalid due to the fact that the system models did not reflect existing

operating procedures that require a manual reduction in generation output at the Dryfork plant for

the listed prior outages. These runbacks effectively mitigate any stability issues associated with the

stated outage combinations. These invalid violations were not included in the results summary.

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Table 5: Transient Stability Analysis Fault Summary

Fault Type Faulted Bus

(230 kV) Cleared Element

Fault

Duration

(cycles)

3Φ None None N/A

3Φ Carr Draw Carr Draw-Buffalo 230 4.25

3Φ Donkey Creek Donkey Creek-Pumpkin Buttes 230 3.5

3Φ Donkey Creek Donkey Creek-Reno 230 4.25

3Φ Donkey Creek Donkey Creek-Wyodak 230 4.25

3Φ Dryfork Dry Fork-Carr Draw 230 4.25

3Φ Dryfork Dry Fork Plant 3.5

3Φ Dryfork Dry Fork-Hughes 230 4.25

3Φ Dryfork Dry Fork-Tongue River 230 4.25

3Φ South Rapid City South Rapid City-Westhill 230 4.25

3Φ Reno Reno-Donkey Creek 230 4.25

3Φ Windstar Windstar-P. Buttes 230 & Windstar-Teckla 230 5.0

3Φ Wyodak Wyodak-Carr Draw 230 4.25

3Φ Wyodak Wyodak-Donkey Creek 230 4.25

3Φ Wyodak Wyodak-Hughes 230 4.25

3Φ Wyodak Wyodak-Osage 230 4.25

3Φ Wyodak Wyodak Plant 4.25

3Φ Osage Osage-Lange 230 + RCDC Tie Block 5.0+2.0

3Φ Wyodak Wyodak-Osage 230 + RCDC Tie Block 5.0+2.0

3Φ Lookout Lookout-Hughes 230 + RCDC Tie 5.0+2.0

3Φ Lange Lange-South Rapid City 230 + RCDC Tie Block 5.0+2.0

3.4.1. 2016HS Transient Stability Results

Post-contingent frequency criteria violations occurred at the Wygen1-3, NSS CT 1-2, NSS1, and

NSS2 13.8 kV terminal buses following 3-phase N-1 faults at the Wyodak or Donkey Creek 230

kV buses. The worst-case contingencies also had the potential to cause frequency dips below 59.6

Hz at the Wyodak, Gillette, Gillette_S, NSS1, and NSS2 69 kV buses, but the most critical

frequency dips remained at the generation terminal buses. The worst-case frequency dip for the

2016HS scenario occurred at the NSS2 13.8 kV bus following a 3-phase fault at the Wyodak 230

kV bus and the loss of the Wyodak-Osage 230 kV line. The frequency reached a minimum of 59.3

HZ and remained below the 59.6 HZ threshold for 13.9 cycles.

With the exception of the single issue mentioned above, all dynamic simulations resulted in

acceptable results for each evaluated study scenario. There were no additional post-contingent

voltage or frequency criteria violations, and all system oscillations were adequately damped.

3.4.2. 2016LW Transient Stability Results

_________________________________________________________________________________________________________________



18

The 2016LW results were consistent with the 2016HS results, with the exception of the worst-case

frequency dip remaining below the 59.6 HZ threshold for 13.8 cycles instead of 13.9 cycles.




3.4.3. 2018LW Transient Stability Results

The 2018LW results were consistent with the 2016HS results, with the exception of the worst-case

frequency dip remaining below the 59.6 HZ threshold for 14.2 cycles instead of 13.9 cycles.




3.4.4. 2022HS Transient Stability Results

The 2022HS results were consistent with the 2016HS results, with the exception of the worst-case

frequency dip remaining below the 59.6 HZ threshold for 15.4 cycles instead of 13.9 cycles. Initial

results were slightly better, but further investigation revealed an erroneous load at the NSS2 13.8

kV bus that skewed actual performance.




3.5. Results Summary

All evaluated scenarios confirmed a known issue of N-1 frequency dips below the 59.6 HZ

threshold for a period longer than 6 cycles at generator terminal buses in the Wyodak area. This

issue is currently being discussed among the affected parties. It is fully expected that an exemption

to the WECC System Performance Criteria will be finalized and adopted in the near future. The

exemption will be crafted to accommodate the system performance through the 10-year planning

horizon without impacting existing protection settings in the affected area.

