ER26-3650-000 · 2026-08-28 · Midcontinent Independent System Operator, Inc.

Tab B - IRR Tariff Clean.pdf

Tab B

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
Calculated Demand Response Resource-Type I Output:  The hourly average Actual Energy 
Injection for each associated Demand Response Resource – Type I for the Hour for the 
purposes of assessing Excessive/Deficient Energy Deployment Charges. 
Calculated Demand Response Resource-Type II Output:  (i) For a DRR-Type II Resource that 
is providing Regulating Service, the Dispatch Interval Actual Energy Injections; or (ii) 
For a DRR-Type II Resource that is not providing Regulation Service, the average 
Dispatch Target for Energy for the DRR-Type II Resource, expressed in MW and scaled 
by Actual Energy Injection.
Calendar Day:  Any day of the week, including Saturday, Sunday or a Federal holiday.
Candidate ARR (CARR):  ARR nominations submitted by Market Participants to be considered 
throughout the Annual ARR Allocation process.
Candidate Baseload ARR:  Candidate ARR rights equal to each Market Participant’s Baseload 
Usage in an ARR Zone.  
Candidate Peak ARR:  Candidate ARR rights equal to each Market Participant’s Peak Usage in 
an ARR Zone.
Candidate MTPS ARR:  MTPS ARR nominations submitted by the Transmission Provider to be 
considered during the Annual ARR Allocation process.
Capacity:  The instantaneous rate at which Energy can be delivered, received or transferred, 
including Energy associated with Operating Reserve, Up Ramp Capability, Down Ramp 
Capability, and Short-Term Reserve, measured in MW.
Capacity Deficiency Charge:  A charge that is assessed to an LSE that has provided notification 
prior to the Planning Resource Auction that it will meet its Initial PRMR in part or in

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
whole by paying the Capacity Deficiency Charge so that the Transmission Provider does 
not clear associated Zonal Resource Credits (ZRC) for the associated Initial PRMR 
through the PRA process.
Capacity Export Limit (CEL):  The amount of Planning Resources in MWs for an LRZ or ERZ 
determined by the Transmission Provider that can be reliably exported from that LRZ or 
ERZ for each Season.
Capacity Import Limit (CIL):  The amount of Planning Resources in MWs for an LRZ 
determined by the Transmission Provider that can be reliably imported into that LRZ for 
each Season.
Capacity Replacement Non-Compliance Charge: The charge assessed to a Market Participant 
for failing to replace ZRCs that were designated for RAR and did not fulfill their 
performance obligations as set forth in Module E-1.
Capacity Resources:  The Generation Resources, Demand Response Resource- Type I, Demand 
Response Resource-Type II, Dispatchable Intermittent Resources, External Resources, 
Intermittent Generation, or Electric Storage Resources that are available to meet Demand.  
Carved Out GFA(s):  Any Grandfathered Agreement(s) that the Commission has identified as 
“carved out” pursuant to Appendix B of the Commission’s September 16, 2004 order, 
Midwest Independent Transmission System Operator, Inc., 108 FERC ¶ 61,236 (2004) or 
that meet the criteria in Section 38.8.3(A).b, and set forth in Attachment P to this Tariff, 
as that Attachment may be amended from time to time.
Cash Collateral Agreement:  A Credit Support Document taking the form found in Exhibit III of 
Attachment L of this Tariff.

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
Cash Deposit:  Cash collateral provided to Transmission Provider to secure Applicant’s and/or 
Tariff Customer’s performance under the terms and conditions of Transmission 
Provider’s Tariff, and/or other agreements.
Catastrophic Generator Outage:  A forced outage that results in a unit being, or reasonably 
expected to be unavailable for a minimum of six (6) continuous months, which is not the 
result of a planned maintenance outage.
Category A Tariff Customer:  A Tariff Customer who grants a continuing first-priority security 
interest to the Transmission Provider in all right, title and interest in any and all accounts 
receivable and other rights of payment of the Tariff Customer for goods and services 
provided under, or otherwise arising under, pursuant to or in connection with, the Tariff 
and/or any of the Agreements.
Category B Tariff Customer:  Any Tariff Customer who does not grant a Receivable Security 
Interest to the Transmission Provider.
Change in Total System Cost:  The net change in variable operational costs, which include fuel, 
variable O&M, variable environmental costs, and other variable costs as mutually agreed 
upon by the Transmission Provider and the Market Participant, measured in dollars as a 
result of changing the output of one or more units in response to a redispatch request 
from the Transmission Provider.
Charge:  The withdrawal of energy from the Transmission System by an Electric Storage 
Resource for the purpose of storing the energy for injection back into the Transmission 
System at a later time.
Cleared Zonal Resource Credits (Cleared ZRCs):  Zonal Resource Credits that have cleared the

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
Planning Resource Auction, were used in a Fixed Resource Adequacy Plan, were used in 
a Reliability Based Demand Curve Opt Out, or are currently being used to replace ZRCs.
Coincident Peak Demand:  The Demand in MWs, for an LSE and/or EDC, that occurs 
coincident to the peak Demand for each Season in the Transmission Provider Region, 
where all Demand has been augmented to include any known reductions in Demand 
related to LMRs.
Co-located Resources:  Two or more Generators located behind the same point of 
interconnection that participate separately in the Energy and Operating Reserve Markets 
and share an Interconnection Service Limit.
Combined Reliability Systems:  The Reliability Coordination Customer Transmission Facilities 
and all other transmission facilities for which the Transmission Provider performs 
Reliability Coordination Services under Part I of Module F.
Commercial Model:  A presentation of the relationships between Market Participants and their 
Resources, Commercial Pricing Nodes and the Network Model in the Energy and 
Operating Reserve Markets.
Commercial Operation Date:  Shall have the meaning set forth in Attachment X of this Tariff.
Commercial Pricing Node (CPNode):  An Elemental Pricing Node or an Aggregate Price Node 
in the Commercial Model used to schedule and settle Market Activities.  Commercial 
Pricing Nodes include Resources, Hubs, Load Zones and/or Interfaces.
Commercially Significant Voltage and Local Reliability Issue:  Transmission System voltage or 
other local reliability concerns that result in Voltage and Local Reliability Commitments.  
These issues are designated for reasons including, but not limited to, occurrence

