Transmission Planning Criteria
Revision 2.1
PUBLIC
TableofContents
1. Purpose ..................................................................................................................................................................................3 2. Introduction............................................................................................................................................................................3 3. Document Review..................................................................................................................................................................3 4. Applicability ..........................................................................................................................................................................3 5. System Models .......................................................................................................................................................................4 6. Thermal Loading Criteria ......................................................................................................................................................4 6.1 Applicable Ratings for Consumers Energy Transmission Elements for Various Conditions ....................................................................... 4 7. Voltage Criteria......................................................................................................................................................................4 7.1 Steady State Voltage .................................................................................................................................................................................. 4 7.2 Post-Contingency Voltage Deviations ....................................................................................................................................................... 4 7.3 Loss of Generation Voltage Deviation ....................................................................................................................................................... 4 7.4 Capacitor Switching Voltage Deviation ..................................................................................................................................................... 5 7.5 Transient Voltage Response....................................................................................................................................................................... 5 8. Steady State Criteria ..............................................................................................................................................................5 8.1 Timing........................................................................................................................................................................................................ 5 8.2 Load Level ................................................................................................................................................................................................. 5 8.3 Sensitivity Analysis ................................................................................................................................................................................... 5 8.4 Spare Equipment Strategy .......................................................................................................................................................................... 5 8.5 Planning Events ......................................................................................................................................................................................... 6 9. Stability Criteria .....................................................................................................................................................................7 9.1 Overview.................................................................................................................................................................................................... 7 9.2 Timing........................................................................................................................................................................................................ 7 9.3 Load Level ................................................................................................................................................................................................. 7 9.4 Sensitivity Analysis ................................................................................................................................................................................... 7 9.5 Planning Events ......................................................................................................................................................................................... 7 9.6 Criteria or Methodology used to identify System instability for conditions such as Cascading, voltage instability, or uncontrolled
islanding ..................................................................................................................................................................................................... 7 10. Extreme Events ......................................................................................................................................................................8 11. Short Circuit Criteria ...........................................................................................................................................................12 12. Power Quality/Reliability Criteria for Delivery Points ........................................................................................................12 13. Facility Connections and Transmission Service Requests ...................................................................................................12 14. Definitions, Abbreviations, and Acronyms ..........................................................................................................................13 Document Review and Approval ....................................................................................................................................................14 Revision History ..............................................................................................................................................................................14 Page 2 of 14
1. Purpose
The Transmission Planning Criteria (Planning Criteria) adheres to current applicable NERC and ReliabilityFirst
(RF) Reliability Standards which establish Transmission system planning performance requirements within the
planning horizon to result in a Bulk Electric System (BES) that will operate reliably over a broad spectrum of
System conditions and following a wide range of probable Contingencies. The Planning Criteria documents the
parameters used by Consumers Energy Transmission Planning (Transmission Planning) to evaluate System
performance as required in the standards and to identify System needs, evaluate Corrective Action Plans, and
justify modifications to the System.
2. Introduction
The Planning Criteria address its applicability, specifies the models to be used to assess System performance, and
specifies performance criteria for Steady State, Stability, and Short Circuit analysis. The Planning Criteria
documents the following parameters to evaluate the System performance:











Steady state voltage limits
Post contingency voltage deviations
Transient voltage response
- low voltage level
- time below the low voltage level
Thermal loading limits
Short circuit limits
Stability limits
- Cascading
- instability
- uncontrolled islanding.
Frequency of studies
Years to be studied
Load levels
Conditions studied (planning events, extreme events, and rationale for events selected)
Spare equipment strategy
3. DocumentReview
The Planning Criteria will be reviewed by Transmission Planning annually, or may be updated more often in
response to changes in standards or other information.
4. Applicability
Transmission Planning evaluates whether Consumers Energy facilities are BES facilities (Facilities) whenever
Consumers Energy facilities are planned to be connected to the existing BES, or whenever the NERC definition
of the BES changes. The evaluation compares the characteristics of Consumers Energy planned facilities against
the NERC definition of Bulk Electric System per the current NERC Glossary of Terms Used in NERC Reliability
Standards. Those Consumers Energy facilities identified as Facilities must be planned per this Planning Criteria.