One issue identified in the 2016-2018 time-frame was the sizing of the Osage 69 kV capacitor. In

the off-peak load scenarios, one capacitor was insufficient to prevent voltage sag on the 69 kV

system, and the second capacitor resulted in over-voltages. This operational issue had no impact

on the transmission system and will be investigated further.

All remaining issues identified through the 2018 time frame were mitigated through existing

operating procedures.

The addition of the St. Onge 230/69 kV substation project showed real benefits in the 2022HS

scenario by avoiding N-1-1 overloads on the Lookout and Yellowcreek 230/69 kV transformers.

_________________________________________________________________________________________________________________



19

The project also reduced loading on several 69 kV lines in the northern Black Hills system. This

project is currently planned for 2014, but the in-service date could be delayed until post-2016,

depending on actual load growth in the area.

Loading on the 100 MVA Lange 230/69 kV transformer became an issue in 2022 as well. The

overload was mitigated by dispatching all Rapid City gas-fired generation assuming Ben French

was unavailable. It is suggested that Rapid City load growth is monitored closely and the 100

MVA transformer be replaced with at least a 150 MVA unit in the event of a failure of the existing

unit, or as load growth requires.

The Wyodak 230/69 kV transformer exceeded the 100 MVA continuous rating by 4% following

the N-1-1 loss of the parallel 100 MVA transformer and the NSS2 plant in the 2022HS scenario.

All available gas-fired NSS CT generation was online, so there were no immediate measures to

reduce loading other than demand reduction. The load growth on the Wyodak 69 kV system

should be monitored closely to better define the critical time frame for mitigation options. Items

for future evaluation include a demand reduction plan for the critical contingency as well as

increased transformation capacity into the area.

The Lookout-Spearfish BEC 69 kV line became overloaded in the 2022 time frame, and the

Spearfish BEC-Hillsview 69 kV line reached its thermal limit. Loading on these lines was reduced

with the addition of the St. Onge substation, but the Lookout-Spearfish BEC 69 kV line loading

remained above the limit. It is suggested that the Lookout-Spearfish BEC 69 kV line be rebuilt

prior to 2022 regardless of the St. Onge addition, and the Spearfish BEC-Hillsview 69 kV line

continued to be monitored as load growth materializes in the area.

The Lookout-Sundance Hill #1 69 kV line clearances should be evaluated in order to determine the

ability to increase the rating to 58 MVA. The need for this project is primarily driven by

anticipated load growth on the Sundance Hill-Belle Creek 69 kV line, and is being addressed

outside of the TCPC process.

4. Transmission System Expansion

4.1. Previously Identified/Existing Projects

The following projects have been previously identified and are currently planned projects for the

CUS 230 kV or 69 kV systems.

4.1.1. Teckla-Osage-Lange 230 kV Line

The addition of a new 230 kV line from Teckla-Lange with an intermediate terminal at Osage is

currently in the Strategic Plan with an in-service date of 2014 for the Teckla-Osage segment of the

line and 2015 for the Osage-Lange segment. The driving factor for this line is the need for an

additional 230 kV circuit into the Black Hills and Rapid City load centers. The total cost for this

line is $53.5 million, with an approximate overall implementation schedule of 24 months.

_________________________________________________________________________________________________________________



20

4.1.2. St. Onge 230/69 kV Substation

The addition of the St. Onge substation and 150 MVA, 230/69 kV transformer is currently in the

Strategic Plan for 2014. Based solely on this reliability analysis, the in-service date of this project

could be delayed beyond 2018, or as load growth adjustments deem necessary. The estimated cost

of this project is $4,480,000 and will take approximately 12 months to complete. It is

recommended that the required project in-service date be delayed until 2018, and that further

analysis of area load distribution and expected growth be performed before making a final

determination on the implementation schedule of the project.

4.1.3. Lookout-Spearfish BEC 69 kV Line Rebuild

This 2-mile line segment consisting of 336 ACSR conductor is part of a larger project to rebuild the

entire 69 kV line between Lookout and Yellowcreek substations. The project is currently

scheduled in the Strategic Plan for completion in 2015. The results of this study indicate that the

project is not required until 2022. It is recommended that the further analysis of area load

distribution and expected growth be performed before making a final determination on the scope

and required implementation schedule of the project, and that the required in-service date of the

project be delayed until 2016 in the interim. The cost of this project is estimated at $3,900,000 and

will take approximately 10 months to complete.