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
frequency, monetary impact, or other criteria as defined in Schedule 44.  A Local 
Balancing Authority or an interested Market Participant may request that the 
Transmission Provider evaluate a Voltage and Local Reliability Issue for designation as 
commercially significant.
Commission:  The Federal Energy Regulatory Commission, also known as FERC, or its 
successor.
Commitment Status: A specification submitted by a Market Participant in its Generation Offer, 
External Asynchronous Resource Offer, Demand Response Resource-Type I Offer, 
Demand Response Resource-Type II Offer, or Electric Storage Resource Offer for each 
Hour to indicate whether or how the Transmission Provider is authorized to commit the 
Resource or deploy the Resource for Operating Reserves for the Hour.
Common Bus:  A single Bus to which two or more Resources are connected in an electrically 
equivalent manner where such Resources are treated as a single Resource for compliance 
monitoring purposes.
Common Information Model (CIM):  The format adopted by the NERC Data Exchange 
Working Group that will be used by the Congestion Management Customer and the 
Transmission Provider to exchange Energy Management System models once a year.
Comparable FTRs:  FTRs that are identical in all material respects except for the quantity of 
MW specified. 
Competitive Developer Qualification Process:  The process utilized to certify Qualified 
Transmission Developers pursuant to Section VIII.B of Attachment FF of the Tariff.
Competitive Developer Selection Process:  The process utilized to solicit Proposals, evaluate

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
Proposals, and designating a Selected Proposal and Selected Developer(s) pursuant to 
Section VIII of Attachment FF of the Tariff.
Competitive Substation Facility:  A transmission substation facility contained within an Eligible 
Project that is subject to the Competitive Developer Selection Process in accordance with 
Section VIII.A of Attachment FF of the Tariff.
Competitive Transmission Executive Committee:  A committee consisting of three (3) or more 
executive staff of the Transmission Provider, including at least one (1) officer, that is 
charged with overseeing all Transmission Provider staff and consultants involved in 
evaluating Transmission Developer Applications and Proposals in response to a posted 
Request for Proposal.  The Competitive Transmission Executive Committee will have 
exclusive and final decision-making authority over: (i) the certification and termination 
of Qualified Transmission Developers; and (ii) the evaluation and selection of Proposals, 
resulting in designating Selected Developers.  The Competitive Transmission Executive 
Committee shall possess the specific technical, financial, and regulatory expertise 
necessary for evaluation of Transmission Developer Applications and Proposals.
Competitive Transmission Facility:  A Competitive Substation Facility or Competitive 
Transmission Line Facility.
Competitive Transmission Line Facility:  A transmission line facility contained within an 
Eligible Project that is subject to the Competitive Developer Selection Process in 
accordance with Section VIII.A of Attachment FF of the Tariff. 
Competitive Transmission Process:  The process utilized to certify Qualified Transmission 
Developers, identify Competitive Transmission Projects, solicit Proposals, evaluate

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
Proposals, and designating a Selected Proposal and Selected Developer(s) pursuant to 
Section VIII of Attachment FF of the Tariff.  The Competitive Transmission Process 
includes the Competitive Developer Qualification Process and Competitive Developer 
Selection Process.
Competitive Transmission Project:  The Competitive Transmission Facilities contained within 
an Eligible Project. 
Competitively Sensitive Information:  Information that is not public and the unauthorized 
disclosure of which could have anti-competitive effects, provide a competitor with an 
unfair or improper competitive advantage, or unfairly or improperly result in competitive 
harm, detriment, prejudice, disadvantage or injury to the legitimate proprietary rights, 
business or commercial interests, market position, or ability to bargain freely, of the 
lawful owners, possessors or users of such information.
Completed Application:  An Application that satisfies all of the information and other 
requirements of the Tariff, including any required deposit.
Composite Credit Score:  A composite numerical score scaled from 1.00 to 6.99, representing 
the sum of the Qualitative and Quantitative score as calculated by the Transmission 
Provider’s credit scoring model in Attachment L of this Tariff.
Computational Load:  Large Load comprised of 25 MW or more of Demand from information 
technology equipment, such as servers, storage, and networking hardware.
Confidential Information:  Any proprietary or commercially or competitively sensitive 
information, trade secret or information regarding a plan, specification, pattern, 
procedure, design, device, list, concept, policy or compilation relating to the present or

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
planned business of a Transmission Customer, Market Participant, or other user, which is 
designated as confidential by the entity supplying the information, whether conveyed 
orally, electronically, in writing, through inspection, or otherwise, that is received by the 
Transmission Provider and is not disclosed except under the terms of a Confidential 
Information policy. 
Congestion Management Customer:  Any entity taking Interconnected Operations and 
Congestion Management Service under Part II of Module F.
Congestion Management Process (CMP):  The process described in Attachment LL of the 
Tariff.
Constraint Contribution Factor:  Factor that represents the impact that an incremental Actual 
Energy Injection or Actual Energy Withdrawal of one MW has on a given Active 
Transmission Constraint.
Constraint Generation Shift Factor Cutoff:  A Generation Shift Factor level defined for each 
transmission constraint that determines the generating units to be included in a Broad 
Constrained Area, Narrow Constrained Area or Dynamic NCA associated with the 
constraint.  Generation Resources with a Generation Shift Factor whose absolute value is 
greater than the Constraint Generation Shift Factor Cutoff are included in the Broad 
Constrained Area, Narrow Constrained Area or Dynamic NCA.
Constraint Management Charge Allocation Factor:  A factor that is used to apportion Real-
Time Revenue Sufficiency Guarantee Credits in an Hour between (i) the Real-Time 
Revenue Sufficiency Guarantee Constraint Management Charge and (ii) the Real-Time 
Revenue Sufficiency Guarantee Day-Ahead Schedule Deviation Charge and the Real-

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
Time Revenue Sufficiency Guarantee Headroom Charge.
Contingency Reserve:  Spinning Reserve and Supplemental Reserve provided by Resources 
available to the Transmission Provider to use in the event of a system contingency as 
specified in Schedule 5-Spinning Reserve and Schedule 6– Supplemental Reserve of this 
Tariff. 
Contingency Reserve Deployment Failure Charge:  A charge assessed to any Resource that 
fails to achieve in a Contingency Reserve Deployment Period at least one hundred 
percent (100%) of the Contingency Reserve Deployment Instruction target.
Contingency Reserve Deployment Instruction:  An instruction issued by the Transmission 
Provider to Resources with cleared Contingency Reserve to deploy a specific MW 
quantity of cleared Contingency Reserve as communicated via Setpoint Instructions or 
other electronic means.
Contingency Reserve Deployment Period:  The period of time the Resource has to deploy 
Contingency Reserve following the issuance of a Contingency Reserve Deployment 
Instruction that is equal to ten minutes. 
Contingency Reserve Offer Price Cap:  The maximum price permitted for a Spinning Reserve 
Offer, an On-Line Supplemental Reserve Offer, an Off-Line Supplemental Reserve Offer 
or a Supplemental Reserve Offer in the Energy and Operating Reserve Markets.
Continuing Error:  A continuing software, system or other execution that is inconsistent with 
the Tariff.
Control:  The possession, directly or indirectly, of the power to direct the management or 
policies of a person or an entity.  A voting interest of ten percent (10%) or more shall

