Planning Subcommittee

May 14, 2020

CPPTT Issue A1 (PAC005): Review MISO planning study objectives, methodologies and assumptions

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Purpose:

• Collaborative review of MISO's planning processes – reliability

and economic planning, transmission service request,

generation interconnection, generation deliverability and

generation retirement.

Key Takeaways:

• Strong stakeholder interest for an in-depth review of MISO

planning study objectives, methodologies and assumptions

• MISO will review planning processes, identify correlation and

document rationale for any disparities between them.

• MISO seeking stakeholder input on areas of opportunities for

what potential adjustments are required to the methodologies

and/or assumptions to ensure comparable treatment

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Purpose & Key Takeaways

MISO Planning Objectives

MISO Board of Directors Planning PrinciplesMake the benefits of an economically efficient

electricity market available to customers

by identifying transmission projects which provide access

to electricity at the lowest total electric

system cost

Develop a transmission plan that meets all

applicable NERC and Transmission Owner planning criteria and safeguards local and

regional reliability through identification

of transmission projects to meet those

needs

Support state and federal energy policy

requirements by planning for access to a changing resource mix

Provide an appropriate cost

allocation mechanismthat ensures that costs

of transmission projects are allocated in a manner roughly commensurate with

the projected benefits of those projects

Analyze system scenarios and make

the results available to state and federal

energy policy makers and other stakeholders to provide context and

to inform choices

Coordinate planning processes with

neighbors and work to eliminate barriers to reliable and efficient

operations

Fundamental Goal

The development of a comprehensive expansion plan that meets reliability, policy, and economic needs

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Planning Roles and Responsibilities

MISO

•Independent review and transparency of all transmission needs and solutions

•Ensure compliance with NERC reliability

•Develop plans to improve market efficiency / enable policy

•Recommend regional plan

Transmission Owner/Developer

•Own and operate transmission lines

•Plan and propose solutions for local needs

•Support MISO planning needs

•Implement all projects included by MISO in Regional plan

State Regulators

•Approval of need and/or siting of specific projects (most states)

•Input into policy and other planning assumptions

Other Stakeholders

•Advise MISO on planning policy and process

•Review and Input to planning process and resulting plans

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Each study process has a uniquely defined purpose

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•Perform a global NERC TPL assessment to identify Transmission Issues

•Assess solutions provided by members / stakeholders / staff to ensure compliance

•Select preferred solutions and recommend to BOD

MTEP-Reliability Planning

•Retirement or suspension of a plant can negatively affect MISO’s ability to operate the system reliably.

•Before a plant owner suspends or retires a generating unit, the impact needs to be assessed and approval obtained

Retirement

•Facilitate the interconnection of a new Generation Resource to the Transmission System or the upgrade of an existing Generation Resource (e.g., capacity uprate, etc.).

•Evaluate reliability impact of the resource interconnection to identify any necessary system upgrades.

Generation Interconnection (GI)

•MISO’s economic planning process helps develop transmission plans that offer MISO customers better access to the lowest electric energy costs.

•Utilizing a regional perspective, MISO and stakeholders identify near-term transmission issues, long-term economic opportunities and new network upgrades to enhance overall efficiency.

Economic Planning

•To ensure existing generator(s) maintain ability to deliver to MISO load without being constrained (“bottled up”)

MTEP Annual Deliverability/NRIS

•MISO serves as a transparent and neutral facilitator for transmission service planning, resulting in fair and open access to the region’s transmission system.

•Requests for transmission service must be evaluated for impacts on system reliability.

