MISO SPP Coordinated System Plan Study Report - Southwest Power … miso spp csp... ·...

MISO-SPP Coordinated System Plan Study Report

June 30, 2015

Table of Contents 1 Executive Summary .......................................................................................................................... 1

2 Introduction ..................................................................................................................................... 1

3 Stakeholder Involvement ................................................................................................................. 2

3.1 Third Party Coordination ................................................................................................................. 3

4 Scope ................................................................................................................................................ 4

5 Future Development ........................................................................................................................ 5

5.1 Sensitivities ...................................................................................................................................... 6

6 Model Development ........................................................................................................................ 7

6.1 Economic Model .............................................................................................................................. 7

6.2 Reliability Models ............................................................................................................................. 9

6.2.1 Dynamics ........................................................................................................................... 9

6.3 Constraint Assessment..................................................................................................................... 9

7 Cost Estimates ................................................................................................................................ 10

8 Economic Evaluation ...................................................................................................................... 10

8.1 Issues Identification ....................................................................................................................... 10

8.1.1 Historical Congestion Analysis ........................................................................................ 10

8.1.2 Projected Congestion Analysis ........................................................................................ 11

8.2 Economic Transmission Solution Development ............................................................................ 11

8.2.1 APC Methodology ........................................................................................................... 12

8.2.2 Screening Process ........................................................................................................... 12

8.2.3 Benefit-to-Cost Analysis .................................................................................................. 13

8.2.4 Potential Interregional Projects for Recommendation ................................................... 13

8.2.5 Sensitivity Analysis .......................................................................................................... 20

9 Reliability Assessment.................................................................................................................... 20

9.1 Steady State Contingency Analysis ................................................................................................ 21

9.1.1 Issues Assessment ........................................................................................................... 21

9.1.2 Reliability Assessment Solutions Development .............................................................. 23

9.1.3 Solution Evaluation ......................................................................................................... 24

9.2 Dynamic Assessment ..................................................................................................................... 26

9.3 Review of Regional Projects ........................................................................................................... 29

9.4 No-harm Test on Economic Projects.............................................................................................. 29

10 Conclusions .................................................................................................................................... 30

10.1 Economic ..................................................................................................................................... 30

10.2 Reliability ..................................................................................................................................... 30

10.2.1 Dynamics ......................................................................................................................... 31

10.3 Interregional Cost Allocation ...................................................................................................... 31

11 IPSAC and Joint Planning Committee Recommendation ............................................................... 31

11.1 IPSAC Recommendation ............................................................................................................. 32

11.2 Joint Planning Committee Recommendation ............................................................................. 32

12 Regional Review Process ................................................................................................................ 32

12.1 Southwest Power Pool ................................................................................................................ 32

12.1.1 Project Review Process ................................................................................................... 32

12.1.2 SPP Regional Cost Allocation........................................................................................... 32

12.2 Midcontinent Independent System Operator ............................................................................ 32

12.2.1 Project Review Process ................................................................................................... 32

12.2.2 MISO Regional Cost Allocation ........................................................................................ 32

Appendix A .................................................................................................................................................. 33

Appendix B .................................................................................................................................................. 41

Table 1: MISO-SPP Coordinated System Plan Tasks ..................................................................................... 4

Table 2: Regional Business as Usual Future Major Assumptions .................................................................. 5

Table 3: MISO-SPP Coordinated System Plan Hurdle Rates ......................................................................... 8

Table 4: MISO-SPP Coordinated System Plan Economic Issues List ........................................................... 11

Table 5: Results of Benefit-to-Cost Analysis ............................................................................................... 13

Table 6: Sensitivity Analysis Results ............................................................................................................ 20

Table 7: Steady - State Thermal and Voltage Issues ................................................................................... 22

Table 8: Areas modeled in Dynamics Assessment ...................................................................................... 27

Table 9: Results of Fast Fault Screen .......................................................................................................... 28

Table 10: Selected Disturbances ................................................................................................................. 28

Table 11: Combined Project Results ........................................................................................................... 30

Table 12: Interregional Cost Allocation for Potential MISO-SPP Interregional Projects............................. 31

Table 13: Congested Flowgate Analysis ...................................................................................................... 41

Table 14: MISO Congested Flowgate Analysis ............................................................................................ 41

Figure 1: Elm Creek to Mark Moore 345 kV Project ................................................................................... 14

Figure 2: Elm Creek – NSUB (Tap of Mark Moore - Pauline 345 kV) 345 kV ............................................... 16

Figure 3: New Series Reactor on Alto – Swartz 115 kV ............................................................................... 17

Figure 4: S. Shreveport – Wallace Lake 138 kV Rebuild .............................................................................. 19

Figure 5: Map of Steady - State Thermal and Voltage Issues ..................................................................... 23

Figure 6: Map of Fisher - Rodemacher 230 kV Project ............................................................................... 25

Figure 7: Map of Gobbler Knob - Datto 161 kV Project .............................................................................. 26

Figure 8: Rotor Angle Response – Laramie River ........................................................................................ 33

Figure 9: Voltage Response - Laramie River................................................................................................ 34

Figure 10: Rotor Angle Response – Arkansas Nuclear One ........................................................................ 35

Figure 11: Voltage Response – Arkansas Nuclear One ............................................................................... 36

Figure 12: Rotor Angle Response – Turk ..................................................................................................... 37

Figure 13: Voltage Response – Turk ............................................................................................................ 38

Figure 14: Rotor Angle Response – Center ................................................................................................. 39

Figure 15: Voltage Response – Center ........................................................................................................ 40

1 Executive Summary The 2014 MISO-SPP Coordinated System Plan (CSP) was performed to evaluate the combined MISO &

SPP transmission systems in an effort to identify mutually beneficial transmission improvements. The

study was an 18-month effort that began in January 2014. MISO and SPP staff focused efforts on two

primary sets of analyses - an economic evaluation and a reliability assessment.

For the economic assessment, a 2024 joint model was built specifically for this study. SPP and MISO staff

evaluated the congestion resulting from the 2024 model to identify a list of economic needs. Based on

those needs, both staff and stakeholders collaborated to propose potential projects to solve the

identified issues, which were then tested for Adjusted Production Cost (APC) and other benefits. Based

on those results, SPP and MISO identified three projects for consideration as an Interregional Project:

Elm Creek to NSUB 345 kV;

Alto Series Reactor; and

South Shreveport – Wallace Lake 138 kV Rebuild.

Each of these projects individually demonstrate benefit to both SPP and MISO as well as APC benefit

that exceeds the cost of the project over the initial 20 years of the project life. These projects were then

recommended by MISO and SPP to the Interregional Planning Stakeholder Advisory Committee (IPSAC)

for endorsement to move from the interregional portion of the study onto the regional review process.

Both the MISO and SPP portion of the IPSAC endorsed the projects with no opposition. Based on that

recommendation the Joint Planning Committee (JPC) voted in favor for approving all three projects for

review in both the MISO and SPP regional processes.

To accomplish the reliability assessment, a 2024 joint power flow model reflecting generation dispatch

utilized in MISO and SPP’s respective regional planning processes was built specifically for the reliability

assessment. MISO and SPP staff also performed an ACCC assessment on the joint power flow model to

determine a list of reliability needs. Similar to the economic assessment, those needs were reviewed by

staff and stakeholders to develop potential projects addressing the issues. The projects that were tested

were compared to MISO and SPP regional projects that also fixed the corresponding needs to determine

if the potential Interregional Projects were more cost effective than the regional solutions. Based on the

results of the study, SPP and MISO did not identify any Interregional Projects for the sole purpose of

resolving reliability issues more cost effectively than MISO and SPP regional solutions.

2 Introduction The FERC-filed MISO-SPP Joint Operating Agreement (JOA) establishes a JPC comprised of

representatives of both MISO and SPP. The JPC is the decision-making body for coordinated

interregional transmission planning and is responsible for all aspects of coordinated interregional

transmission planning, including the development of a CSP. The JPC is charged with verifying that the

results of the study are accurate and meet the expectations of the JPC and IPSAC based on the study

scope.

The IPSAC was formed to provide an opportunity for stakeholders to review the development of the CSP

study and to provide guidance and recommendations to the JPC. IPSAC participation is open to all

stakeholders.

On an annual basis, MISO and SPP have agreed to review potential transmission issues identified by

each RTO or any stakeholder, in response to the RTO’s request, at an IPSAC meeting as part of an Annual

Issues Review process. The Annual Issues Review is administered by the JPC in coordination with the

IPSAC to determine whether there is a need for MISO and SPP to perform a CSP study. When MISO and

SPP determine a CSP study is warranted, the Order 1000 interregional coordination procedures outlined

in the MISO-SPP JOA will be used to guide the CSP study process.

The purpose of the MISO-SPP CSP study is to jointly evaluate seams transmission issues and identify

transmission solutions that efficiently address the identified issues to the benefit of both MISO and SPP.