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
create a rebuttable presumption of Control.
Controllable Devices:  Devices that may include phase shifters, DC lines, and back-to-back 
AC/DC converters. 
Co-optimized Zonal Contingency Reserve Requirement: The minimum amount of Contingency 
Reserve the Transmission Provider needs to procure within a Reserve Zone as determined 
based upon co-optimization with Post Reserve Deployment Constraints.
Co-optimized Zonal Operating Reserve Requirement:  The sum of the Co-optimized Zonal 
Contingency Reserve Requirement and Co-optimized Zonal Regulating Reserve 
Requirement.
Co-optimized Zonal Regulating Reserve Requirement: The minimum amount of Regulating 
Reserve the Transmission Provider needs to procure within a Reserve Zone as determined 
based upon co-optimization with Post Reserve Deployment Constraints.
Co-optimized Zonal Short-Term Reserve Requirement: The minimum amount of Short-Term 
Reserve the Transmission Provider needs to procure within a Reserve Zone as determined 
based upon co-optimization with Post Reserve Deployment Constraints.
Co-optimized Zonal Spinning Reserve Requirement:  The minimum amount of Spinning 
Reserve the Transmission Provider needs to procure within a Reserve Zone as determined 
based upon co-optimization with Post Reserve Deployment Constraints.
Coordinated Flowgate:  A Flowgate that is subject to the Transmission Provider’s or 
Coordination Customer’s operational control and through which flows are affected by 
transmission over transmission facilities within its operational control, or with respect to 
which Transmission Provider serves as a Reliability Authority.

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
Coordinated Transaction Schedule:  An Interchange Schedule to purchase Energy in the Real-
Time Energy and Operating Reserve Market from a Source Point in either the MISO 
Balancing Authority Area or PJM Balancing Authority Area and sell it at a Sink Point in 
the other balancing authority area that is cleared if the forecasted LMP at the Sink Point 
minus the forecasted LMP at the Source Point is greater than or equal to the dollar value 
specified in the bid associated with the Interchange Schedule.
Coordinating Owner:  Any entity that is not subject to the jurisdiction of the Commission but 
participating in the ISO through the execution of a coordination agreement which 
includes provisions for the elimination of rate pancaking.  The terms and provisions of a 
Coordinating Owner’s coordination agreement shall supersede the similar terms and 
provisions of this Tariff where applicable.
Coordination Customer:  Any customer taking Coordination Services from the Transmission 
Provider pursuant to Module F of the Tariff.  The term Coordination Customer includes:  
Reliability Coordination Customer, and Congestion Management Customer.
Coordination Services:  The services provided by the Transmission Provider pursuant to Module 
F of the Tariff.  Coordination Services include Reliability Coordination Service and 
Interconnected Operations and Congestion Management Service.
Corporate Guaranty:  A legal document taking the form found in Exhibit I of Attachment L of 
this Tariff used by an Affiliate of an Applicant and/or Tariff Customer that guarantees the 
obligations of such Applicant or Tariff Customer. 
Cost Allocation Zone:  The zones identified in Attachment WW of this Tariff used for allocating 
the costs of Market Efficiency Projects.

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
Cost of Congestion:  The Marginal Congestion Component of LMP at the sink minus the 
Marginal Congestion Component of LMP at the source.
Cost of Losses:  Marginal Losses Component of LMP at the sink minus the Marginal Losses 
Component of LMP at the source.
Cost of New Entry (CONE):  The capital, operating, financial and other costs of acquiring a new 
Generation Resource within the Transmission Provider Region for any designated LRZ.
Council of the City of New Orleans (CNO):  The governmental body with the power of 
supervision, regulation, and control over public utilities providing service within the City 
of New Orleans, i.e., Entergy New Orleans, pursuant to the Constitution of the State of 
Louisiana and the Home Rule Charter of the City of New Orleans.  CNO shall have all 
the rights and responsibilities granted herein to states, state public utility commissions, 
state agencies, and State Regulatory Authorities.
Counterflow ARR:  ARR allocated during the LTTR Restoration and Termination Stage of an 
Annual ARR Allocation based on a Counterflow ARR Entitlement.
Counterflow ARR Entitlement:  Any Stage 1A eligible ARR Entitlement’s portion that was not 
nominated in Stage 1A of a Market Participant’s year 1 Annual ARR Allocation but that 
the Transmission Provider deems to provide counterflow necessary to enable curtailed 
Stage 1A CARRs to be restored (fully or partly) during the LTTR Restoration and 
Termination Stage of an Annual ARR Allocation.
Credit and Security Agreement:  A Credit Support Document taking the form found in Exhibit 
V of Attachment L of this Tariff.
Credit Policy:  The Transmission Provider’s creditworthiness requirements and credit evaluation

MISO
1.C
FERC Electric Tariff
Definitions - C
MODULES
81.0.0
Effective On: December 4, 2026
procedures as contained in Attachment L of this Tariff. 
Credit Support Documents:  Any agreement or instrument in any way guaranteeing or securing 
any or all of a Tariff Customer’s obligations under this Tariff (including, without 
limitation, the Credit Policy), any agreement entered into under, pursuant to, or in 
connection with this Tariff or any agreement entered into under, pursuant to, or in 
connection with this Tariff or the Credit Policy, and/or any other agreement to which the 
Transmission Provider and the Tariff Customer are parties, including, without limitation, 
any Corporate Guaranty, Cash Collateral Agreement, Letter of Credit, Credit and 
Security Agreement or agreement granting a security interest. 
Critical Energy Infrastructure Information (CEII):  Confidential information described in 18 
C.F.R § 388.113(c)(1), as may be amended from time to time.
Curtailment:  A reduction in firm or non-firm Transmission Service in response to a transfer 
capability shortage as a result of system reliability conditions pursuant to Section 14.7 or 
Section 27A of this Tariff.
Customer Load Aggregation:  A Load Zone approved by the Transmission Provider for the 
purposes of submitting Bids to or scheduling into the Energy and Operating Reserve 
Markets and for settlement of Market Activities. 
Cyber Exigency:  A suspicious electronic act or event that has the potential to compromise 
reliability within the Transmission Provider Region or other electrical facilities directly 
or indirectly connected to the Transmission System and whose severity reasonably 
requires that the Transmission Provider obtain expert assistance not normally called upon 
to counter such an electronic act or to resolve such an event.

MISO
1.L
FERC Electric Tariff
Definitions - L
MODULES
52.0.0
Effective On: December 4, 2026
Large Load:  Load with Demand of 50 MW or more associated with any facility or aggregation 
of facilities located at a single substation behind one or more Point(s) of Withdrawal from 
the Transmission System that is owned, operated, or controlled by: (a) a single entity, or 
(b) a group of entities that will coordinate with respect to the profile of the Load.  Large 
Load does not include Load used exclusively for charging an Electric Storage Resource.
Large Load Equipment:  Any of the facilities, devices, or equipment that constitutes a part of a 
Large Load, or are used to interconnect the Large Load to the Transmission System.
Legitimate Risks:  Business operation risks, incurred by a Market Participant, that increase as a 
result of providing any of the products described in the Tariff.  These risks include, but 
are not limited to, the risk of repair expenses; business interruption due to outages 
resulting from either a failure to start, or unplanned outages that occur when the facility is 
in service; regulatory restrictions; and disruptions from labor relations problems.  These 
risks are in the nature of marginal costs included in Reference Levels.  In contrast, the 
risk associated with fuel purchase price is not a component of Reference Levels, but 
rather a basis for the Fuel Cost Uncertainty Adder and some of the conduct thresholds 
under Module D. 
Letter of Credit:  A Credit Support Document taking the form found in Exhibit II of Attachment 
L to this Tariff. 
Line Outage Distribution Factor (LODF):  The percent of flow on line A, which is transferred 
to line B for the loss of line A.
Load:  A term that refers to either an end-user of Energy, net of system losses, or the amount of 
Energy (MWh) consumed by such end-user within the Transmission Provider Region.