4.1.4. Lookout-Sundance Hill #1 69 kV Line Rebuild

This 12.6-mile line segment consisting of 336 ACSR conductor is currently in the Strategic Plan

for completion of the rebuild in 2014. It is recommended that this project proceed as scheduled,

unless expected spot load growth requires completion at a sooner date. An increase in the rating

based on clearance of the existing line is currently under evaluation as an intermediate step, and the

rebuild is being addressed outside of the TCPC process. The cost of this rebuild is estimated at

$3,300,000 and will take approximately 8 months to complete.

4.1.5. Whitewood-Sundance Hill 69 kV Line Rebuild

This 20.5-mile line segment consisting of 336 ACSR conductor is currently in the Strategic Plan to

be rebuilt beyond 2015. The results of this study indicate that the project is not required until 2022

or as load growth develops, assuming the clearances on this line are verified and the rating can be

increased from 43 MVA to 58 MVA. A survey of line clearances should be performed to verify

the appropriate line rating. Further evaluation of the area load growth and system additions should

also be performed to determine the need to rebuild the line. The addition of the St. Onge substation

would require the rebuild of this line. The cost of this project is estimated at $5,430,000 and will

take approximately 10 months to complete.

4.1.6. Custer-Westhill 69 kV Line Rebuild

This 23.8-mile line is currently in the Strategic Plan to be rebuilt in 2014. The age of the line is the

primary driver for the project. The cost of this project is estimated at $6,307,000 and will take

approximately 9-12 months to complete.

_________________________________________________________________________________________________________________



21

4.1.7. Osage-Newcastle 69 kV Line Rebuild

This 15-mile line consisting of 3/0 conductor is currently in the Strategic Plan to be rebuilt in 2013.

The age of the line is the primary driver for the project. The cost of this project is estimated at

$3,790,000 and will take approximately 8 months to complete.

4.1.8. Exemption from NERC/WECC System Performance Criteria

CUS members and neighboring utilities are developing an agreement for an exemption from the

WECC Disturbance-Performance Table (Table W-1) of Allowable Effects on Other Systems as it

pertains to minimum frequency dips following a Category B event. The stated exemption will

make current system performance acceptable and will nullify performance criteria violations. It is

expected that the agreement will be enacted and submitted to WECC in 2012.

4.2. Recommended Projects

The following transmission projects are recommended for possible future inclusion in the BHBE

LTP. Further analysis of the expected load growth and completion of other system upgrades is

necessary to confirm the need and expected in-service date of these projects.

4.2.1. Additional Wyodak-Area Transformation Capacity

The 2022HS scenario identified insufficient transformation capacity to serve the Wyodak-area 69

kV load following a single N-1-1 outage. This scenario did not reflect the anticipated retirement of

the NSS1 generation, which would compound the problem. Since the issue was not encountered

prior to the 2022HS time-frame in this analysis, there is sufficient lead time to evaluate the problem

and associated area load growth in greater detail before developing a preferred solution. This issue

will be monitored in subsequent planning assessments.

5. Conclusions

An open and transparent process was utilized in conducting the 2011 Local Transmission Plan

study. Stakeholders were provided several opportunities for involvement and input into the study

process and scope. Through this process, the TCPC participants believe they have fulfilled the

requirements of Attachment K to the Joint Open Access Transmission Tariff (JOATT).

The need for several previously planned projects was confirmed in the 2011 study process, and a

new reliability concern was identified for further analysis and stakeholder consideration before

developing a final long-term build out plan. A review of expected load growth and planned

resource development should continue to be incorporated in the development of the next ten-year

LTP.

Also, the critical nature of the loss of a 230/69 kV transformer on the CUS system, in conjunction

with the considerable lead time necessary to replace one, underscores the importance of

maintaining a spare transformer to mitigate the impacts of a failure.