Transmission Service Request (TSR)

Model Development Overview

• Planning Model development at MISO is a collaborative

process with significant stakeholder interaction

• Planning Model development is coordinated with MISO

members as well as neighboring regions

• Reliability and Economic models are built annually and

support MISO’s core planning functions needed to

ensure tariff and NERC compliance

• MISO processes are independent from the regional

(ERAG MMWG) model building process

Stakeholder Roles

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Reliability Model Assumptions Are Set

To Meet NERC and Tariff Obligations

Season Scenarios are defined in the ERAG MMWG model building procedure . MISO references these definition within our MOD-32 Manual in section 3.3

NERC Standards & the MISO Tariff require that generation dispatch reflect the expected system conditions for the planning horizon

The NERC TPL 01-5 transmission planning standard provides some additional clarification that the base dispatch should reflect firm transmission service and sensitivities to base dispatch should look at credible changes to assumptions in order to sufficiently stress the System

Reliability Models With The Proposed Wind/Solar

Dispatch Assumptions

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Representative Year

Model scenario

Expected Load LevelProposed Wind

Output (%) Assumption

Proposed Solar Output (%)

Assumption

MISO Groups that use

model

Year – Two (Base)TPL -001-4 R2.1.1

SummerPeak

The sum. peak demand expected to be served

Capacity Credit 15.7%

Capacity Credit 50%

MTEP, Ret,TSR

Year – Two R2.1.4(Sensitivity)

Spring Light Load

Early morning load within 30-50% of Sum peak

No Wind0%

No Solar0%

MTEP

Year – Five (Base)TPL -001-4 R2.1.1

SummerPeak

The sum. peak demand expected to be served

Capacity Credit 15.7%

Capacity Credit 50%

MTEP, Ret,TSRGI, Del, Econ

Year – Five R2.1.4(Sensitivity)

SummerShoulder

70% to 80% of the Summer Peak Load

83% 0% MTEP, GI

Year – Five (Base)TPL -001-4 R2.1.2

SummerShoulder

70% to 80% of the Summer Peak Load

Average Wind 27%

Average Solar31%

MTEP

Year – Five R2.1.4(Sensitivity)

Spring Light Load

Early morning load within 30-50% of Summer peak

High Wind70%

No Solar0%

MTEP

Year – Five TPL -001-4 NA

Winter PeakThe winter peak demand

expected to be served.Average Wind

67%Average Solar

0%MTEP

Year – Ten (Base)TPL -001-4 R2.2.1

SummerPeak

The sum. peak demand expected to be served

Capacity Credit 15.7%

Capacity Credit 50%

MTEP, Econ

*Proposed values in red

Modeling Assumption Overview

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•Approved MTEP Upgrades and Target Appendix A upgrades

•GIP: prior queued network upgrades

Topology

•Load levels submitted by Load Serving Entities and TO’s for each of the respective models

•Econ: Up until MTEP21, demand and energy values were pulled from Module E data. Starting in MTEP21, Policy Planning will be working with the State Utility Forecasting Group (SUFG) at Purdue University to conduct a survey to more accurately determine future demand, DER, and DSM levels. Forecasts are adjusted based on each future’s narrative.

Demand

•Latest available MMWG representation for external entities

•Outreach to neighbor PCs in January for any additional updates to MMWG

•GIP: external prior queued generation requests

External Representation

•Only units with a signed GIA will be represented

•Existing or Signed GIAs are eligible for dispatch.

•Attachment Y units are not eligible for dispatch

•GIP: Prior Queued (Generation not in MTEP model but higher queue priority than Study units), Study units are included in the model

•Econ: Signed GIAs that are publicly announced will be included in the base model data. Forecasted units from the Policy Planning’s Electric Generation Expansion Analysis System (EGEAS) study are included on top of the base generation fleet. Each model year/future has a different set of forecasted units based on its specific future narrative (i.e. MTEP19 Accelerated Fleet Change (AFC) future has high renewable penetration and had more forecasted wind units included). Futures also include retirement assumptions, typically age-based.

Generation

•Amite South

•Down Stream of Gypsy

•Western

•WOTAB

VLR guidelines

How Generation is Dispatched

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•Generation = AI + Load + Losses for each individual local balancing area

•Generators with NRIS dispatched first

•Area Interchange (AI) Calculated by Transaction workbook. Firm Transactions as agreed by parties of each transaction

•Load obtain from BLG submittal

•Losses are variable

•Four dispatch steps performed for each area

•Behind the Meter Generation: As submitted by LBA in MOD profiles

•Hydro: 5 year seasonal average (EIA 923)

•Renewables (Wind, Solar): Dispatched to Seasonal level or Capacity Credit Level. Currently both are capacity credit level by unit, unless information is unavailable for said unit, where the system wide capacity credit level is used.