MISO
1.L
FERC Electric Tariff
Definitions - L
MODULES
52.0.0
Effective On: December 4, 2026
Load Forecast:  An estimate of the amount of Energy (MWh) or Capacity (MW) to be 
consumed within the Transmission Provider’s Region, prepared by the Transmission 
Provider based upon input from Local Balancing Authorities and Load Serving Entities, 
and used in the Transmission Provider’s scheduling and dispatch decisions to ensure 
reliable operation of the MISO Balancing Authority. 
Load Modifying Resource:  A Demand Resource or Behind the Meter Generation Resource. 
Load Modifying Resource Market Participant (LMR MP):  A Market Participant that has the 
rights to control the energy demand or the energy production from a Load Modifying 
Resource.
Load Ratio Share:  Ratio of a Transmission Customer’s Network Load in a Zone to the total 
Load in that pricing Zone computed in accordance with Module B, Section 34.2 of this 
Tariff.
Load Serving Entity (LSE):  Any entity that has undertaken an obligation to serve Load for end-
use customers by statute, franchise, regulatory requirement or contract for Load located 
within or attached to the Transmission System, including but not limited to purchase-
selling entities and retail power marketers with the obligation to serve Load.  Where a 
distribution cooperative or a municipal distribution system otherwise covered by the prior 
sentence is a wholesale customer of a generation and transmission cooperative or a 
municipal Joint Action Agency, the generation and transmission cooperative, a state or 
federal agency or municipal Joint Action Agency may act as the Load Serving Entity for 
such distribution cooperative or municipal distribution system.  Where retail Load 
switching occurs in a state, the entity with the obligation to serve Load is the LSE

MISO
1.L
FERC Electric Tariff
Definitions - L
MODULES
52.0.0
Effective On: December 4, 2026
Load Shedding:  The systematic reduction of system demand by temporarily decreasing Load in 
response to a Transmission System Emergency, Local Transmission Emergency, or 
MISO Balancing Authority Area or Sub-Area Capacity shortages, system instability, or 
voltage control considerations under Module B and Module C, of this Tariff. 
Load Zone:  A Zone determined by Market Participants representing an aggregate area of 
consumption for a single Load Serving Entity within the MISO Balancing Authority Area 
and used for the purposes of scheduling, reporting Actual Energy Withdrawal volumes, 
and settling Energy transactions at aggregated Load levels, approved and maintained by 
the Transmission Provider to facilitate transactions.
Local Balancing Authority (LBA):  An operational entity or a Joint Registration Organization 
which is (i) responsible for compliance to NERC for the subset of NERC Balancing 
Authority Reliability Standards defined in the Balancing Authority Agreement for their 
local area within the MISO Balancing Authority Area, (ii) a Party to Balancing Authority 
Agreement, excluding MISO, and (iii) shown in Appendix A to the Balancing Authority 
Agreement. 
Local Balancing Authority Area:  Shall have the meaning set forth in the Balancing Authority 
Agreement.
Local Clearing Requirement (LCR):  The minimum amount of Seasonal Accredited Capacity 
for an LRZ that is required to meet its LOLE for each Season while fully using the Zonal 
Import Ability for such LRZ and accounting for controllable exports. 
Local Clearing Requirement Charge: A charge that is assessed to Load Serving Entities 
whenever an LRZ’s Auction Clearing Price for a Season is increased due to its LCR

MISO
1.L
FERC Electric Tariff
Definitions - L
MODULES
52.0.0
Effective On: December 4, 2026
being greater than the sum of individual Final PRMR of the LSEs.
Local Reliability Requirement (LRR):  The minimum amount of Unforced Capacity for an LRZ 
to meet its LOLE for each Season, without considering transmission ties to systems 
outside of the LRZ. 
Local Resource Zone (LRZ):  A geographic area within the Transmission Provider Region that 
is prescribed by the Transmission Provider, based upon the criteria in Section 68A.3, to 
address congestion that limits Planning Resource deliverability.
Local Resource Zone Peak Demand:  The Demand in MWs, for an LSE and/or EDC, in a Local 
Resource Zone that occurs coincident to the peak Demand for each Season in the Local 
Resource Zone, where all Demand has been augmented to include any known reductions 
in Demand related to LMRs.
Local Short-Term Reserve: Short-Term Reserve available to the Transmission Provider to 
address transmission constraints in any Reserve Zone(s). 
Local Short-Term Reserve Requirements: The amount of Local Short-Term Reserve, as 
determined pursuant to Module C of the Tariff, that the Transmission Provider is required 
to procure in a Reserve Zone.
Local Transmission Emergency:  Transmission System conditions or events that have the 
potential to exceed or have exceeded operating limits that do not pose a risk of cascading 
to the interconnection but require emergency-level actions.
Locational Marginal Price (LMP):  A price for Energy at a given Commercial Pricing Node in 
the Transmission Provider Region which is the marginal cost of serving demand at the 
Commercial Pricing Node while meeting Zonal and Market-Wide Operating Reserve

MISO
1.L
FERC Electric Tariff
Definitions - L
MODULES
52.0.0
Effective On: December 4, 2026
Requirements, Up Ramp Capability requirements, Down Ramp Capability requirements, 
and Short-Term Reserve Requirements.  Such price may be either Ex Ante or Ex Post. 
Long-Term Firm Point-To-Point Transmission Service:  Firm Point To Point Transmission 
Service under Module B of this Tariff with a term of one (1) year or more.
Long Term Transmission Rights (LTTR):  ARRs allocated in Stage 1A of the Annual ARR 
Allocation process.  LTTRs carry annual rollover rights lasting ten (10) years or more. 
Look Ahead Commitment (LAC):  A process performed during the Real-Time Energy and 
Operating Reserve Market that develops Resource commitment and decommitment 
options that may be used by the Transmission Provider to ensure sufficient Resources 
will be available to meet Load Forecast, Operating Reserve, Up Ramp Capability, Down 
Ramp Capability, Short-Term Reserve and other demand requirements for the near term 
intra-hour intervals.
Loss of Load Expectation (LOLE):  An estimate of the average number of days with supply 
interruption to end use customers, whether for a single hour or multiple hours in a day. 
Loss of Load Probability Curve:  The probability of shedding firm Load under varying levels of 
Contingency Reserve shortages, to be used in accordance with Schedule 28. This curve is 
further described in the Transmission Provider’s Business Practices Manual for the 
Energy and Operating Reserves Markets (BPM-002).
Loss Pools:  A single Local Balancing Authority Area or an aggregation of Local Balancing 
Authority Areas, including those Local Balancing Authority Areas operated by 
Coordinating Owners consistent with the terms and provisions of the Coordinating 
Owners agreement, designated by the Transmission Provider for the purposes of

MISO
1.L
FERC Electric Tariff
Definitions - L
MODULES
52.0.0
Effective On: December 4, 2026
calculating and distributing Day Ahead and Real Time Hourly Marginal Losses Revenue 
Surplus.
Lost Opportunity Cost:  The LMP revenues that were not realized relative to a theoretical future 
operating point.