_________________________________________________________________________________________________________________



22

Assessment of the identified system enhancements will continue through additional transmission

planning studies and the next TCPC study cycle. Active stakeholder involvement will be a key

component as the process continues. This will ensure the CUS will effectively meet the long-term

requirements for all transmission customers.

Cascading and instability were not identified as valid issues in the 2011 TCPC analysis. All

identified violations of NERC and WECC TPL criteria were accompanied by a suggested

mitigation plan, including estimated cost and implementation schedule. It was determined that this

analysis satisfied the requirement of the TPL-001 through 004 Standards for CUS transmission

providers.

_________________________________________________________________________________________________________________



A-1

Appendix A

Prior and Forced Outage Lists

_________________________________________________________________________________________________________________



A-2

Steady-State and Transient Prior Outages PO 230 SERIES PO GEN SERIES PO X SERIES

LABEL DESCRIPTION LABEL DESCRIPTION LABEL DESCRIPTION

SYSINT System Intact GEN-1 Wyodak Unit XFMR-1 Wyodak XFMR 1

230-1 Goose Crk-Sheridan GEN-2 Dryfork Unit XFMR-2 Wyodak XFMR 2

230-2 Buffalo-Sheridan GEN-3 Wygen3 Unit XFMR-3 Westhill XFMR

230-3 Buffalo-Kaycee GEN-4 LRS Unit XFMR-4 Osage XFMR

230-4 Casper-Claimjpr GEN-5 DJ Unit #4 XFMR-5 Hughes XFMR

230-5 Casper-DJ XFMR-6 Lange XFMR 1

230-6 Sheridan-T. River XFMR-7 Lange XFMR 2

230-7 T. River-Arvada XFMR-8 Lookout XFMR 1

230-8 Arvada-Dryfork XFMR-9 Lookout XFMR 2

230-9 Dryfork-Carr Draw XFMR-10 Yellowcreek XFMR

230-10 Dryfork-Hughes XFMR-11 South Rapid XFMR

230-11 Buffalo-Carr Draw XFMR-12 St. Onge XFMR

230-12 Wyodak-Carr Draw XFMR-13 Minnekhata XFMR

230-13 Carr Draw-Barber Creek

230-14 Barber Creek-PButtes

230-15 Windstar-PButtes

230-16 PButtes-Teckla

230-17 Teckla-Antelope

230-18 Yellowcake-Windstar

230-19 Windstar-Dave Johnston

230-20 Windstar-Aeolus

230-21 Teckla-Osage

230-22 Osage-Lange

230-23 Reno-Teckla

230-24 Donkey Creek-Reno

230-25 Donkey Creek-Pumpkin

230-26 Wyodak-Donkey Creek #1

230-27 Wyodak-Osage

230-28 Wyodak-Hughes

230-29 Hughes-Lookout

230-30 Yellow Creek-Osage

230-31 Lookout-Yellow Creek

230-32 Osage-Minnekhata

230-33 Westhill-Minnekhata

230-34 St. Onge-Lookout

230-35 Lange-St. Onge

230-36 Lange-South Rapid City

230-37 South Rapid City-Westhill

230-38 RCDCW-South Rapid

230-39 Westhill-Stegall

_________________________________________________________________________________________________________________



A-3

1 TECKLA-WINDSTAR 35 WESTHILL 230.-MINNKHAT 230. #1 LINE 69 LKO-KIRK 69 103 RCSOUTH1 230.-RCSOUTH2 69.0 #1 XFMR

2 BUFFALO 230.-CARR DRA 230. #1 LINE 36 LAR.RIVR 230.-STEGALL 230. #1 LINE 70 SUNDHILL 69.0-ST.ONGE 69.0 #1 LINE 104 ST.ONGE 230.-ST.ONGE 69.0 #1 XFMR

3 BUFFALO 230.-KAYCEE 230. #1 LINE 37 ARCHERTS 345.-LAR.RIVR 345. #1 LINE 71 TEKLA 230.-PUMPKIN 230. #1 LINE 105 MINNKHAT 230.-MINNKHAT 69.0 #1 XFMR