Page 3 of 14
5. SystemModels
System models to be used to assess System performance are developed by Consumers Energy in accordance with
applicable NERC standards. The models include Corrective Action Plans and represent System conditions,
including:
1. Existing Facilities
2. Known outage(s) of generation or Transmission Facility(ies) with a duration of at least six months.
3. New planned Facilities and changes to existing Facilities.
4. Real and reactive Load forecasts.
5. Known commitments for Firm Transmission Service and Interchange.
6. Resources (supply or demand side) required for Load.
Consumers Energy may also choose to use peer-reviewed models produced by its Planning Coordinator or its
Regional Reliability Organization.
6. ThermalLoadingCriteria
6.1 Applicable Ratings for Consumers Energy Transmission Elements for Various Conditions
Double Contingencies
Extreme
N-1 after System
Events
N-2
Adjustments
Rating 
Normal
Emergency1
Normal
Emergency1 Emergency1
1
Long term emergency rating. For outages expected to be short term in duration a short term emergency
rating, applicable to the expected outage duration, may be used for limiting elements with appropriate
documentation as to applicability.
Condition 
Normal or Single
Generator Out
Single Transmission
Element Out
7. VoltageCriteria
7.1 Steady State Voltage
Location
345 kV substation bus
138 kV substation bus
Normal Voltage Limits
Minimum
Maximum
97%
107%
97%
107%
Emergency Voltage Limits
Minimum
Maximum
92%
107%
92%
107%
7.2 Post-Contingency Voltage Deviations
The maximum acceptable voltage deviation at a transmission substation bus following a single contingency
event (other than loss of a generator or switched capacitor), after switched capacitors and adjustable
transformers have operated is 10% of nominal.
7.3 Loss of Generation Voltage Deviation
The maximum acceptable voltage deviation at a transmission substation bus due to a generator tripping during
normal system conditions before switched capacitors and adjustable transformers have operated is 5% of
nominal.
Page 4 of 14
7.4 Capacitor Switching Voltage Deviation
The maximum acceptable voltage deviation at a transmission substation bus due to a capacitor switching
during normal system conditions before other switched capacitors and adjustable transformers have operated
is 3% of nominal.
7.5 Transient Voltage Response
Transient voltage response shall be verified by demonstrating, for P1-P7 category events, applicable BES
buses recover to 80% of the pre-contingency voltage within ten seconds of the initiating event.
8. SteadyStateCriteria
8.1 Timing
Steady state analysis is performed annually. Special studies may also be conducted. Typically, years 1, 2, 5,
and 10 for System Peak Load and year 2 for System Off-Peak Load are studied, unless other study years are
necessary to coordinate with MISO studies, or as otherwise deemed appropriate by Transmission Planning.
Years 2, 5, and 10 are representative of close, middle, and long range study years.
8.2 Load Level
System Peak Load = 100% of the Corporate Load Forecast, 50% confidence level.
System Off-Peak Load = 85% of the Corporate Load Forecast, 50% confidence level.
8.3 Sensitivity Analysis
Items 1 through 3 below are typically adjusted for the sensitivity analysis. Item 8.b. must be studied, if
applicable. Transmission Planning may also choose one or more of items 4 through 8 as appropriate to be
adjusted for the sensitivity analysis to aid in risk assessment:
1.
2.
3.
4.
5.
6.
7.
Generation additions, retirements, or other dispatch scenarios (Ludington generatingpumping)
Expected transfers (westeast, eastwest)
Real and reactive forecasted Load (MW = Corporate Load Forecast 65% confidence level)
Real and reactive forecasted Load (MW = Corporate Load Forecast 95% confidence level)
Expected in service dates of new or modified Transmission Facilities
Reactive resource capability
Controllable Loads and Demand Side Management
8. a) Duration or timing of known Transmission outages
b) Known outage(s) of generation or Transmission Facility(ies) with a duration of at least six months 8.4 Spare Equipment Strategy
Unavailability of long lead time (one year or more) Transmission equipment will be assessed for System
impact under P0, P1 and P2 events in Table 1.2 However, Transmission Planning may choose to study
particular long lead time equipment events, as appropriate, to coordinate with MISO studies.
1
Year 2 is defined as the 2nd year following the latest summer peak, e.g. year 2 following the summer 2014 peak will be the summer of 2016
and year 5 will be summer of 2019.