This study incorporates an evaluation of economic seams transmission issues and an assessment of

potential reliability violations.

At the completion of the CSP study, the JPC shall produce a draft report documenting the study,

including transmission issues evaluated, studies performed, solutions considered, and if applicable, the

recommended Interregional Projects with the associated interregional cost allocation. The draft report

will be made available for stakeholder review. Taking into consideration the recommendation of the

IPSAC, the JPC shall meet and vote whether to recommend any Interregional Project(s) and the

associated interregional cost allocation identified in the CSP study report to both MISO’s and SPP’s

respective regional processes for review and approval by the respective Board of Directors.

The Annual Issues Review IPSAC meeting was held on January 21, 2014, in Dallas, TX. Multiple

stakeholders, along with MISO and SPP staff, presented proposed transmission issues that were

considered for evaluation in the CSP. The issues ranged from reliability issues, economic issues, and

issues identified due to the sub-regional power balance constraint between MISO North\Central and

MISO South. The feedback from stakeholders at this meeting indicated that there was a strong

consensus for moving forward with a CSP starting in 2014.

Following the IPSAC, the JPC held a meeting where it was formally decided to perform a CSP starting in

2014. The schedule for the 2014 SPP-MISO CSP study would be no longer than 18 months and would be

scheduled to conclude in June 2015.

3 Stakeholder Involvement

The MISO-SPP IPSAC is the joint stakeholder group which is utilized to provide stakeholders an

opportunity to comment on the CSP Study. The IPSAC’s role is to provide input and review on the

following items in the CSP Study:

i. study scope and analysis approach;

ii. joint planning models and input assumptions;

iii. identified seams transmission issues or opportunities;

iv. proposed transmission solutions and alternatives;

v. recommendation on transmission solutions; and

vi. CSP report.

The IPSAC met on multiple occasions throughout the CSP Study both in person and via conference calls.

The IPSAC met on the following dates:

i. November 6, 2013;

ii. January 21, 2014;

iii. April 8, 2014;

iv. May 12, 2014;

v. October 7, 2014;

vi. February 24, 2015;

vii. May 6, 2015; and

viii. June 18, 2015.

The IPSAC meetings were facilitated jointly by MISO and SPP staff, and the meetings were hosted by one

RTO or the other on an alternating basis. All meeting materials are maintained on each RTO’s respective

IPSAC webpage.

3.1 Third Party Coordination In addition to coordination between the RTOs and the stakeholders within each RTO, there were

opportunities to work with third party stakeholders. As an example, there were some projects which

could potentially provide value to Associated Electric Cooperatives, Inc. (AECI), which is a cooperative

located in Missouri. Due to AECI’s location it is possible that they would be interested in certain projects

identified in the CSP.

If it was determined that a project could provide value to a third party, that party was contacted to

determine if there was any interest in that party participating in that project along with MISO and SPP.

While there were a few projects where this took place, as you will see below, none of those projects

were identified as being more cost effective or efficient than other Interregional Projects or regional

solutions.

4 Scope At the first IPSAC meeting held in November 2013, stakeholders proposed 34 transmission issues in

preparation for the start of the Annual Issues Review process. The submitted issues were reviewed by

the JPC for consideration to be evaluated in the CSP. The selected issues to be evaluated in the CSP

study were used to identify and evaluate potential Interregional Projects that may provide benefits to

MISO and SPP. A broad range of issues were proposed, including the following:

congestion;

integration of the MISO South region;

expanded market operation by SPP;

real-time operational issues;

reliability issues; and

public policy requirements1.

During the development of the CSP study scope the JPC took into consideration those proposed issues.

A high-level overview of the scope of the CSP study is shown in the table below:

Table 1: MISO-SPP Coordinated System Plan Tasks

MISO-SPP CSP Tasks

Scope Development

Develop and finalize scope document for CSP study

Develop detailed schedule for CSP study

Economic Evaluation and Reliability Assessment

Economic Evaluation Reliability Assessment

Future and Model Development

Perform steady-state reliability assessment using jointly developed power flow models

Historical and Projected Congestion Analysis

Test system stability using scenario(s) appropriate for studying dynamics.

Solution Development Determine if there are interregional alternatives to proposed regional solutions

Solution Evaluation and Evaluate potential

1 It should be noted that while there was not a specific assessment focused on public policy issues, all approved

public policy mandates and targets were included in the models used for the economic and reliability assessment.

Robustness Testing transmission solutions, as needed, based on identified issues.

Reliability Analysis

Determine interregional cost allocation

Draft Coordinated System Plan study report

Regional Evaluation and Cost Allocation (if needed)

5 Future Development The CSP study future was a Business as Usual (BAU) Future, developed from the 2015 MISO

Transmission Expansion Plan (MTEP15) and the 2015 SPP Integrated Transmission Plan 10-Year

Assessment (ITP10) BAU Futures.

MISO’s MTEP 15 BAU Future captures all current policies and trends in place at the time of futures

development and assumes they continue, unchanged, throughout the duration of the study period. All

applicable Environmental Protection Agency (EPA) regulations governing electric power generation,

transmission and distribution are modeled. Demand and energy growth rates are modeled at a level

equivalent to the 50/50 forecasts submitted into the Module E Capacity Tracking (MECT) tool. All

current state-level Renewable Portfolio Standard (RPS) and Energy Efficiency Resource Standard (EERS)

mandates are modeled. To capture the expected effects of environmental regulations on the coal fleet,

12.6 GW of coal unit retirements are modeled.

SPP’s 2015 ITP10 BAU Future-(F1) utilizes inputs provided by SPP stakeholders to develop the modeling

inputs based on the assumption that policy requirements will remain constant. Stakeholders provide to

SPP their anticipated level of renewable resources to meet all required mandates and targets.

Renewable resources include 3.3 GW of new wind and 20.5 MW of new solar. Less than 1 GW of coal

unit retirements are modeled in the 2015 ITP10. The load forecast used in the 2015 ITP10 BAU (F1) is a

50/50 load forecast.

Table 2: Regional Business as Usual Future Major Assumptions

Regional BAU

Futures

Demand and Energy

Growth

Retirements Natural Gas Price

(2014$)

RPS (10-year incremental GW)

CO₂ Price

DSM (annual demand reduction

in year 10 for EE/DR)

MISO 0.8% 12.6 GW Coal

$4.30 3.6 GW wind/ 1.1 GW Solar

None 6,000 GWh/ 12 MW

SPP 1.3% < 1 GW Coal $5.41 3.3 GW Wind/ 20.5 MW Solar

None Embedded in Load

5.1 Sensitivities In additional to the BAU future described above, MISO and SPP agreed, based on stakeholder feedback,

to also perform three sensitivities. These sensitivities were used to evaluate the impacts of a carbon

price, higher natural gas price forecast, and the Sub-Regional Power Balance Constraint (SRPBC)

between MISO /Central and South impacts on congestion between the two planning regions. 2

For the carbon price sensitivity, a carbon price of $64 dollars was used. This was derived from the MISO

MTEP 15 Public Policy Future. The carbon price is applied to the model year 2024 in an effort to capture

changes in generation dispatch and market economics assuming a carbon tax.

The natural gas price sensitivity is used to evaluate the impact of rising natural gas prices on the

performance of the Interregional Projects. The natural gas prices used were derived from an SPP 2015

ITP10 sensitivity.

The Sub-Regional Power Balance Constraint sensitivity is an attempt to replicate the power transfer

limits and constraints between the two MISO sub-regions (North/Central and South) consistent with the

operation of the current MISO Market. The effect of the SRPBC on MISO’s market dispatch is currently

the subject of a dispute and settlement discussions between MISO and SPP3. Pending the outcome of

those discussions, it is unknown how this constraint will be utilized in the future, and this sensitivity is

only meant to reflect one possibility which is consistent with how the MISO Market is currently being

operated.

The SRPBC sensitivity models the difference between generation and load in the MISO South Region

with an adjustment for interchange transactions with the balancing authority areas connected to the

MISO South sub-region. Additionally, the SRPBC is modeled to reflect the following market criteria:

hurdle rate of 9.57 $/MWh for transfers above 1000 MW; and

maximum transfer limit of 2000 MW4.

Sensitivities were used to further evaluate the potential Interregional Projects. This evaluation utilizing

the sensitivities provides additional information that the JPC can use in determining whether or not to

propose an Interregional Project to the respective RTOs.5

2 The Sub-Regional Power Balance Constraint as used in this report refers to the 1000 MW contract path between

Ameren, AECI, and Entergy. 3 FERC dockets Docket Nos. EL14-21, EL14-31, ER14-1174, EL11-34.

4 This sensitivity was designed prior to increasing the Operational Reliability Coordination Agreement (ORCA)

transfer limit to 3,000 MW which is the current limit. 5 It is not a requirement that a project perform well in the sensitivities in order to be recommended to the RTOs.