4 BUFFALO 230.-SHERIDAN 230. #1 LINE 38 OSAGE 230.-LANGE 230. #1 LINE 72 RICHMHL-YELOWCRK 69 106 MBPP-1 24.0 #1 GEN

5 CARR DRA 230.-WYODAK 230. #1 LINE 39 OSAGE 230.-TEKLA 230. #1 LINE 73 YELOWCRK-WHITEWOOD 69 107 BENFRNCH 13.8 #1 GEN

6 CARR DRA 230.-BARBERCK 230. #1 LINE 40 OSAGE 230.-YELOWCRK 230. #1 LINE 74 WYODAK 69.0-HUGHES 69.0 #1 LINE 108 NSS1 13.8 #1 GEN

7 CARR DRA 230.-DRYFORK 230. #1 LINE 41 OSAGE 230.-MINNKHAT 230. #1 LINE 75 WYODAK 69.0-NSS2 69.0 #1 LINE 109 RCCT1 13.8 #1 GEN

8 CASPERPP 230.-DAVEJOHN 230. #1 LINE 42 LANGE 230.-RCSOUTH1 230. #1 LINE 76 PACTOLA-YWCRK 69 110 RCCT2 13.8 #2 GEN

9 CASPERPP 230.-CLAIMJMP 230. #1 LINE 43 LANGE 230.-ST.ONGE 230. #1 LINE 77 HUGHES 230.-DRYFORK 230. #1 LINE 111 RCCT3 13.8 #3 GEN

10 CASPERPP 230.-RIVERTON 230. #1 LINE 44 RENO 230.-TEKLA 230. #1 LINE 78 CAMBELL-LNG TIE 69 112 RCCT4 13.8 #4 GEN

11 CASPERPP 230.-SPENCE 230. #1 LINE 45 RENO 230.-DONKYCRK 230. #1 LINE 79 SUNDHILL-BELLECRK69 113 NSS2 13.8 #2 GEN

12 CASPERPP 230.-LATIGO 230. #1 LINE 46 SIDNEY 230.-SIDNEYDC 230. #1 LINE 80 RCSOUTH1 230.-RCDCW 230. #1 LINE 114 NSSCT1 13.8 #1 GEN

13 DAVEJOHN 230.-DIFICULT 230. #1 LINE 47 SIDNEY 230.-STEGALL 230. #1 LINE 81 DONKYCRK 230.-PUMPKIN 230. #1 LINE 115 NSSCT2 13.8 #1 GEN

14 DAVEJOHN 230.-WINDSTAR 230. #1 LINE 48 LOOKOUT1 230.-YELOWCRK 230. #1 LINE 82 ST.ONGE-WHITEWOOD 69 116 WYGEN 13.8 #1 GEN

15 DAVEJOHN 230.-WINDSTAR 230. #2 LINE 49 LOOKOUT1 230.-HUGHES 230. #1 LINE 83 TONGRIVR 230.-ARVADA 230. #1 LINE 117 WYGEN2 13.8 #1 GEN

16 DAVEJOHN 230.-LAR.RIVR 230. #1 LINE 50 LOOKOUT1 230.-ST.ONGE 230. #1 LINE 84 TONGRIVR 230.-DECKER 230. #1 LINE 118 WYGEN3 13.8 #1 GEN

17 DAVEJOHN 230.-STEGALL 230. #1 LINE 51 BFRENCH-SRC 69 85 PUMPKIN 230.-BARBERCK 230. #1 LINE 119 LNGCT1 13.8 #1 GEN

18 GOOSE CK 230.-SHERIDAN 230. #1 LINE 52 BENFRNCH 69.0-LANGE 69.0 #1 LINE 86 DRYFORK 230.-ARVADA 230. #1 LINE 120 DRYFORK 19.0 #1 GEN