•Dispatch algorithm will maintain desired Area Interchange.

•Firm Resources (NR, ER w/ TSR), dispatched by LBA Tier Order to satisfy each areas generation requirement. Area swing last unit committed.

MTEP Reliability Planning LBA Dispatch•Model TSRs agreed to in the transactions workbooks

submitted by data submitters

•MWEX – Not Implemented

•MHEX – Restricted to Firm OASIS Transactions

•NDEX – Not Implemented

•North/South Split – Restricted to Firm OASIS Transactions

•St Louis Load Pocket – Not Implemented

•Econ: TSRs are not modeled. Interchange between regions is constrained by hurdle rates, but all dispatch is otherwise determined by a Security Constrained Economic Dispatch (SCED). Regional constraints such as MWEX are modeled just like in the market. Flows on the interfaces are constrained to their identified stability limits. MISO Overall Import/Export Level – Restricted to Firm OASIS Transactions

TSR Modeling / Regional Constraints:

•Amite South

•Down Stream of Gypsy•Western

•WOTAB

VLR guidelines

How Generation is Dispatched

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•MTEP models are starting point in DPP model dispatch

•Prior queued units are dispatched per fuel dispatch table with output of MTEP existing units scaled down to accommodate to create the benchmark case

•Study Units are dispatched per fuel dispatch table with output of MTEP existing and prior queued generation scaled down to accommodate to create the Study Case

DPP Dispatch

•MTEP models are updated to reflect prior approved retirements/suspensions as a starting point in generation retirement study. Base case has a study unit On and changed case has the study unit OFF using security constrained economic dispatch SCED.

Retirement

•Models use a Security Constrained Economic Dispatch (SCED). Each model contains a year’s worth of load data at hourly granularity

•TSRs are not modeled. Interchange between regions is constrained by hurdle rates

Economic Planning

•MTEP models are starting point, top 30 plants (highest Dfax greater than 5%) contributing to flow on the flowgateidentified by the TARA tool (harmers) will be ramped up by the tool to the granted/requested NR level

•Also ramp-up all generators that have Dfax ≥ 5% and MW impact ≥ 20% of the line rating

•The rest of MISO generation is ramped down uniformly by the MW amount that is ramped up

MTEP Annual Deliverability/NRIS

•Begin with MISO near term and out year (rollover period) models. Add transmission projects with in-service dates during the study timeframe that have been submitted by the transmission owners since the creation of the base models.

•Add higher queued TSRs in CONFIRMED/SUTDY mode that use the same path as the requested TSRCounter flow TSRs are not modeled as they may mask the impact of the requested TSR

TSR

Planning Analyses performed to Identify Needs/Values

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•Steady state, Dynamic and Voltage stability, Transfer assessment, Short Circuit*

MTEP-Reliability Planning

•Steady state, dynamic (as applicable)

Retirement

•Steady state, Dynamic and Short Circuit

GI

•Adjusted Production Cost savings from congestion relief

Economic Planning

•Steady state

MTEP Annual Deliverability/NRIS

•Transfer capability assessment

TSR

*Delegation agreement

Monitoring Elements and Contingencies

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• MISO + First tier neighbors

• P1-P7+Extreme

MTEP-Reliability Planning

• MISO + First tier neighbors

• P1-P7 + Ops/SH input

Retirement

• MISO + First tier neighbors

• P1-P7 (except P3/P6)

GI

• MISO, MHEB, NY, PJM, SERC, SPP, TVA, AECIZ

• P1 (match the market)

Economic Planning

• MISO + First tier neighbors

• P1

MTEP Annual Deliverability/NRIS

• MISO + First tier neighbors

• P1-P2

TSR

System performance, Criteria Used to Identify System Deficiency and the need for a Corrective Action Plan (CAP)

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•NERC TPL 01-4

•TOs planning criteria

MTEP-Reliability Planning

•FAC-002

•Network Analysis - compare pre-retirement case to post-retirement case for P1-P2 and selected P3-P7 contingencies -Identified needs valid only if overload >5% PTDF, 3% OTDF