6 Model Development

6.1 Economic Model Two economic models were built: a 2019 model and a 2024 model. As the CSP Study is focused on the

10th year of the study horizon, the 2024 model was the primary model used for issues evaluation,

screening, and project development. The 2019 model was utilized for the 20-year financial analysis to

extrapolate data points beyond the 2024 model year.

Both MISO and SPP utilize Ventyx’s PROMOD model in their respective regional planning processes for

their economic evaluations. In a similar manner, PROMOD was used in the CSP Study. The PROMOD

model was built starting with the base data provided by Ventyx. Ventyx creates and compiles this data

from publicly available information and their proprietary sources and processes. In each RTO’s regional

processes MISO and SPP then update the model with data specific to the MISO and SPP regions through

their own respective stakeholder processes.

As a starting point for the CSP Study the applicable respective regional PROMOD models were merged.

Data for the SPP region and for the Associated Electric Cooperatives, Inc. (AECI) region was pulled from

the SPP regional PROMOD model. Data for the MISO region and all regions east of MISO was pulled from

the MISO regional PROMOD model.

Modeling Footprint The joint CSP economic model footprint included: MISO, SPP, AECI, Manitoba Hydro, MRO, PJM, SERC, and TVA. The SPP footprint and balancing authority was modeled to include the Integrated System as a member of the SPP RTO6. Transmission Topology The transmission topology used in the 2019 and 2024 models was created using the latest MISO MTEP 15 and SPP 2015 ITP10 power flow models. Note that PJM, SERC, TVA, and Manitoba Hydro areas were based on MISO’s MTEP modeling of external areas that is largely based on the Eastern Reliability Assessment Group (ERAG) Multi-regional Modeling Working Group (MMWG) series models; unless specific regions have provided MISO updated information. The AECI region was enhanced from the ERAG model to include AECI’s approved firm construction plan and any updates as included in the 2015 ITP10 model. Existing DC interconnections between the Eastern Interconnection and the Western Interconnection and ERCOT were modeled using profiles from SPP’s 2015 ITP10 study. Load Forecasts The load forecasts for the MISO and SPP region were the forecasts used in the MISO MTEP 15 BAU Future and SPP 2015 ITP10 BAU Future. The load forecasts utilized reflect a 50/50 case. The load shape

6 The Integrated System (IS) was included as a part of the SPP System. The IS is comprised of Western Area Power

Administration Upper Great Plains Region (WAPA), Basin Electric Cooperatives (Basin), and Heartland Consumer Power District (Heartland). The IS members are joining SPP as transmission owning members in October 2015.

profiles are from the same year as the wind profiles to ensure synchronization. Demand response and energy efficiency were modeled consistent with how each planning region models it in their respective regional BAU Futures. Generation The existing resource mix came from the SPP 2015 ITP10 and MISO MTEP 15 models for their respective

regions. Retirements were modeled based on each RTO’s BAU assumptions. New generation, including

siting, came from each planning region’s current BAU resource expansion plan. The resource expansion

plan was incorporated into the model using the same process as the rest of the modeling data. Data

from the SPP 2015 ITP10 F1 was utilized for the SPP and AECI regions. All other data was sourced from

the 2015 MISO MTEP.

The hourly profiles for renewables were developed using data from NREL and were time-synchronized with load shapes. The hourly profiles were based on data for 2005, except for the MISO South region and portions of SERC which used data from 2006. Fuel Prices Coal, oil, and uranium fuel prices were provided by Ventyx. After comparing the natural gas prices from the respective MISO and SPP BAU futures and noting that no significant difference exists between the two, the JPC agreed to use the natural gas prices from MISO’s MTEP 15 BAU future. Hurdle Rates The CSP study used the hurdle rates from MISO’s MTEP15 BAU future for the following areas: 1) where only MISO is interconnected (e.g., MISO-PJM, MISO-TVA, MISO-MHEB); and 2) AECI-TVA, TVA-PJM, PJM-SERC, SERC-TVA, SERC-AECI. MISO and SPP developed and agreed to the hurdle rates between MISO-SPP, MISO-AECI, and SPP-AECI. The specific values used for the hurdle rates in the study were provided to the IPSAC.

Table 3: MISO-SPP Coordinated System Plan Hurdle Rates

Hurdle Dispatch Commit

MISO to SPP $7.55 $10.00

SPP to MISO $5.09 $10.00

MISO to AECI $7.55 $10.00

AECI to MISO $8.29 $10.00

SPP to AECI $1.50 $10.00

AECI to SPP $10.00 $10.00

Stakeholder Review After staff concluded the initial efforts on developing the model, the consolidated economic model was

provided to stakeholders for their review and suggested edits. These suggested edits were reviewed by

MISO and SPP staff and included in the final economic models as appropriate. Throughout the study the

economic model was refined to address modeling errors as they were identified.

6.2 Reliability Models A 2024 summer peak power flow model was built for the CSP reliability assessment. The model utilizes

generation dispatch consistent with both MISO and SPP regional study processes. As a starting point the

2014 MISO MTEP power flow model was merged with the 2015 SPP ITP10 power flow model. The MTEP

model provided the most current MISO topology and dispatch and the ITP10 model provided the same

for the SPP footprint. The MISO footprint used a Local Balancing Authority (LBA) dispatch and includes

all approved MTEP14 Appendix A projects. The SPP footprint used a Consolidated Balancing Authority –

Security Constrained Economic Dispatch (CBA-SCED) and excluded all 2015 ITP10 projects approved in

January 2015 by the SPP Board of Directors. The modeling footprint and transmission topology are

consistent with what was described in Section 7.1 for the economic model.

The following steps were taken to accomplish the merge of the MTEP and ITP power flow models:

extracted SPP with ties from the MTEP model;

pulled SPP from the 2015 ITP10 model and applied it to the MTEP model;

applied SPP ties from the MTEP; and

verified MISO and SPP Interchange was unchanged.

Stakeholder Review

After staff concluded the initial efforts on developing the model, the consolidated power flow model

was provided to stakeholders for their review. Throughout the study the issues were refined to address

modeling errors as they were identified.

6.2.1 Dynamics

The dynamics assessment also included a jointly developed model consisting of the MISO MTEP14

model, the SPP 2015 MDWG model, and the 2013 MMWG series for the external footprint. The

dynamics assessment was run using a 2019 light load case.

As a starting point, the 2014 MISO MTEP model was merged with the 2015 ITP10 reliability model in

order to utilize the generation dispatch that is consistent with both MISO and SPP regional models. The

MTEP model provided the most current MISO topology and dispatch and the ITP10 model provided the

same for SPP.

6.3 Constraint Assessment The NERC book of flowgates was used as the initial source in the selection of the flowgates for use in the

event file. MISO and SPP evaluated the additional flowgates used in the current MTEP and ITP10 studies

and identified a mutually agreed upon list of constraints to use for the MISO-SPP CSP study.

7 Cost Estimates Cost estimates were developed utilizing the assumptions MISO and SPP respectively use in their regional

planning processes. If the project was geographically located within MISO’s footprint, MISO’s project

cost estimates were utilized. If the project was geographically located within SPP’s footprint, SPP’s

project cost estimates were utilized. SPP applied the SPP region-wide average of 17% for the Net Plant

Carrying Charge Rate (NPCC) and approximately 8% for the Discount Rate. MISO applied the MISO

region-wide average of 17.4% for the NPCC Rate and approximately 8% for the Discount Rate.

Two separate cost estimate methodologies were utilized. The first was for project screening. In the CSP

these estimates are called the conceptual cost estimates. These estimates are derived by using generic

data which is used by each RTO in their respective region. That data is compiled based on historical data

for projects previously constructed in each region and stakeholder feedback. While the actual values

used in the cost estimates may vary between the RTOs, this is a reasonable assumption as costs

associated with transmission development vary by region. MISO and SPP’s cost estimation processes are

consistent in the process that is used to develop a cost estimate at this stage of the study. The

assumptions used by MISO and SPP for these cost estimates were reviewed with the IPSAC.

The second cost estimate is called the study estimate in the CSP. The study estimate was developed for

those projects which are being considered by the JPC for recommendation as an Interregional Project.

This estimate is expected to be a +/- 30% level estimate. MISO utilizes their internal staff in the

Transmission Developer Qualification Selection group to develop the study level estimate. SPP contracts

with a consultant to develop the study level estimate. While MISO and SPP have their own processes for

calculating this estimate, both RTOs target a cost estimate that is within +/-30%.

8 Economic Evaluation

8.1 Issues Identification As previously stated, the JPC reviewed 34 transmission issues submitted by stakeholders for

consideration to be included in this study scope. In addition to the submitted transmission issues, the

JPC included in the study scope an evaluation to review economic congestion utilizing historical top

congested flowgates from market reports and projected congestion resulting from the joint economic

model developed for this study effort.