MISO
1.P
FERC Electric Tariff
Definitions - P
MODULES
71.0.0
Effective On: December 4, 2026
Partial-Year FTR Allocation:  The procedure used by the Transmission Provider to allocate 
FTRs to Market Participants in the new ARR Zones added as a result of Transmission 
Provider Region expansion that becomes effective after the start of the Annual ARR 
Allocation period.  The Partial-Year FTR Allocation will cover the partial year period 
when the new ARR Zone(s) become effective to the start of the next Annual ARR 
Allocation.  For the partial year period, the Market Participants in the new ARR Zone(s) 
may request an allocation of FTRs, which will be in lieu of an allocation of ARRs. 
Party(ies):  The Transmission Provider, ITC where appropriate, Market Participants, 
Transmission Customers, or any combination of the above. 
Past Due Amount:  Any amount invoiced by the Transmission Provider that is not paid when 
due.
Peak Reserved Source Set:  Set of Resources including those constituting the Baseload Reserved 
Source Point that have met the Resource Qualification Requirements for inclusion as a 
Reserved Source Point for a given ARR Zone. 
Peak Usage:  A Market Participant’s Total Forecasted Peak Load in a given ARR Zone for the 
upcoming Annual ARR Allocation period calculated using the immediate prior three year 
actual peak Loads.  The Total Forecast Peak Load is the sum of the forecast Network 
Integration Transmission Service peak Load for the upcoming allocation period plus peak 
Load served by Option A – Grandfathered Agreements plus peak Load served by Option 
B – Grandfathered Agreements.
Penalty Level:  A component of a mitigation measure described in Module D that represents the 
amount of Energy purchased by a Market Participant that is an LSE or represents an LSE

MISO
1.P
FERC Electric Tariff
Definitions - P
MODULES
71.0.0
Effective On: December 4, 2026
in the Real Time Energy Market in excess of the Allowance Level the entity is subject to. 
Physical Withholding Threshold Quantity:  Threshold employed by the IMM to identify 
physical withholding by a supplier of Planning Resources for the Planning Resource 
Auction, expressed in MW.
Plan:  The Transmission Provider’s Market Monitoring Plan set forth in Module D of this Tariff.
Planned Transmission Outage:  Any transmission outage scheduled for the performance of 
maintenance or repairs or the implementation of a system enhancement which is planned 
in advance for pre-determined duration and which meets the notification requirements for 
such outages as specified by the Transmission Provider.  
Planning Advisory Committee:  A committee of stakeholders established under the ISO 
Agreement for the purpose of providing input to the planning staff on the development of 
the MTEP.  
Planning Area(s):  A collective or alternative reference to the First Planning Area and/or the 
Second Planning Area.
Planning Coordinator:  The entity responsible for the longer term reliability of its planning 
coordinator area.
Planning Reserve Margin (PRM):  The percentage above forecasted Coincident Peak Demand 
of Planning Resources for the Transmission Provider Region in order to meet the LOLE.  
This percentage will include a quantity sufficient to cover transmission losses.
Planning Reserve Margin Requirement (PRMR):  The amount of ZRCs required of each LSE 
with Coincident Peak Demand in an LRZ to meet the LSE’s Resource Adequacy 
Requirements in each Season.

MISO
1.P
FERC Electric Tariff
Definitions - P
MODULES
71.0.0
Effective On: December 4, 2026
Planning Resource:  A Capacity Resource or Load Modifying Resource that can be used to 
satisfy PRMR.
Planning Resource Auction (PRA):  Auctions conducted by the Transmission Provider to 
determine the ACP and the cleared ZRC Offers for each LRZ and ERZ for each Season 
in the applicable Planning Year.
Planning Year:  The period of time from June 1st of one year to May 31st of the following year 
that is used for developing Resource Plans.  The first Planning Year shall commence on 
June 1, 2009.
PMAX:  The maximum Generator real power output reported in MWs on a seasonal basis.
PMIN:  The minimum Generator real power output reported in MWs on a seasonal basis.
Point(s) of Delivery:  Point(s) on the Transmission System where Capacity and Energy 
transmitted by the Transmission Provider will be made available to the Receiving Party 
under Module B and Module C of this Tariff.  The Point(s) of Delivery shall be specified 
in the Service Agreement for Long Term Firm Point To Point Transmission Service or 
the HVDC Service Agreement.
Point(s) of Receipt:  Point(s) of interconnection on the Transmission System where Capacity and 
Energy will be made available to the Transmission Provider by the Delivering Party 
under Module B and Module C of this Tariff.  The Point(s) of Receipt shall be specified 
in the Service Agreement for Long Term Firm Point To Point Transmission Service or 
the HVDC Service Agreement.
Point(s) of Withdrawal:  The point(s) where a non-transmission facility that is used to withdraw 
Energy from the Transmission System to serve Load connects to the Transmission

MISO
1.P
FERC Electric Tariff
Definitions - P
MODULES
71.0.0
Effective On: December 4, 2026
System.
Point-To-Point Transmission Service:  The reservation of Capacity and of Energy on either a 
firm or non firm basis from the Point(s) of Receipt to the Point(s) of Delivery under 
Module B of this Tariff. 
Portfolio:  For Multi-Value Project purposes, means two or more Multi-Value Projects proposed 
to be located in one or more Transmission Pricing Zones that, when evaluated together, 
are expected to result in system-wide benefits across the MISO footprint or benefits 
across the subregion. For purposes of the Portfolio, subregion refers to either the MISO 
Midwest MVP Cost Allocation Subregion or MISO South MVP Cost Allocation 
Subregion.
Post Reserve Deployment Constraints:  The post zonal Operating Reserve and Short-Term 
Reserve deployment flows on the transmission constraints and Sub-Regional Power 
Balance Constraints, used to determine the Co-optimized Zonal Regulating Reserve 
Requirement, Co-optimized Zonal Contingency Reserve Requirement, Co-optimized 
Zonal Spinning Reserve Requirement, and Co-optimized Zonal Short-Term Reserve 
Requirement, for each Reserve Zone.
Post Reserve Deployment Constraints Demand Curve:  Demand curves used to price Post 
Reserve Deployment Constraints.
Power Purchaser:  The entity that is purchasing the Capacity and reserved Energy to be 
transmitted under this Tariff. 
PPA Schedule: Schedule associated with a PPA that is executed after April 3, 2014.
Pre-Confirmed Application:  An Application that commits the Eligible Customer to execute a 
Service Agreement upon receipt of notification that the Transmission Provider can