2
At this time Consumers Energy does not own any long lead time (one year or more) Transmission equipment.
Page 5 of 14
8.5 Planning Events
Transmission Planning identifies those planning events in Table 1 that are expected to produce more severe
System impacts and lists them in a Planning Event Contingency list to evaluate for System performance. The
MISO and adjacent Transmission Planners must be consulted to ensure that planning events on adjacent
Systems which may impact the Consumers Energy Systems are included in the Planning Event Contingency
list.
Each Contingency must simulate the removal of all elements that Protection Systems and automatic controls
are expected to disconnect, and simulate Normal Clearing unless otherwise specified. Appropriate automatic
operation of generator exciters, phase-shifting transformers, load tap changing transformers, and switched
capacitors and inductors shall be simulated.
The analyses shall include the impact of subsequent:
 Tripping of generators where simulations show the generator does not meet Section 2.2 of CE Facility
Connection Requirements for low voltage ride through capability or tripping of generators based on
information from the generator owner. The assessment shall include any assumptions made.
 Tripping of Transmission elements where transient swings cause a Protection System operation based on
generic or actual relay models.
The rationale for those Contingencies selected for inclusion in the Planning Event Contingency list is either:
1. They are part of a full set of planning event contingencies where those having a more severe System
impact are later identified through filtering of the contingency output.
2. They are provided by MISO as a planning event on an adjacent System which may impact the Consumers
Energy System.
Studies shall be performed for planning events in the Planning Event Contingency List to determine whether
the BES meets the performance requirements listed below.
1. The System shall remain stable. Cascading and uncontrolled islanding shall not occur.
2. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding
P0.
3. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are
allowed if such adjustments are executable within the time duration applicable to the Facility Ratings.
4. Applicable Facility Ratings shall not be exceeded.
5. System steady state voltages and post-Contingency voltage deviations shall be within acceptable limits as
established by the MISO and Consumers Energy.
6. The response of voltage sensitive Load that is disconnected from the System by end-user equipment
associated with an event shall not be used to meet steady state performance requirements.
Page 6 of 14
9. StabilityCriteria
9.1 Overview
Stability is the ability of the System to remain in synchronous equilibrium under steady state operating
conditions and to regain a state of equilibrium after a disturbance has occurred.
9.2 Timing
Stability analysis is performed annually. Special studies may also be conducted. Typically year 2 (System
Peak Load) and year 2 (System Off-Peak Load) are studied, unless other study years are determined based on
the availability of cases in the most recent regional dynamic data sets, or as otherwise deemed appropriate by
Transmission Planning. Year 2 is representative of close range study years. Years 6-10 must be assessed only
if there are planned material generation additions or changes during that timeframe and must include the
rationale for determining material changes.
9.3 Load Level
System peak = 100% of the Corporate Load Forecast, 50% confidence level.
System off-peak = 70-80% of the Corporate Load Forecast, 50% confidence level.
Dynamic models may use the cases available in the most recent regional dynamic data sets.
9.4 Sensitivity Analysis
Items 1 and 2 below are typically adjusted for the sensitivity analysis. Transmission Planning may also
choose one or more of items 3-5 as appropriate to be adjusted for the sensitivity analysis:
1. Generation additions, retirements, or other dispatch scenarios (Ludington generatingpumping)
2. Expected transfers (westeast, eastwest)
3. Load level, load forecast, or dynamic Load model assumptions (MW = Corporate Load Forecast 95%
confidence level)
4. Expected in service dates of new or modified Transmission Facilities
5. Reactive resource capability
9.5 Planning Events
Transmission Planning identifies those planning events in Table 1 that are expected to produce more severe
System impacts and lists them in a Planning Event Contingency list to evaluate for System performance.
Studies shall be performed for planning events in the Planning Event Contingency List to determine whether
the BES meets the performance requirements in accordance with TPL-001-4.
9.6 Criteria or Methodology used to identify System instability for conditions such as Cascading,
voltage instability, or uncontrolled islanding
The analysis shall investigate the potential for Cascading, voltage instability, or uncontrolled islanding, if one
or more of the following are observed in planning assessments:




Thermal overload on a facility exceeding phase protective relay settings described in NERC PRC-023-3
Transmission Relay Loadability, and trips.
Loss of positive reactive power margin.