8.1.1 Historical Congestion Analysis

The purpose of the historical congestion analysis is to identify congested flowgates based on current and

past market activity. The historically congested flowgates were evaluated to determine whether similar

congestion is occurring in the 2024 CSP Study economic model. If there is congestion on that flowgate in

the model to a sufficient degree, then it will be evaluated to determine if there is an efficient and cost

effective interregional solution. If that historically congested flowgate does not show up in the 2024 CSP

Study model, MISO and SPP staff reviewed to determine the reason.

MISO and SPP reviewed the MISO and SPP market reports and identified flowgates along the MISO – SPP

seam. After identifying the applicable flowgates, MISO and SPP staff reviewed the CSP model to

determine if the model reflected similar congestion as to what is described in the respective market

reports. If the flowgate is not congested in the CSP model, staff reviewed to confirm that the issue was

resolved through a MISO or SPP previously approved regional project. The results are shown in Appendix

B.

These results demonstrate that the seams flowgates that are described in the respective market reports

as being congested are either shown as being congested in the CSP model or they are not congested in

the CSP model because the congestion is expected to be mitigated by a previously approved planned

project.

8.1.2 Projected Congestion Analysis

The projected congestion analysis involved identifying the top congested flowgates based on the 2024

CSP Study model. The flowgates were ranked using the following indicators:

1. Binding Hours – number of hours in a year the flowgate is binding

2. Shadow Price – reduced production cost for 1 MW increase of thermal rating on the flowgate

3. Congestion Costs – flowgate shadow price times MW flow on the flowgate

Table 4: MISO-SPP Coordinated System Plan Economic Issues List

Issue Id

Constraint Name Contingency

M-1 Frederick Town AECI - Frederick Town AMMO 161 kV Lutesville - St Francois 345kV

S-2 North East - Charlotte 161 kV Iatan – Stranger 345 kV

M-5 Blue Earth - Winnebago 161kV Lakefield Junction - Lakefield 345kV

M-6 Wapello 161/69 kV Transformer T1 Wapello 161/69 kV Transformer T2

M-9 Prairie 345/230kV Transformer T2 Prairie 345/230kV Transformer T1

M-10 Swartz - Alto 115kV Baxter Wilson - Perryville 500 kV

M-11 Reed - Dumas 115kV Sterlington - El Dorado 500kV

S-12 Essex - Idalia 161 kV Essex - New Madrid 345 kV

M-13 Grimes – Mt Zion 138 kV Grimes – Ponderosa 230 kV

S-14 South Shreveport – Wallace Lake 138 kV Dolet Hills 345/230 kV Transformer

8.2 Economic Transmission Solution Development The historical and projected congestion analysis, combined with the issues submitted by stakeholders,

guided the development of transmission solution ideas that were evaluated as potential MISO-SPP

Interregional Projects. The solution development and evaluation were focused on the set of identified

congested flowgates that captured a majority of congestion costs (e.g., greater than 70%).

Each respective RTO staff and stakeholders were able to propose transmission solutions to address the

identified transmission issues. Solutions were solicited through the MISO-SPP IPSAC meetings.

MISO and SPP staff solicited a request for stakeholders to submit potential projects addressing

congestion identified in the issues list presented at the October 7, 2014 IPSAC meeting. Stakeholders

submitted a total of 39 projects addressing approximately 75% of the issues posted. In addition to

stakeholder submissions, staff submitted 15 additional projects for consideration.

8.2.1 APC Methodology

As stated in the MISO-SPP JOA, MISO and SPP agreed to jointly evaluate the benefits to the combined

MISO-SPP region and to each region individually, using an agreed upon APC metric over a multi-year

analysis. The APC is calculated for each simulated year and benefits for intermediate years between

simulated years will be based on interpolation. Benefits for years beyond the last simulated year will be

based on extrapolation. The total project benefit was determined by calculating the present value of

annual benefits for the first 20 years of project life after the projected in-service date.

The APC benefit metric is based upon the impact of the project on adjusted production cost, which is

adjusted to account for purchases and sales. Both MISO and SPP’s APC represents the summation of the

APC for the defined areas in each region. Each area’s production cost was adjusted for purchases and

sales as follows:

For each simulation hour in which an area is selling interchange, the APC was calculated by

multiplying the interchange sales MW times the area’s generation-weighted LMP and then

subtracting this value from the area’s production cost; and

For each simulation hour in which an area is purchasing interchange, the APC was calculated by

multiplying the interchange purchase MW times the area’s load-weighted LMP and then adding

this value to the area’s production cost.

8.2.2 Screening Process

A preliminary screening analysis was performed on all proposed transmission solution ideas to

determine the solution ideas that have the most potential and warrant further evaluation. All

consolidated transmission solution ideas and all transmission solution ideas which have potential value

were evaluated for APC benefits to MISO and SPP. If there were projects which appeared to be

duplicates, only one of the projects was evaluated.

The screening index was calculated by using results of one model year 2024 of APC benefits compared

to one model year 2024 costs. If the screening index was at least .5 and the project provided significant

benefits to both MISO and SPP, the project was considered to have passed screening.

Projects passing the screening process include:

St Francois – Fletcher 345 kV;

St Francois – Taum Sauk – Fletcher 345 kV;

Walker Tap – Rivtrin 138 kV;

Series Reactor on Alto – Swartz 115 kV;

S Shreveport – Wallace Lake 138 kV;

Elm Creek – Mark Moore 345 kV; and

Elm Creek NSUB 345 kV.

8.2.3 Benefit-to-Cost Analysis

To calculate an indicative benefit to cost ratio for proposed transmission solutions, a 20-year net present

value calculation of benefits and costs was used7. Benefits were calculated by the change in adjusted

production cost with and without the proposed Interregional Project. The adjusted production cost was

adjusted to account for purchases and sales. The APC benefit metric was calculated for the simulated

years 2019 and 2024. Benefits for intermediary years were calculated using interpolation and years

beyond 2024 using extrapolation. The period covered by the benefit and cost calculation was 20 years

starting with the project’s in-service year8. The annual costs were calculated using an average carrying

cost of existing Transmission Owners in MISO and SPP. The present value calculation assumed an 8%

discount rate.

Table 5: Results of Benefit-to-Cost Analysis

Project Description NPV Project Cost (2015-M$)

B/C Ratio Benefit: MISO%

Benefit: SPP%

Walker Tap - Rivtrin 138kV $48.7 1.05 117% -17%

St Francois - Fletcher 345kV $113 .51 88% 12%

Elm Creek – Mark Moore 345kV $156.3* 1.03 7% 93%

Elm Creek – NSUB 345kV $133.8* 1.22 20% 80%

Series Reactor on Alto – Swartz 115kV $5.4* 4.32 86% 14%

S Shreveport - Wallace Lake 138kV $17.7* 2.61 80% 20%

*Denotes study level cost estimates (+/- 30%)

8.2.4 Potential Interregional Projects for Recommendation

8.2.4.1 Elm Creek – Mark Moore 345 kV

The proposed Interregional Project Elm Creek – Mark Moore 345 kV is a new transmission project

heading north from an Elm Creek 345 kV substation in North Central Kansas (Cloud County) to the

current Mark Moore 345 kV in Southeastern Nebraska (Lancaster County) with a length of

approximately 100 miles. The Elm Creek 345 kV substation is being built as a part of the SPP Elm Creek –

Summit 345 kV project that was approved in the 2012 SPP ITP10. That project has an expected in-service

date of 2018.

7 There is not a B/C ratio requirement in the CSP study.

8 Initially MISO and SPP have made the assumption that the in-service date for all projects is 2024.

Figure 1: Elm Creek to Mark Moore 345 kV Project

This project was proposed to relieve congestion on the Northeast to Charlotte 161 kV flowgate. MISO

and SPP’s analysis shows that relieving the congestion on this flowgate provides benefit to both Parties.

This project relieves 23%9 of the congestion on the Northeast to Charlotte 161 kV flowgate. The number

of binding hours is reduced from 1,802 hours with the project to 1,307 with the project. However, in

addition to the relief to the Northeast to Charlotte 161 kV flowgate, this project also addresses

congestion on the Fairport – Osborn 230 kV which is a north-south flowgate east of the Kansas City area.

Congestion on this flowgate is reduced by 29%. While the Gentleman – Red Willow 345 kV flowgate is a

north-south flowgate geographically located in western Nebraska, it is a flowgate that can constrain

both the MISO and SPP markets. This flowgate is relieved by 10%. Additional congestion was relieved or

mitigated throughout the combined system, primarily along the north-south corridor.

9 This value is calculated by comparing the congestion scores with and without the project. The congestion score is

calculated by multiplying the binding hours times the average shadow price.