MISO
1.P
FERC Electric Tariff
Definitions - P
MODULES
71.0.0
Effective On: December 4, 2026
provide the requested Transmission Service.
Price Sensitive Demand Bids:  Demand Bids in which the Market Participant specifies a 
maximum price (dollars per MWh) at which the Market Participant desires to purchase 
the designated MWh of Energy.
Price Taker:  A Market Participant with an Energy and/or Operating Reserve Offer not capable 
of setting LMPs or MCPs. 
Production Costs:  The Energy output cost of a Generation Resource or a Demand Response 
Resource-Type II based upon Start Up, No Load and Energy Offer cost components set 
forth in an Offer or the Energy reduction cost of a Demand Response Resource-Type I 
based upon Shut Down Offer, Hourly Curtailment Offer and Energy Offer cost 
components set forth in an Offer.
Project Cost:  All costs for Network Upgrades, as determined by the Transmission Provider to be 
a single transmission expansion project, including those costs associated with seeking and 
obtaining all necessary approvals for the design, engineering, construction, and testing of 
the Network Upgrades.  These Network Upgrades will include costs classified by the 
Transmission Owners and Independent Transmission Companies as transmission plant 
using the Uniform System of Accounts 350 through 359 or equivalent set of accounts for 
any Coordinating Owner. 
Project Financial Security:  The Cash Deposit or Irrevocable Letter of Credit described in 
Appendix 1 to Attachment FF of the Tariff that a Selected Developer is required to 
provide.
Proposal: A proposal to construct, implement, own, operate, maintain, repair, and restore all

MISO
1.P
FERC Electric Tariff
Definitions - P
MODULES
71.0.0
Effective On: December 4, 2026
Competitive Transmission Facilities associated with a Competitive Transmission Project, 
in response to a Request for Proposal. Proposals may be submitted in one of two different 
forms: (i) a Single-Developer Proposal; or (ii) a Joint-Developer Proposal. The term 
“Proposal” shall include “Single-Developer Proposal” and “Joint-Developer Proposal”. 
Proposal Cure Period: A period of time, as set forth within Attachment FF, Section VIII.D.10, 
allowed for an RFP Respondent to correct deficiencies identified by the Transmission 
Provider in its previously submitted Proposal. The Proposal Cure Period commences 
upon notification by the Transmission Provider to an RFP Respondent of deficiencies in 
its Proposal. 
Proposal Participant(s): Any entity or entities involved in a Proposal, excluding the RFP 
Respondent(s), that will co-own the Competitive Transmission Project and rely on the 
RFP Respondent(s) to be the Selected Developer(s) responsible for constructing and 
implementing the Competitive Transmission Facilities associated with the Competitive 
Transmission Project. Proposal Participants may be identified in a Proposal as 
responsible for one or more aspects of operations, maintenance, repair, or restoration, on 
terms comparable to those that would apply if the RFP Respondent(s) intended to rely on 
a third-party contractor. 
Proposal Submission Deadline: The date and time Proposals must be submitted to the 
Transmission Provider by in order to be considered and evaluated by the Transmission 
Provider. The Submission Deadline shall be no later than 5:00 PM EPT on the date specified 
in the RFP, which shall not exceed one hundred and sixty-five (165) Calendar Days from the 
date the RFP was issued by the Transmission Provider, unless such date falls on a Saturday, 
Sunday, or MISO observed holiday in which case the Proposal Submission Deadline shall be

MISO
1.P
FERC Electric Tariff
Definitions - P
MODULES
71.0.0
Effective On: December 4, 2026
the next Business Day that is not a MISO observed holiday.
Proposed Generator Planned Outage:  The planned removal from service, in whole or in part, 
of a Generation Resource for inspection, maintenance or repair for which the Generation 
Owner has sought or will seek approval from the Transmission Provider for such planned 
removal in accordance with the Business Practices Manuals.
Protected Information:  Privileged and non public information to be maintained by the 
Transmission Provider.
Proxy Offers: The Offers created for resources that are deployed during Emergency operating 
procedures by the Transmission Provider as specified in Schedule 29A.
Pseudo-tie:  A telemetered reading or value that is updated in real time and used as a tie line 
flow in the Area Control Error equation but for which no physical tie or energy metering 
actually exists.  The integrated value is used as a metered MWh value for interchange 
accounting purposes.  Pseudo tied status of Resources and Loads may only be changed 
during Network Model updates and the timing of such updates shall be as defined in the 
Business Practices Manuals. 
Pseudo-tie Agreement:  The Agreement between MISO and a Market Participant included as 
Attachment FFF-1 or Attachment FFF-2 to this Tariff, as applicable, outlining the terms 
and conditions of the real-time transfer of control of a generating unit or load to (or from) 
the MISO Balancing Authority Area from (or to) a specified external Balancing 
Authority Area.
Public Power:  For credit scoring purposes, an Applicant or Market Participant that is a not for 
profit municipality, cooperative, Joint Action Agency, or agent representing one or more 
Public Power entities and whose credit quality is directly derived from the credit quality

MISO
1.P
FERC Electric Tariff
Definitions - P
MODULES
71.0.0
Effective On: December 4, 2026
of the Public Power entities represented through the agency relationship.
Public Power Composite Score:  For credit scoring purposes, the weighted average value of the 
Public Power Qualitative Score and the Public Power Quantitative Score.  The relative 
weights are sixty percent (60%) and forty percent (40%). 
Public Power Qualitative Score:  A component of a Public Power Composite Score which has, 
for credit scoring purposes, a value ranging from 1 to 6.99, with 1 being the best and 6.99 
being the worst.  The value is based on a review by the Transmission Provider of 
qualitative factors relative to an Applicant’s business, including but not limited to: i) 
regulatory; ii) legal; iii) demographic; and iv) energy supply/price factors as provided in 
Attachment L to this Tariff.
Public Power Quantitative Score:  A component of a Public Power Composite Score which has, 
for credit scoring purposes, a value ranging from 1 to 6.99, with 1 being the best and 6.99 
being the worst.  The value is based on a review by the Transmission Provider of various 
financial metrics as detailed in the Transmission Provider’s credit scoring model in 
Attachment L.