19 GOOSE CK 230.-YELOWTLP 230. #1 LINE 53 BF-PACTOLA 69 87 LKO-SPFSH-YELOWCRK 69 121

20 KAYCEE 230.-MIDWEST 230. #1 LINE 54 CAMBELL 69.0-LANGE 69.0 #1 LINE 88 MINNKHAT-EDGEMONT 122

21 CLAIMJMP 230.-MIDWEST 230. #1 LINE 55 CMBL-4TH-BF 69 89 CUSTER-MINNKHAT 123

22 SHERIDAN 230.-TONGRIVR 230. #1 LINE 56 PACTOLA-CUSTER 69 90 WYODAK 230.-WYODAK 69.0 #1 XFMR 124

23 WYODAK 230.-OSAGE 230. #1 LINE 57 CUSTER 69.0-WESTHILL 69.0 #1 LINE 91 WYODAK #2 230-69 XFMR 125

24 WYODAK 230.-HUGHES 230. #1 LINE 58 KIRK 69.0-YELOWCRK 69.0 #1 LINE 92 WESTHILL 230-69 XFMR 126

25 WYODAK 230.-DONKYCRK 230. #1 LINE 59 KIRK 69.0-YELOWCRK 69.0 #2 LINE 93 LANGE 230-69 XFMR #1 127

26 WYODAK 230.-DONKYCRK 230. #2 LINE 60 RCS-CAMBELL 69 94 LANGE 230-69 XFMR #2 128

27 YELLOWCK 230.-WINDSTAR 230. #1 LINE 61 HUGHES-OSAGE 69 95 LOOKOUT 230-69 XFMR #1 129

28 AEOLUS 230.-WINDSTAR 230. #1 LINE 62 NSS1 69.0-WYODAK 69.0 #1 LINE 96 LOOKOUT 230-69 XFMR #2 130

29 AEOLUS 230.-WINDSTAR 230. #2 LINE 63 NSS1 69.0-NSS2 69.0 #1 LINE 97 YELOWCRK 230-69 XFMR 131

30 WINDSTAR 230.-LATIGO 230. #1 LINE 64 OSAGE 69.0-88 OIL 69.0 #1 LINE 98 LAR.RIVR 230.-LAR.RIVR 345. #1 XFMR 132

31 WINDSTAR 230.-PUMPKIN 230. #1 LINE 65 WHITEWOOD-LANGE 69 99 OSAGE 230.-OSAGE 69.0 #1 XFMR 133

32 AULT 345.-LAR.RIVR 345. #1 LINE 66 LKO-SPFSHPRK 100 STEGALL 115.-STEGALL 230. #1 XFMR 134

33 WESTHILL 230.-STEGALL 230. #1 LINE 67 LOOKOUT 69.0-SUNDHILL 69.0 #1 LINE 101 STEGALL 115.-STEGALL 230. #2 XFMR 135

34 WESTHILL 230.-RCSOUTH1 230. #1 LINE 68 LOOKOUT 69.0-SUNDHILL 69.0 #2 LINE 102 HUGHES 230.-HUGHES 69.0 #1 XFMR 136

STEADY STATE FORCED OUTAGES

_________________________________________________________________________________________________________________



B-1

Appendix B

Load and Resource

Assumptions

_________________________________________________________________________________________________________________



B-2

Table B1: Load and Resource Assumptions

BUS # GENERATOR NAME GENERATOR OUTPUT (MW)

2016HS 2016LW 2018LW 2022HS

66730 WYODAK 377 377 377 377

73285 BENFRNCH 18 18 18 18

73288 NSS1 18 18 18 18

73289 RCCT1 0 0 0 0

73291 RCCT2 0 0 0 0

73292 RCCT3 0 0 0 0

73293 RCCT4 0 0 0 0

73321 OSAGE1 0 0 0 11

73322 OSAGE2 0 0 0 11

73323 OSAGE3 0 0 0 11

73341 NSS2 90 90 90 90

73520 BFDIESEL 0 0 0 0

74014 NSS_CT1 0 0 0 38

74015 NSS_CT2 38 0 0 38

74016 WYGEN 91 90 91 91

74017 WYGEN2 97 98 100 98

74018 WYGEN3 106 98 101 106

74029 LNG_CT1 38 0 20 38

74399 BHPLPLAN 106 0 0 105

76301 ARVADA1 0 0 0 0

76302 ARVADA2 0 0 0 0

76303 ARVADA3 0 0 0 0

76305 BARBERC1 0 0 0 0

76306 BARBERC2 0 0 0 0

76307 BARBERC3 0 0 0 0

76309 HARTZOG1 0 0 0 0

76310 HARTZOG2 0 0 0 0

76311 HARTZOG3 0 0 0 0

76404 DRYFORK 420 420 440 440

76502 SPFSHPRK 0 0 0 0

TOTAL CUS GENERATION: 1399 1209 1255 1490

TOTAL CUS LOAD + LOSSES: 967 736 741 1071

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