SPP estimated an engineering and construction (E&C) study-level cost estimate of approximately $164.4

million10 with an assumed in-service date of 2024. The $164.4 million E&C cost results in a 20-year

present value of $156.3 million11. MISO and SPP’s 20-year benefit analysis shows that over the first 20

years of the project’s life MISO and SPP are estimated to receive $161.8 million12 in APC benefit resulting

in a B/C ratio of 1.03. Of the $161.8 million of APC benefit, SPP is estimated to receive $150.4 million

with MISO receiving $11.3 million. Since the proportion of cost paid by MISO and SPP is based on the

proportion of benefits, both MISO and SPP’s B/C ratio is 1.03.

8.2.4.2 Elm Creek – NSUB (Tap of Mark Moore - Pauline 345 kV) 345 kV

The proposed Interregional Project Elm Creek – NSUB 345 kV is a new transmission project heading

north from an Elm Creek 345 kV substation in North Central Kansas (Cloud County) to a new 345 kV

substation that taps the existing Mark Moore – Pauline 345 kV line. This project has an estimated length

of 78 miles. The Elm Creek 345 kV substation is being built as a part of the SPP Elm Creek – Summit 345

kV project that was approved in the 2012 SPP ITP10. That project has an expected in-service date of

2018.

10

2015 dollars 11

The 20-year present value cost number is calculated using SPP’s 17% NPCC, factoring in depreciation, and discounting at 8%. 12

The 20-year present value benefit number is calculate using a discount rate of 8%.

Figure 2: Elm Creek – NSUB (Tap of Mark Moore - Pauline 345 kV) 345 kV

This project was proposed to relieve congestion on the Northeast to Charlotte 161 kV flowgate and is

mutually exclusive of the Elm Creek - Mark Moore 345 kV project discussed above. MISO and SPP’s

analysis shows that relieving the congestion on this flowgate provides benefit to both Parties. This

project relieves 19%13 of the congestion on the Northeast to Charlotte 161 kV flowgate. The number of

binding hours is reduced from 1,802 hours with the project to 1,413 with the project. However, in

addition to the congestion relief to the Northeast to Charlotte 161 kV flowgate, this project also

addresses congestion on the Fairport – Osborn 230 kV which is a north-south flowgate east of the

Kansas City area. Congestion on this flowgate is reduced by 23%. While the Gentleman – Red Willow 345

kV flowgate is a north-south flowgate geographically located in western Nebraska it is a flowgate that

can constrain both the MISO and SPP markets. This flowgate is relieved by 13%. Additional congestion

was relieved or mitigated throughout the combined system, primarily along the north-south corridor.

13

This value is calculated by comparing the congestion scores with and without the project. The congestion score is calculated by multiplying the binding hours times the average shadow price.

SPP estimated an engineering and construction (E&C) cost estimate of approximately $140.6 million14

with an assumed in-service date of 2024. The $140.6 million E&C cost results in a 20-year present value

of $133.8 million15. MISO and SPP’s 20-year benefit analysis shows that over the first 20 years of the

project’s life MISO and SPP are estimated to receive $165 million16 in APC benefit resulting in a 20-year

B/C ratio of 1.22. Of the $165 million of APC benefit, SPP is estimated to receive $132 million with MISO

receiving $33 million. Since the proportion of cost paid by MISO and SPP is based on the proportion of

benefits both MISO and SPP’s B/C ratio is 1.22.

8.2.4.3 New Series Reactor on Alto – Swartz 115 kV

The proposed Interregional Project New Series Reactor on Alto – Swartz 115 kV proposes to add a 10%

reactor on 100 MVA base in series with the Alto-Swartz 115 kV line. The reactor is to be normally

bypassed, and un-bypassed post-contingency for critical contingencies such as a loss of Baxter Wilson –

Perryville 500 kV. The Alto-Swartz 115 kV line with which the reactor would be placed in series is located

in North Central - Northwest Louisiana.

Figure 3: New Series Reactor on Alto – Swartz 115 kV

14

2015 dollars 15

The 20-year present value cost number is calculated using SPP’s 17% NPCC, factoring in depreciation, and discounting at 8%. 16

The 20-year present value benefit number is calculated using a discount rate of 8%.

This project was proposed to relieve congestion on the Swartz – Alto 115 kV flowgate. MISO and SPP’s

analysis shows that relieving the congestion on this flowgate provides benefit to both MISO and SPP.

This project completely mitigates the congestion on the Swartz – Alto 115 kV flowgate. Without the

reactor this flowgate is projected to be binding 292 hours with an average shadow price of

approximately $382. While the primary value from this project is addressing the congestion on Swartz –

Alto 115 kV, additional congestion is mitigated on other flowgates though in a smaller magnitude.

MISO estimated an engineering and construction (E&C) cost estimate of approximately $5.3 million17

with an assumed in-service date of 2024. The $5.3 million E&C cost results in a 20-year present value of

$5.4 million18. MISO and SPP’s 20-year benefit analysis shows that over the first 20 years of the project

life’s MISO and SPP are estimated to receive $23.4 million19 in APC benefit resulting in a 20-year B/C

ratio of 4.32. Of the $23.4 million of APC benefit MISO is estimated to receive $20.1 million with SPP

receiving $3.3 million. Since the proportion of cost paid by MISO and SPP is based on the proportion of


8.2.4.4 S. Shreveport – Wallace Lake 138 kV Rebuild

The proposed Interregional Project South Shreveport – Wallace Lake 138 kV rebuild proposes rebuilding

the existing 11 mile South Shreveport to Wallace Lake 138 kV line with 1533.3 CSRT/TW conductor along

with upgrades at the South Shreveport and Wallace Lake substations. The South Shreveport – Wallace

Lake 138 kV line is located in Northwestern Louisiana.

17

2015 dollars 18

The 20-year present value cost number is calculated using MISO’s 17.4% NPCC, factoring in depreciation, and discounting at 8%. 19


Figure 4: S. Shreveport – Wallace Lake 138 kV Rebuild

This project was proposed to relieve congestion on the South Shreveport – Wallace Lake 138 kV

flowgate. MISO and SPP’s analysis show that relieving the congestion on this flowgate provides benefit

to both MISO and SPP. This project completely mitigates the congestion on the South Shreveport –

Wallace Lake 138 kV flowgate. Without the rebuild this flowgate is projected to be binding 941 hours

with an average shadow price of approximately $120. While the primary value from this project is

addressing the congestion on the South Shreveport – Wallace Lake 138 kV, additional congestion is

mitigated on other flowgates though in a smaller magnitude.

SPP estimated an engineering and construction (E&C) cost estimate of approximately $18.5 million20

with an assumed in-service date of 2024. The $18.5 million E&C cost results in a 20-year present value of

$17.6 million21. MISO and SPP’s 20-year benefit analysis shows that over the first 20 years of the

20

2015 dollars 21

The 20-year present value cost number is calculated using MISO’s 17.4% NPCC, factoring in depreciation, and discounting at 8%.

project’s life MISO and SPP are estimated to receive $46.1 million22 in APC benefit resulting in a 20-year

B/C ratio of 2.61. Of the $46.1 million of APC benefit MISO is estimated to receive $36.8 million with SPP

receiving $9.2 million. Since the proportion of cost paid by MISO and SPP is based on the proportion of


8.2.5 Sensitivity Analysis

As previously described in Section 6, additional analyses were performed on projects being considered

for recommendation by the JPC using the three sensitivities. The proposed Interregional Projects that

are identified in the assessment utilizing the BAU Future were evaluated using the three sensitivities to

determine how the projects perform under these scenarios. After receiving input from stakeholders, the

study scope included a high natural gas price, carbon price, and modeling of the Sub-Regional Power

Balance Constraint as sensitivities.

With input from the IPSAC, the JPC set the high natural gas price to $8.66/MMBtu for 2024 and the

carbon price to $64/ton in 2024.

The table below demonstrates the potential change in APC benefit for each project. These are the

results of a one-year analysis utilizing the 2024 model. As an example, the High Natural Gas Price

Sensitivity indicated that the benefits attributed to the project Series Reactor on Alto – Swartz would

increase by 43% if the gas price was set to $8.66/MMBtu.