MISO 
v 
FERC Electric Tariff 
REQUIREMENTS FOR LARGE LOAD 
MODULES 
31.0.0 
Effective On: December 4, 2026
MISO
V
FERC Electric Tariff
REQUIREMENTS FOR LARGE LOAD
MODULES
31.0.0
Effective On: December 4, 2026

MISO
37A
FERC Electric Tariff
Applicability of Large Load Reliability Requirements
MODULES
31.0.0
Effective On: December 4, 2026
I.
Applicability of Large Load Reliability Requirements
The Transmission Customer taking Transmission Service on behalf of a Large Load shall 
be responsible for complying with each of the requirements of this Section 37A applicable to 
each Large Load it represents.
Except as set forth in Section 37A.II, all Large Load shall be subject to the Basic Facility 
Data, Modeling, Telemetry, Forecast Data, and Audit requirements set forth in Sections 37A.1 
through 37A.4 and section 37A.8 of the Tariff. 
Except as set forth in Section 37A.II, Computational Load, shall be subject to the Phasor 
Measurement Unit, Ride-Through and Ramp requirements set forth in Sections 37A.5 through 
37A.7 of the Tariff.  The Transmission Provider shall determine whether Computational Load is 
associated with a Large Load based on information provided by the Transmission Customer to 
the Transmission Provider for such purpose, as set forth in the Business Practices Manual for 
Large Load.
A Transmission Customer taking Transmission Service on behalf of a Large Load shall 
demonstrate its ability to effectuate compliance with each of the requirements of this Section 
37A.  The Transmission Customer shall provide the Transmission Provider with documentation 
necessary for the Transmission Provider to verify compliance with the requirements of this 
Section 37A.  Such documentation may include applicable agreement(s), if any, between the 
Transmission Customer and the entity or entities that own, operate or use the Large Load, or an 
attestation signed by an authorized officer of the Transmission Customer demonstrating that the 
Transmission Customer will be provided access to all information reasonably required to enable 
the Transmission Customer to comply with and for the requirements of this Section 37A,

MISO
37A
FERC Electric Tariff
Applicability of Large Load Reliability Requirements
MODULES
31.0.0
Effective On: December 4, 2026
including compliance with the terms of any operating protocols adopted by the Transmission 
Provider, Transmission Owner and/or the Transmission Customer for a specific Large Load.  
Failure to comply with the requirements established in this Section 37A may result in a 
delayed Service Commencement Date, a period of time needed for corrective action, operational 
limitations, or other remediation action(s) by Transmission Provider as may be necessary to 
maintain Transmission System reliability.  The process by which Transmission Provider will 
determine whether any such measures are appropriate, which may include the period of time 
during which corrective action must be undertaken, shall be as set forth in the Business Practices 
Manual for Large Load.
II.
Transition Provisions
1)
For purposes of these transition provisions, Load associated with a transmission 
project shall be defined as meeting the “MTEP/EPR Condition” if the project has 
either: (a) been approved by the Transmission Provider Board in MTEP 2026, or a 
prior MTEP; or, (b) been submitted to the Transmission Provider for Expedited 
Project Review (EPR) on or prior to June 18, 2026, in accordance with 
Attachment FF of the Tariff.
2)
A Transmission Customer taking Transmission Service on behalf of a Large Load 
shall ensure that all Large Load shall be subject to all the requirements as set forth 
in this Section 37A, provided that:
(a)
Fully Exempt Large Load:
A Large Load that has a Service Commencement Date on or prior to 
December 4, 2026, shall be exempt from all requirements set forth in this 
Section 37A with respect to the portion of the Large Load that has

MISO
37A
FERC Electric Tariff
Applicability of Large Load Reliability Requirements
MODULES
31.0.0
Effective On: December 4, 2026
procured Transmission Service as of the Service Commencement Date.  
Any modification or series of modifications to a Load that meets the 
MTEP/EPR Condition, which results in a cumulative increase of 25 MW 
or more in Transmission Service for such Load and with a Service 
Commencement Date after December 4, 2026, shall be subject to 
subsection (2)(b) below.
(b)
Partially Exempt Large Load:
(i) A Large Load, or a portion of a Large Load, that does not have a 
Service Commencement Date prior to December 4, 2026, but that meets 
the MTEP/EPR Condition as defined herein shall be subject to the 
requirements set forth in Sections 37A.1 through 37A.5 and Section 
37A.8, and shall be exempt from the requirements set forth in Sections 
37A.6 through 37A.7.
(ii) A Large Load, or a portion of Large Load, that does not have a Service 
Commencement Date prior to December 4, 2026, and that has not met the 
MTEP/EPR Condition but has submitted Load associated with a 
transmission project to the Transmission Provider for EPR on or after June 
19, 2026, but on or before October 31, 2026, shall be subject to all 
requirements set forth in this Section 37A, provided that Transmission 
Provider may waive the requirements set forth in Section 37A.6 based 
upon a determination that: a) exemption from such requirements would 
not have an adverse reliability impact; and, b) compliance with such 
requirements would result in significant costs.  The Business Practices

MISO
37A
FERC Electric Tariff
Applicability of Large Load Reliability Requirements
MODULES
31.0.0
Effective On: December 4, 2026
Manual for Large Load shall set forth the process and documentation 
necessary for Transmission Provider to determine whether such criteria 
have been met.
(c)
Non-Exempt Large Load:
A Large Load, or a portion of a Large Load, that does not meet the 
MTEP/EPR Condition shall be subject to all applicable requirements set 
forth in this Section 37A.
3)
Notwithstanding any of the provisions above the Transmission Provider has the 
right to require compliance with any or all requirements of this Section 37A if the 
Transmission Provider determines that operation of a Large Load results in a 
material adverse effect on Transmission System reliability.  The process by which 
Transmission Provider will make such a determination and which, if any, of the 
requirements of this Section 37A are to be applied shall be as set forth in the 
Business Practices Manual for Large Load.

MISO
37A.1
FERC Electric Tariff
Large Load Information and Basic Facility Data Requirements
MODULES
31.0.0
Effective On: December 4, 2026
Large Load Information and Basic Facility Data Requirements
A Transmission Customer taking Transmission Service on behalf of a Large Load shall 
be responsible for providing the Transmission Provider with basic information, one-line 
diagrams, and a description of the electrical characteristics of the Large Load for all Large Load 
Equipment, in the format and consistent with the timelines specified in the Business Practice 
Manual for Large Load.  Any changes to the characteristics of a Large Load and/or Large Load 
Equipment, including any changes to the modeling details for the Large Load, shall be provided 
to the Transmission Provider in a timely manner, consistent with the Business Practices Manual 
for Large Load. Such changes may include, but are not limited to, Load MW amounts, firm and 
non-firm MW amounts, any dispatchable Load MWs, power factor, metering, telemetry, breaker 
configuration, staged Load additions and annual energy as further set forth in the Business 
Practices Manual for Large Load. 
A Transmission Customer taking Transmission Service on behalf of a Large Load must 
coordinate with the Transmission Owner where the Large Load Point(s) of Withdrawal is located 
pursuant to the Transmission Provider’s load interconnection guidance and applicable NERC 
standards.