•Criteria documented in section 6.2.5 of BPM-020

Retirement

•FAC-002

•ERIS: 5% for system intact and 20% for a specific contingency condition DFAX

•NRIS/Deliverability: 5%/5% DFAX

•DFAX criteria is document in section 6.1.1.1.8 of BPM-015

GI

•Congested flowgates must meet a pre-defined shadow price threshold and are reviewed with stakeholders (BPM-020, section 4.4.2.3)

•FERC Orders 890 and 1000 broadly define need for economic planning studies

Economic Planning

•If a study generator does not contribute more than 5% of the DFAX on any flowgate with a loading violation it is considered fully deliverable

•DFAX criteria is document in section 6.1.1.1.8 of BPM-015 and section 4.5.2 of BPM-020

MTEP Annual Deliverability/NRIS

•Compare pre-transfer to post-transfer case for base, (N-1) and (N-2) contingencies recommended by stakeholders

•Cut-off of 5% for Power Transfer Distribution Factors (PTDF) and 3% for Outage Transfer Distribution Factors (OTDF) and only net impacts larger than 1MW will be considered. Criteria documented in section 5.3.2.3.11 of BPM-020

TSR

Impact of overloads on planning processes

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115%

loaded

100.5% loaded

G

GG

G

G

C

D

E

P12

Contingency

F

Generation at various “upstream locations”

•Upgrade AB

•Upgrade CD and DE

MTEP Reliability

•Upgrade AB only if study gens have PTDF>5%

•Upgrade CD and DE only if OTDF >3% or SSR agreement

Retirement

•Upgrade AB only if study gens have DFAX>5% ERIS and NRIS

• Upgrade CD and DE only if DFAX >20% for ERIS or if DFAX > 5% for NRIS

GI

•Upgrade CD and DE only if BC >1.25Economic

•Upgrade AB only if study plants have DFAX>5

•Upgrade CD and DE only if study gens have DFAX of >5%

Deliverability:

•Upgrade AB only if study TSR has DFAX>5%

•Upgrade CD and DE only if DFAX >3% TSR:

105%

loaded

G

G

GG

A

B

Base case: System intact

Change case: N-1 Contingency

Sensitivity Models Used to Identify Needs/Valuesand application of Corrective Action Plan (CAP)

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• Year –2&5 (Sensitivity) per TPL -001-4 R2.1.4

• CAP if constraints identified in 2 or more sensitivities

MTEP Reliability Planning

• Sensitivities only on Case by Case

• CAP required to avoid or limit SSR need

Retirement

• None unless specified in TOs LPC requirement

• All Constraints require CAP based on (DFAX, MW Impact, etc)

GI

• Sensitivities are determined separately for each congestion issue as needed. Feedback on which sensitivities to run is solicited from stakeholders.

Economic Planning

•None

MTEP Annual Deliverability/NRIS

•None

TSR

Adherence and Application of Local Planning Criteria

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•Tariff

•Facility Limits or Appendix K of BPM20

•If TOs use own models and LPC for projects justification -need to be posted.

MTEP Reliability Planning

•Facility Limits or Appendix K of BPM20

Retirement

•FAC-002 R1.2

•LPC document explicitly describes dispatch conditions/requirement applicable on to GI study

•Facility Limits or Appendix K of BPM20

GI

•Facility Limits or Appendix K of BPM20

Economic Planning

•Facility Limits or Appendix K of BPM20

MTEP Annual Deliverability/NRIS

•Facility Limits or Appendix K of BPM20

TSR

Feedback Request:• MISO is requesting feedback on the following by May 28th:

• Is provided information sufficient enough or MISO needs to go deep into the study process overview? Why? What is missing and which process?

• To ensure comparable treatment and potential planning process alignment identify areas of concern related to MISO planning study objectives, methodologies and assumptions. What concerns do you have and what change is desired?