Table 6: Sensitivity Analysis Results

Project Description

% Change in APC Benefits (MISO and SPP combined)

High Natural Gas Price

Carbon Tax SRPBC

Series Reactor on Alto – Swartz 115kV +43% +37% +73%

S Shreveport - Wallace Lake 138kV -79% -58% -39%

New Elm Creek – Mark Moore 345kV +52% -62% -7%

New Elm Creek – NSUB 345kV +54% -67% -7%

9 Reliability Assessment The reliability assessment in this scope included multiple studies. This multi-faceted approach has

allowed MISO and SPP to evaluate various transmission issues near the MISO-SPP seam. The phases of

the reliability assessment included in the CSP study are:

1. Review of reliability projects that were identified in the respective regional planning

processes of MISO and SPP that are located near the seam to determine if there were

22


interregional alternatives to the currently proposed transmission solutions that should be

evaluated through the respective regional planning processes;

2. A steady state assessment was conducted using jointly developed power flow models

consistent with reliability processes used by each region; and

3. A dynamics assessment to test system stability using a light load power flow case.

Solutions to address the identified reliability issues were developed and reviewed in coordination with

the respective regional planning processes. These solutions, which may include alternative projects that

more effectively mitigate identified issues, were submitted by:

respective RTO staff;

stakeholders through regional planning processes; and

stakeholders through MISO-SPP IPSAC meetings

Transmission solutions to address identified reliability issues were evaluated to determine the most

efficient and cost-effective method to address the identified constraints. Projects addressing reliability

issues were also evaluated for potential economic benefits to MISO and SPP. The projects identified as

addressing the identified reliability issues were not found to provide substantial economic benefit to

MISO or SPP in the context of this study scope.

9.1 Steady State Contingency Analysis An N-1 contingency analysis was conducted using the Study models described in Section 6.2. Topology details can be found in Section 6.1.

9.1.1 Issues Assessment

Criteria used to determine the potential violations were as follows:

Monitored

o Facilities 100kV and above in the MISO and SPP footprints

o Thermal Overloads over 100%

o Base Case Voltages below .95pu

o Contingency Voltages below .90pu

o Or more stringent local planning criteria

Contingencies

o Full N-1

o MISO and SPP Category B contingencies submitted by stakeholders

The process that was followed to jointly develop the final issues list which was posted and made

available for stakeholders was as follows:

MISO and SPP performed separate contingency analyses and compared and verified that each

other’s results were consistent;

issues were reviewed on each respective transmission system; and

MISO and SPP used engineering judgement to filter out issues not electrically close to the seam.

MISO and SPP jointly performed separate base case (N-0) and contingency (N-1) analysis that provided a

list of potential thermal and voltage violations. The results were compared and verified. Engineering

judgment was used to filter out issues not electrically close to the seam. This initial issues list was

provided to stakeholders along with a request for potential solutions to address the potential violations.

After stakeholder feedback and additional validation was completed a final issues list was created. The

table below summarizes the number of potential reliability issues. The map below is an overview of all

the issues identified.

Table 7: Steady - State Thermal and Voltage Issues

Needs Overall Unique MISO System

SPP System

Overloads 50 18 14 4

Low Voltages 84 34 31 3

Figure 5: Map of Steady - State Thermal and Voltage Issues

9.1.2 Reliability Assessment Solutions Development

The issues list and reliability power flow model were made available to stakeholders. MISO and SPP

requested stakeholders submit any potential solutions that could address any of the listed issues. Staff

received 12 project submissions from four different study participants. In addition to stakeholder-

submitted projects, MISO and SPP Staff leveraged previously identified regional projects from the MTEP

and ITP processes, respectively. MISO and SPP analyzed these regional projects to determine if they

addressed the issues identified in the CSP:

SPP ITP Projects

o Evaluated 1401 projects from 2015 ITP10

o Evaluated 531 projects from 2015 ITPNT

MISO MTEP Projects

o Reviewed 578 projects from Appendix B and Target Appendix A

o Evaluated 8 projects from MTEP 15

In addition to all the projects listed above, staff also worked to create numerous potential solutions

addressing the issues specific to this study. Additionally, staff evaluated all potential projects identified

in the economic portion of the CSP. The CSP economic projects were evaluated to see if they provided

any reliability benefit in addition to the economic benefit.

9.1.3 Solution Evaluation

MISO and SPP evaluated projects to determine:

if benefit was provided to both MISO and SPP;

if thermal overloads were solved to under 100%;

if base case voltages were solved to within applicable planning criteria;

if contingency voltages were solved to within applicable planning criteria; and

if interregional solutions were more cost effective than MISO and SPP regional projects.

Two projects were highlighted throughout the process as being mutually beneficial to both MISO and

SPP.

9.1.3.1 Fisher to Rodemacher 230 kV

Fisher to Rodemacher is a proposed new 50 mile 230 kV line addressing issues identified in the study

located in west Louisiana. The project addresses thermal overloads in both MISO and SPP. The

conceptual cost of the project was estimated to be approximately $46M.

Figure 6: Map of Fisher - Rodemacher 230 kV Project

MISO and SPP determined this project was not cost effective as both RTO’s could address the overloads

with regional projects for approximately $10M each.

9.1.3.2 Gobbler Knob – Datto 161 kV

Gobbler Knob to Datto is a proposed new 20 mile 161 kV line addressing issues identified in the study

located in northeast Arkansas. The project addresses both thermal overloads and low voltages on the

MISO system. The project also addresses low voltages on the SPP transmission system, specifically on

portions of Southwestern Power Administration (SPA). The conceptual cost of the project was estimated

to be approximately $25M23

. The project potentially replaces $44M of regional upgrades on the MISO

system and $3M of upgrades on the SPA system.

23

This estimate is a conceptual level cost estimate which was proposed by a stakeholder. If this project was deemed to be a viable Interregional Project MISO and SPP would have developed a study level cost estimate which could change the cost estimate.

Figure 7: Map of Gobbler Knob - Datto 161 kV Project

MISO and SPP determined the project will not be recommended as a part of the MISO-SPP CSP due to

the limited participation of SPA in SPP’s planning region. However the project will continue to be

evaluated in the MISO regional process as an alternative to the MISO Targeted Appendix A project Jim

Hill to Datto rebuild. SPP will continue to work with SPA and will be available to provide any

coordination needed between SPP and others regarding SPA’s interest in this project.

9.2 Dynamic Assessment The dynamics assessment utilized a joint model developed from MISO and SPP’s regional models as

described in section 6.2.1 of this report. A 2019 light load case was developed in an effort to highlight

seasonal transient instability issues most likely to occur. MISO and SPP selected areas to be monitored

that were adjacent to the MISO-SPP seam shown in

Table 8: Areas modeled in Dynamics Assessment below.

Table 8: Areas modeled in Dynamics Assessment

SPP Areas MISO Areas 515 SWPA 645 OPPD 333 CWLD 600 XEL

520 AEPW 650 LES 356 AMMO 635 MEC

523 GRDA 652 WAPA 360 CWLP 615 GRE

536 WERE 608 MP 327 EES-EAI

540 GMO 613 SMMPA 332 LAGN

541 KCPL 620 OTP 351 EES

542 KACY 661 MDU 502 CLEC

544 EMDE 627 ALTW 503 LAFA

546 SPRM 633 MPW 504 LEPA

640 NPPD 694 ALTE

Disturbances for study were determined using POM-TS’s Fast Fault Screening (FFS) Tool. The POM-TS

FFS takes a single set of contingencies (N-1) and determines a severity ranking index (RI) and a critical

clearing time (CCT). The ranking index takes into account kinetic energy, torque, and voltage deviations

to determine a score. A shorter clearing time and higher severity index score indicate a more severe

disturbance. Contingencies resulting in a CCT of less than 9 cycles to clear were chosen for further

evaluation.

Table 9: Results of Fast Fault Screen summarizes the results of the FFS.

Four severe locations for study were selected, two each in SPP and MISO, based on maximum impact at

the seam. It was agreed that MISO would perform the studies for the two SPP faults and SPP would

perform the studies for the two MISO faults. This cross allocation of work served to help the respective

staffs understand the impact of faults occurring in the other RTO’s respective footprint. The four

locations selected were used to develop disturbance events for a time-domain analysis. Table 10:

Selected Disturbances provides the event descriptions for the four selected locations. Stability analysis

was accomplished using PTI’s PSS/E and PSSPLT software. During the analysis, monitored parameters

included:

generator rotor angles,

voltage deviation (0.7 ≤ Vbus ≤ 1.2),

oscillation damping,

out-of-step conditions, and

any additional local planning area criteria.