MISO
37A.2
FERC Electric Tariff
Large Load Modeling Requirements
MODULES
31.0.0
Effective On: December 4, 2026
Large Load Modeling Requirements 
A Transmission Customer taking Transmission Service on behalf of a Large Load shall 
provide the Transmission Provider with verified and complete electrical models of the Large 
Load, as well as detailed Load profiles, for modeled Loads, in the format and consistent with the 
timelines specified in the Business Practice Manual for Transmission Planning.  Such model 
information must include sufficient detail for the Transmission Provider to evaluate system 
performance under contingency conditions in accordance with currently active versions of 
Transmission System Planning Performance Standards.
Following completion of applicable studies and prior to the Service Commencement Date 
of the Large Load, the Transmission Customer shall submit final verified models to the 
Transmission Provider in accordance with the Business Practices Manual for Large Load.  The 
Transmission Customer shall provide notice to the Transmission Provider of any material 
modifications to the Large Load and shall not implement any such proposed modifications until 
studied and approved by the Transmission Provider in accordance with the Business Practices 
Manual for Large Load.
The final models of a Large Load shall reflect the as-built configuration and actual 
operating characteristics of the Large Load and Large Load Equipment.  The Transmission 
Customer shall maintain and update models as required by the Transmission Provider.

MISO
37A.3
FERC Electric Tariff
Large Load Telemetry Requirements
MODULES
31.0.0
Effective On: December 4, 2026
Large Load Telemetry Requirements
Prior to the later of the Service Commencement Date of a Large Load or September 1, 
2027, a Transmission Customer taking Transmission Service on behalf of a Large Load must 
provide real-time telemetry for the Large Load, either directly, through the applicable 
Transmission Owner, or other Transmission Provider-approved communication path, in the form 
and manner as set forth in the Business Practices Manual for Large Load. 
Individual metering will be required for all Large Load and any Generation Resource(s) 
serving such Large Load that is located behind the same Point(s) of Withdrawal to the 
Transmission System as the Large Load and meeting thresholds outlined in the Business 
Practices Manual for Large Load.  All telemetry shall be provided via Inter-Control Center 
Communications Protocol (ICCP) and must meet Transmission Provider update requirements as 
specified in the Business Practices Manual for Large Load.  The Transmission Customer must 
use commercially reasonable efforts to maintain telemetry availability and accuracy for the Large 
Load and must promptly correct erroneous data, bad mappings, and ICCP modeling issues.

MISO
37A.4
FERC Electric Tariff
Large Load Forecast Data Requirements
MODULES
31.0.0
Effective On: December 4, 2026
Large Load Forecast Data Requirements
Prior to the later of the Service Commencement Date of a Large Load or September 1, 
2027, a Transmission Customer taking Transmission Service on behalf of a Large Load must 
provide day(s) ahead and real-time Load Forecasts for a Large Load directly to the Transmission 
Provider to support the Reliability Assessment Commitment (RAC) and Security Constrained 
Economic Dispatch (SCED) processes, along with other reliability studies.  The Load Forecasts 
shall be updated to reflect the most current information on the expected Demand, in accordance 
with the Business Practices Manual for Large Load.

MISO
37A.5
FERC Electric Tariff
Large Load Phasor Measurement Unit Requirements
MODULES
31.0.0
Effective On: December 4, 2026
Large Load Phasor Measurement Unit Requirements
The Transmission Customer taking Transmission Service on behalf of a Computational 
Load shall be subject to the Phasor Measurement Unit (PMU) requirements set forth in this 
Section 37A.5.  Prior to the later of the Service Commencement Date of a Large Load or 
September 1, 2027, phasor measurement recording and communications equipment must be 
installed by the Transmission Owner, at the Transmission Customer’s expense, that is capable, at 
a minimum, of gathering phasor measurements as specified in Business Practices Manual for 
Large Load.  The phasor measurement equipment must be installed at the Transmission Owner’s 
side of the Point(s) of Withdrawal and become part of the Transmission Owner interconnection 
facilities.  To the extent similar quality equipment is being added or already exists, such as relays 
or digital fault recorders, that can collect data at least at the same rate as PMU and which data is 
synchronized via a high-accuracy satellite clock, such equipment may be utilized to satisfy this 
requirement if the equipment is located on the Transmission Owner’s side of the Point(s) of 
Withdrawal.  Phasor measurements must be streamed in the format specified in the Business 
Practices Manual for Large Load and be provided to the Transmission Provider by the 
Transmission Owner.

MISO
37A.6
FERC Electric Tariff
Large Load Ride-Through Requirements
MODULES
31.0.0
Effective On: December 4, 2026
Large Load Ride-Through Requirements
A Transmission Customer taking Transmission Service on behalf of a Computational 
Load shall be responsible for ensuring that the Computational Load remains connected to the 
Transmission System and continue operation during voltage and frequency disturbances within 
the performance criteria established by the Transmission Provider in the Business Practices 
Manual for Large Load.
Ride-through requirements apply at the Point(s) of Withdrawal and may include 
evaluation, testing, modeling, monitoring, and other compliance measures established by the 
Transmission Provider in the Business Practices Manual for Large Load.

MISO
37A.7
FERC Electric Tariff
Large Load Ramp Requirements
MODULES
31.0.0
Effective On: December 4, 2026
Large Load Ramp Requirements
A Transmission Customer taking Transmission Service on behalf of a Computational 
Load shall be subject to the ramp requirements set forth in this Section 37A.7.  Ramp limits shall 
be measured in aggregate across the applicable Point(s) of Withdrawal during stable-state 
transition, including any reduction/ramp smoothing provided by generation or other resources 
that meets the eligibility requirements specified in the Business Practices Manual for Large 
Load.  Computational Load shall be subject to up-ramp and down-ramp limits established by the 
Transmission Provider consistent with the process set forth in the Business Practices Manual for 
Large Load.  The Computational Load must have an effective up and down ramp rate not 
exceeding the specified limit outlined in the Business Practices Manual for Large Load unless 
otherwise directed by the Balancing Authority, Reliability Coordinator, or Transmission 
Operator.

MISO
37A.8
FERC Electric Tariff
Large Load Audit Rights
MODULES
31.0.0
Effective On: December 4, 2026
Large Load Audit Rights
The Transmission Provider has the right to audit or verify the information provided by a 
Transmission Customer taking Transmission Service on behalf of a Large Load including, but 
not limited to, information related to the registration, claimed capacity, operations, modeling, 
inverter settings, metering, settlements, Large Load Equipment, and/or any other information 
related to the participation of the Large Load under this Tariff.  The Transmission Customer shall 
maintain individual Large Load data and information related to the registration, Load Forecasts, 
operations, modeling, metering, and/or settlements for five (5) Years.  The Transmission 
Provider shall maintain individual Large Load data and information it receives related to the 
registration, Load Forecasts, operations, modeling, metering, and/or settlements for five (5) 
Years.