• All feedback requests are posted to the Stakeholder Feedback Page and stakeholder comments are submitted through the feedback tool: https://www.misoenergy.org/stakeholder-engagement/stakeholder-feedback/ (under Planning Subcommittee)

• MISO will review stakeholder feedback at the next PSC in June

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Questions?Edin HabibovicSr. Manager, Expansion Planningehabibovic@misoenergy.org

Appendix

List of Acronyms, Reference Materials and Contacts…

Documents:

• MISO Planning Web Site

• Business Practice Manuals

• MISO Tariff

• FERC Orders

• NERC Planning Standards

Contacts:

• MISO Client Relations:

• 866-296-6476, option 3 , clientrelations@misoenergy.org

Acronyms:

• DFAX: The Generation Shift Factor measures the change in MW flow on transmission branches as a function of an injection of unit MW at a certain node.

• PTDF: Power transfer distribution factor-indicates the incremental change in real power that occurs on transmission lines due to real power transfers between two regions.

• OTDF: Outage transfer distribution factor is a sensitivity measure of how a change in a line’s (equipment) status affects the flows on other lines (equipment) in the system.

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Relevant Language From Attachment FF

Section I.C.7

Planning Models: The Transmission Provider shall collaborate with Transmission Owners, other transmission providers, Transmission Customers, and other stakeholder to develop appropriate planning models that reflect expected system conditions for the planning horizon. …

Section II.A.1

… The Transmission Provider shall test the MTEP for adequacy and security based on commonly applicable national Electric Reliability Organization (“ERO”) standards, and under likely and possible dispatch patterns of actual and projected Generation Resources within the Transmission System and of external resources, including dispatch reflective of Long-Term Transmission Rights of Transmission Customers, and shall produce an efficient expansion plan that includes all Baseline Reliability Projects determined by the Transmission Provider to be necessary through the planning horizon of the MTEP. …

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Relevant Language From TPL-001-4R1 Each Transmission Planner and Planning Coordinator shall maintain System models within its respective

area for performing the studies needed to complete its Planning Assessment. The models shall use data consistent with that provided in accordance with the MOD-010 and MOD-012 standards, supplemented by other sources as needed, including items represented in the Corrective Action Plan, and shall represent projected System conditions. This establishes Category P0 as the normal System condition in Table 1.

R2.1.1 System Peak Load for either Year One or year two, and for year five.

R2.1.2 System Off-Peak Load for one of the five years.

R2.1.4 For each of the studies described in Requirement R2, Parts 2.1.1 and 2.1.2, sensitivity cases(s) shall be utilized to demonstrate the impact of changes to the basic assumptions used in the model. To accomplish this, the sensitivity analysis in the Planning Assessment must vary one or more of the following conditions by a sufficient amount to stress the System within a range of credible conditions that demonstrate a measurable change in System response

R2.2.1 A current study assessing expected System peak Load conditions for one of the years in the Long-Term Transmission Planning Horizon and the rationale for why that year was selected.

Based on FERC approved Tariff language on Energy

Resource Interconnection Service MISO has to study

full output in at least one case

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Section 3.2.1: https://cdn.misoenergy.org/Attachment%20X109843.pdf

3.2.1.1 ER Interconnection Service allows Interconnection Customer to connect the Generating Facility to the

Transmission System or Distribution System, as applicable, and be eligible to deliver the Generating Facility’s

output using the existing firm or non-firm capacity of the Transmission System on an “as available” basis and

may be granted on a conditional basis. ER Interconnection Service does not in and of itself convey any right to

deliver electricity to any specific customer or Point of Delivery.

3.2.1.2 The Study. The stability and steady state studies would identify necessary upgrades to allow full output

of the proposed Generating Facility and would also identify the maximum allowed output, at the time the

study is performed, of the interconnecting Generating Facility without requiring additional Network Upgrades.

Updated fuel type table for ER Interconnection Service

Notes:• Network Resource Interconnection Service study/dispatch is not impacted by the MTEP or Fuel table dispatch

• Solar Shoulder Peak dispatch updated from 50% to 0%, Wind will remain unchanged

• Additionally, storage would only be studied as discharging during summer peak case

• Dispatch changes targeted for the DPP 2020 cycle