Table 9: Results of Fast Fault Screen

Bus (Severe Fault Location)

Area Name

Area Number

Critical Clearing Time (Cycles)

Ranking Index

Outaged Element Selected for Study

659131 LARAMIE 345kV WAPA 652 3 29.82 STEGALL 345kV Line MISO

345764 SIOUX 138kV AMMO 356 8.4 25.47 BRCKHSE2 138kV Line

631115 OTTUMWA 161kV ALTW 627 7.2 24.12 OTTUMWA3 Transformer

337860 WRIGHTSVILLE 500kV

EES-EAI

327 4.8 24.05 KEO 500kV Line

661016 COYOTE 345kV OTP 620 0.6 22.17 CENTER 345kV Line

500250 DOLETT HILLS 345kV CLEC 502 6 21.22 SW SHREVEPORT 345kV Line

337909 A.N.O. 500kV EES-EAI

327 6 21.15 PLEASANT HILL 500kV Line

SPP

507454 TURK 138kV AEPW 520 6 20.16 TURK 345kV Transformer MISO

659101 ANTELOPE 345kV WAPA 652 7.2 19.90 CHARLIE CREEK 345kV Line

659105 LELANDO 345kV WAPA 652 8.4 17.38 GROTON 345kV Line

657751 CENTER 230kV OTP 620 8.4 16.09 MANDAN 230kV Line SPP

Table 10: Selected Disturbances

Severe Fault Location

FFS CCT

Event Description

1 Laramie River 3 Three phase fault near the Laramie 345kV bus for 4 cycles, open the Laramie - Stegall 345kV Line to clear the fault

2 Arkansas Nuclear One

6 Three phase fault near the ANO 500kV bus for 5 cycles, open the ANO - Pleasant Hill 500kV Line to clear the fault.

3 Turk 6 Three phase fault near the Turk 138kV bus for 5 cycles, open the Turk

345/138/13.8kV three phase transformer to clear the fault

4 Center 8.4 Three phase fault near the Center 230kV bus for 5 cycles, open the Center - Mandan 230kV Line to clear the fault

Study results showed that no instability was found for the simulated events. All machines were stable

with good oscillation damping and bus voltages were within tolerances. The figures in Appendix A

demonstrate rotor angle and voltage responses for the four events.

9.3 Review of Regional Projects MISO and SPP staff reviewed reliability projects from their respective regional processes, highlighted in

section 9.1.2. No regional projects of one RTO were identified as replacing the need for a project in the

other respective regional process. Additionally there were no regional projects that could be replaced by

a joint Interregional Project which would address the issues from both regions.

9.4 No-harm Test on Economic Projects Interregional Projects identified to address congestion were evaluated to ensure they do not create

reliability issues. The evaluation may result in the modification of the Interregional Project or

identification of additional interregional facilities that are needed to mitigate the projected reliability

issue.

Staff utilized the 2024 joint power flow model used in the initial steady state assessment of this study to

perform the no-harm analysis. Individual ACCC runs were completed for each economic project that had

the potential to be recommended by the JPC. Below are the four projects that were tested:

Elm Creek to Mark Moore;

Elm Creek to NSUB5;


South Shreveport to Wallace Lake.

Staff compared the issues list from the original steady state assessment against the issues list resulting

from the ACCC assessments, including each economic project. This was done to determine if any new

reliability issues were created by each project.

After the conclusion of the no-harm evaluation for the four economic projects considered it was

determined that no new reliability issues were identified due to the inclusion of the economic projects

and that no mitigations were needed.

Elm Creek to Mark Moore 345 kV

o No new issues identified

Elm Creek to NSUB5 345 kV


Alto Series Reactor


South Shreveport to Wallace Lake 138 kV Rebuild


In addition to running each of the tested projects individually, they were analyzed as a group and again

no new reliability issues were identified due to the inclusion of the projects as a group.

10 Conclusions

10.1 Economic Based on the results of the economic assessment, MISO and SPP identified three projects for

consideration as Interregional Projects:

Elm Creek to NSUB 345 kV;


South Shreveport – Wallace Lake 138 kV Rebuild.

Each of these projects individually demonstrate benefit to both MISO and SPP as well as APC benefits

that exceed the costs of the projects over the initial 20 years of the project life.

These three projects recommended for consideration as an Interregional Project were evaluated to

ensure the reliability of the transmission system was not negatively impacted. As discussed in Section

9.4 the evaluation of these projects did not identify any new reliability issues as a result of these

projects. Additionally, staff evaluated the reliability of the transmission system if all three projects were

constructed. The results were consistent with the analysis from reviewing each project individually. No

additional potential reliability issues were identified.

MISO and SPP also analyzed these three projects as a group to ensure that the benefits did not

significantly change as a result of all three being in service. If all projects are assumed to be in service

the total NPV Benefit of the projects is $214.6 million resulting in a B/C ratio of 1.37.

Table 11: Combined Project Results

Project NPV Cost (2015 - M$)

NPV Benefit (2015 - M$)

B/C Ratio

Benefit: MISO%

Benefit: SPP%

Series Reactor on Alto – Swartz 115 kV 5.4 23.4 4.32 86% 14%

S. Shreveport – Wallace Lake 138 kV Rebuild

17.7 46.1 2.61 80% 20%

Elm Creek - NSUB 345kV 133.8 162.4 1.21 20% 80%

Combination 156.9 214.6 1.37 36% 64%

10.2 Reliability Based on the results of the study, MISO and SPP did not identify any joint transmission solutions for the

sole purpose of reliability that were more cost effective or more efficient solutions than MISO and SPP

regional solutions addressing regional reliability issues.

10.2.1 Dynamics

Results show that no instability was found for the simulated events. All machines were stable with good

oscillation damping and bus voltages were within tolerances.

10.3 Interregional Cost Allocation MISO and SPP have agreed to use the APC benefit metric to allocate the costs to each planning region of

proposed Interregional Projects addressing primarily economic congestion.

If the recommended Interregional Projects are approved by both the MISO and SPP Board of Directors

as an Interregional Project, the cost allocation between MISO and SPP will be allocated per the chart

below.

Table 12: Interregional Cost Allocation for Potential MISO-SPP Interregional Projects

Project E&C Cost M$

MISO Cost %

SPP Cost %

Elm Creek - NSUB 345 kV $140.7 20% 80%

Alto Series Reactor 115 kV $5.3 86% 14%

S. Shreveport - Wallace Lake 138 kV Rebuild

$18.5 80% 20%

11 IPSAC and Joint Planning Committee Recommendation As described in Section 9.3.3.5.1 of the MISO-SPP JOA, a draft report detailing the work efforts

completed as part of the Coordinated System Plan, including any proposed Interregional Projects, was

presented to the IPSAC on June 18, 2015. After review of the draft report, the IPSAC had the opportunity

to provide feedback and a recommendation, as determined by an IPSAC vote, on any proposed

Interregional Projects to the JPC. Both MISO and SPP stakeholders have a portion of the IPSAC vote.

Taking into consideration the recommendation from the IPSAC and the combination of MISO and SPP

stakeholders’ votes, the JPC met and voted whether to recommend the Interregional Projects and

associated interregional cost allocation, provided in this report, to both the MISO and SPP regional

processes for review and approval.

The Coordinated System Plan study report proposes three Interregional Projects to be recommended for

regional review:

Elm Creek - NSUB 345 kV;


S. Shreveport - Wallace Lake Rebuild.

11.1 IPSAC Recommendation The IPSAC net conference on June 18 resulted in feedback in support of the three proposed

Interregional Projects. Multiple stakeholders expressed support for the projects while there was no

voiced opposition.

In addition to the IPSAC input provided during the June 18 IPSAC net conference, the MISO stakeholders’

share of the IPSAC vote was conducted on June 24, 2015 at the MISO Planning Advisory Committee

meeting. The MISO portion of the IPSAC is represented by the sector representatives of the MISO

Planning and Advisory Committee. MISO stakeholders voted in favor of recommending all three

proposed Interregional Projects to both the MISO and SPP regional review processes with no opposition.

The SPP portion of the JPC requested that SPP stakeholders provide feedback on how they would like for

the SPP portion of the JPC to vote. The SPP stakeholders from the IPSAC held a conference call on June

19 to provide this feedback. The SPP stakeholders on the IPSAC include the members of the SPP Seams

Steering Committee (SSC) and a representative from each SPP Transmission Owner which is

interconnected with MISO’s transmission system. The SPP stakeholders voted unanimously to direct the

SPP portion of the JPC to vote in favor of recommending all three proposed Interregional Projects to

both the MISO and SPP regional review processes.

11.2 Joint Planning Committee Recommendation The MISO and SPP representatives of the Joint Planning Committee met on June 29, 2015 to formally

vote on the three proposed Interregional Projects to be recommended for review in both the MISO and

SPP regional processes. Taking into consideration the recommendation of the IPSAC, the JPC voted in

favor of recommending all three proposed Interregional Projects for review in both the MISO and SPP

regional processes.

12 Regional Review Process

12.1 Southwest Power Pool

12.1.1 Project Review Process

12.1.2 SPP Regional Cost Allocation

12.2 Midcontinent Independent System Operator

12.2.1 Project Review Process

12.2.2 MISO Regional Cost Allocation

Appendix A Figures 8-15 below show rotor angle and voltage responses for the four events analyzed in the dynamics

assessment described in section 9.2 of this report.

Figure 8: Rotor Angle Response – Laramie River

Figure 9: Voltage Response - Laramie River

A three phase fault was applied at the Laramie 345 kV bus and was cleared after four cycles by opening

Laramie to Stegall 345 kV line in WAPA. The total duration of the fault simulation was set to 12 cycles. A

second voltage spike, recorded around 9 cycles, is attributed to the operation of the Stegall back-to-back

HVDC tie. Overall system performance, measured through generator rotor angle and voltage response

within that subsystem, recovers within the prescribed constraints and remains stable. The primary

Critical Clearing Time for the Laramie 345 kV bus is 4.5 cycles.

Figure 10: Rotor Angle Response – Arkansas Nuclear One

Figure 11: Voltage Response – Arkansas Nuclear One

Figure 12: Rotor Angle Response – Turk

Figure 13: Voltage Response – Turk

A three phase fault was applied at the Turk 138 kV bus, and was cleared after four cycles by opening the

Turk to Sugarhill 138 kV line in AEP West. The total duration of the fault simulation was set to 12 cycles.

System performance, measured through generator rotor angles and voltage response within that

subsystem, recovers within the prescribed constraints and remains stable. The primary Critical Clearing

Time for the Turk 138kV bus is 4 cycles.

Figure 14: Rotor Angle Response – Center

Figure 15: Voltage Response – Center

Appendix B Table 13: Congested Flowgate Analysis

RTO Seams Flowgate In CSP Comment

SPP Pentagon to Mund (115 kV) No Congestion mitigated by SPP Approved Projects

SPP Circleville - King Hill (115 kV) Yes N/A

SPP Lake Road - Alabama (161 kV) No Congestion mitigated by SPP Approved Projects

SPP S1226 - Tekamah (161 kV) Yes N/A

SPP Eastowne Transformer No Congestion mitigated by SPP Approved Projects

SPP Hayes - Vine (115 kV) Yes N/A

SPP Iatan - Stranger (345 kV) Yes N/A

Table 14: MISO Congested Flowgate Analysis

Year Day Ahead/

Real Time

Constraint Name Contingency Description In CSP

2012 RT DPCGEN01_LACROSS_LACROCOULE16_1_1 ALMA UNIT6 (399MW) No

2012 RT FoxLk_Rutland_161kV_flo_LkfldGS_Wilmarth_345kV

LAKEFIELD-FIELDON-WILMARTH+SPS

No

2012 RT Oak_Grove_Galesburg_flo_Nelson_ElectricJct NELSON-ELECTRIC JCT 345 B (15502)

No

2012 RT NSP3405_BLUEART_BLUEAWINBA16_1_1 LAKEFIELD-FIELDON-WILMARTH+SPS

Yes

2012 RT DPCALW06_LANSING_TR1_TR1 GENOA-LANSING_161 No

2014 RT DPC16006_ADAMS_I_TR2_TR2 BEAVER CRK-HARMONY-ADAMS-RICE_161

No

2013 RT ALW16066_HIAWATA_TR1_TR1 FAIRFAX-ARNOLD_161 No

2013 DA HIAWATA TR1 FLO FAIRFAX-ARNOLD FAIRFAX-ARNOLD_161 No

2014 RT NSP3405_SOUTHBND_SOUTHBLUEA16_1_1 LAKEFIELD-FIELDON-WILMARTH+SPS

No

2014 RT ALW16X26_WAPELLO_TR91_TR91 WAPELLO 161/69 TR92 No


No

2014 RT ALW16085_ARORAHTS_ARORAJASPE69_1_1 JASPER-NEWTON_161 Yes

2014 DA SOUTHBND-BLUEART FLO LAKFLD-FLDN-WILMRTH


No

2014 DA ADAMS I TR2 FLO BVR-HARM-ADAMS-RICE BEAVER CRK-HARMONY-ADAMS-RICE_161

No

2014 DA WAPLLO TR91 FLO WAPLLO TR92 WAPELLO 161/69 TR92 No

2014 RT ALW16065_ARORAHTS_ARORAKLLG69_1_1 POWESHIEK-REASNOR 161 Yes

2013 DA FXLAKE-RTLND FLO LKFLDGS-FLDN-WLMRTH LAKEFIELD-FIELDON-WILMARTH+SPS

No

2014 RT ALW16015_KNOXVIL_KNOXVLUCAS69_1_1 BEACON-TRICOUNTY_161 Yes


No

2014 DA NELSON E T1 FLO HARTBURG - CYPRESS HARTBURG - CYPRESS 500 Yes

2014 DA IATAN-STR-CR1 FLO ST JOE-HAWTHORN ST JOE-HAWTHORN 345 No

2014 RT NelsonAT1500_230_ftlo_Hartburg500_Cypress HARTBURG - CYPRESS 500 Yes

2014 DA KNOXVIL-LUCAS FLO BEACON-TRICOUNTY BEACON-TRICOUNTY_161 Yes

2013 RT NSP3405_SOUTHBND_SOUTHBLUEA16_1_1 LAKEFIELD-FIELDON-WILMARTH+SPS

No

2014 RT NSPALE01_GLENMNT_GLENMREDRO11_1_1 EAU_CLA TR9 + KING-ECL-ARP_345

No

2012 DA ALBANY-BVR CH FLO CORDOVA-NELSON 15503 CORDOVA-NELSON 345 B (15503)

No

2014 DA ARORAHTS-KLLG FLO POWESHIEK-REASNOR POWESHIEK-REASNOR 161 Yes

2012 DA IATNA-STR-CR1 FLO STJ-HWTHRN-LK RD-NSH STJOE-HAWTHORN345+LAKERD-NASHUA161

No

2014 DA GLENMNT-REDRCK FLO ECL TR9+KNG-ECL-ARP EAU_CLA TR9 + KING-ECL-ARP_345

No

2013 DA OAKGR-GALES FLO NLSN ELCT JNT NELSON-ELECTRIC JCT 345 B (15502)

No

2013 RT FoxLk_Rutland_161kV_flo_LkfldGS_Wilmarth_345kV


No

2013 RT ALW16079_GLENWTH_TR1_TR1 GLENWTH-HAYWARD 161 No

2013 DA GLENWTH XF1 FLO GLENWTH-HAYWARD GLENWTH-HAYWARD 161 No


No

2012 DA ALW16015_KNOXVIL_KNOXVLUCAS69_1_1 SALEM 345/161 TR2 No

2014 DA CHARTON-LUCAS FLO OTTUMWA-WAPELO OTTUMWA-WAPELLO_161_1

No

2012 DA OAKGR-GALES FLO NLSN ELCT JNT NELSON-ELECTRIC JCT 345 B (15502)

No

2014 DA ADAMS I TR2 FLO BVR CRK-HRMNY-ADAMS BEAVER CRK-HARMONY-ADAMS-RICE_161

No

2013 DA SOUTHBND-BLUEART FLO LAKFLD-FLDN-WILMRTH


No

2013 DA CHARIT-LUCAS FLO OTTUMWA-WAPELLO OTTUMWA-WAPELLO_161_2

No


2013 DA LACROSS-COULE FLO ALMA UNIT ALMA UNIT6 (399MW) No

2013 DA FAIRFAX-ARNOLD FLO HIAWATA-ARNOLD HIAWATA-ARNOLD_161 No

2013 DA LUCAS-LUCAS TP FLO OTTUMWA-MONTEZUMA OTTUMWA-MONTEZUMA_345

Yes

2013 DA WELLSBURG TR1 FLO ABBOTT-TRAER-DYSART ABBOTT-TRAER-DYSART 161

No


No


2014 RT IATSTRSTJHAW ST JOE-HAWTHORN 345 No

2014 DA OTTMWA-WAPLLO 2 FLO OTTMWA-WAPLLO 1 OTTUMWA-WAPELLO_161_1

Yes

2012 DA ECALMS-DAVENPRT FLO QUAD CTY-ROCK CRK QUAD CITIES-ROCK CREEK 345 (0405)

No

2013 DA OTTMWA-WAPLLO 2 FLO OTTMWA-WAPLLO 1 OTTUMWA-WAPELLO_161_1

Yes

2012 DA STWRTVL-STEWVLJ FLO BVR-HRMY-ADMS-RICE BEAVER CRK-HARMONY-ADAMS-RICE_161

No

2012 RT IATSTRSTJHAW STJOE-HAWTHORN345+LAKERD-NASHUA161

No

2013 DA BLUEART-WINBAGO FLO LKFLD-FIELDN-WLMRT LAKEFIELD-FIELDON-WILMARTH+SPS

Yes

2013 DA LANSING TR1 FLO GENOA-LANSING 161 GENOA-LANSING_161 No

2014 DA STGABE-AACCOR6 FLO WILLOW GLEN-WATERFORD

WILLOW GLEN-WATERFORD 500+WTRF AT1

No

2014 DA PLANTATION-FERRIDAY FLO NATCHEZ-PLANTN NATCHEZ S-VIDALIA-PLANTATION 115

No

Date post:	23-Apr-2020
Category:	Documents
Upload:	others
View:	2 times
Download:	0 times

MISO SPP Coordinated System Plan Study Report - Southwest Power … miso spp csp... ·...

Documents