Single generator which pulls out of synchronism.
Transient voltage response not meeting criteria in Section 7.5.
Page 7 of 14
10.ExtremeEvents
Transmission Planning identifies a subset of those extreme events from NERC Std. TPL-0010-4 Table 1 that
are expected to produce more severe System impacts and lists them in an Extreme Event Contingency list. The
subset of Contingencies selected for evaluation for System performance is based on the rationale that
transmission planning should consider the impact of Extreme events on high or critical load centers and
locations of high concentrations of generation capacity. Each Contingency must simulate the removal of all
elements that Protection Systems and automatic controls are expected to disconnect, and simulates Normal
Clearing unless otherwise specified in NERC Std. TPL-001-4 Table 1.
These events may involve significant loss of generation or load, however, they should not result in cascade
outages beyond the adjacent area transmission system.
If the analysis concludes there is Cascading caused by the occurrence of extreme events, an evaluation of
possible actions designed to reduce the likelihood or mitigate the consequences and adverse impacts of the
event(s) shall be conducted.
Page 8 of 14
Table 1
Category
Initial Condition
P0
No
Contingency
Normal System
Planning Event1
None
Fault
Type2
BES
Level3
N/A
EHV,
HV
3Ø
EHV,
HV
Interruption
of Firm
Transmission
Service
Allowed4
(Maximum)
NonConsequential
Load Loss
Allowed
(Maximum)
Load
Level
(% of
System
Peak)
Ratings
Used14
Minimum
Voltage
Maximum
Voltage
No
No
100%
Normal
97%
107%
Normal
97%
107%
Emergency
92%
107%
100%
Emergency
92%
107%
100%
Emergency
92%
107%
Loss of one of the following:
P1
Single
Contingency
P2
Single
Contingency
1. Generator
Normal System
2. Transmission Circuit
5
3. Transformer
4. Shunt Device6
5. Single pole of a DC line
SLG
1. Opening of a line section w/o a fault7
N/A
2. Bus Section Fault
Normal System
3. Internal Breaker Fault8
(non-Bus-tie Breaker)
SLG
8
4. Internal Breaker Fault
(Bus-tie Breaker)
P3
Multiple
Contingency
Loss of generator
unit followed by
System
adjustments9
Loss of one of the following:
1. Generator
2. Transmission Circuit
3. Transformer5
4. Shunt Device6
5. Single pole of a DC line
3Ø
9
No
12
No
EHV,
HV
No9
No12
EHV
No9
No
HV
Yes (100 MW)
Yes (100 MW)
9
EHV
No
No
HV
Yes (300 MW)
Yes (300 MW)
EHV,
HV
Yes
Yes
EHV,
HV
No9
No12
100%
SLG
Page 9 of 14
Table 1 continued
Category
P4
Multiple
Contingency
(Fault plus
stuck
breaker10)
Initial Condition
Normal System
P5
Multiple
Contingency
(Fault plus
relay failure
to operate)
Normal System
P6
Multiple
Contingency
(Two
overlapping
singles)
Loss of one of the
following followed by
System adjustments9:
1. Transmission Circuit
2. Transformer5
3. Shunt Device6
4.
Single pole of a DC line
P7
Multiple
Contingency
(Common
Structure)
Normal System
Planning Event1
Fault
Type2
Loss of multiple elements
caused by a stuck breaker10
(non-Bus-tie Breaker)
attempting to clear a Fault on
one of the following:
1. Generator
2. Transmission Circuit
3. Transformer5
6
4. Shunt Device
5. Bus Section
2Ø
6. Loss of multiple elements
10
caused by a stuck breaker
(Bus-tie Breaker) attempting
to clear a Fault on the
associated bus
2Ø
Delayed Fault Clearing due to
the failure of a non-redundant
relay13 protecting the Faulted
element to operate as
designed, for one of the
following:
1. Generator
2. Transmission Circuit
3. Transformer5
6
4. Shunt Device
5. Bus Section
Loss of one of the following:
1. Transmission Circuit
2. Transformer5
3. Shunt Device6
Interruption
of Firm
Transmission
Service
Allowed4
(Maximum)
NonConsequential
Load Loss
Allowed
(Maximum)
Load
Level
(% of
System
Peak)
Ratings
Used14
Minimum
Voltage
Maximum
Voltage
EHV
No9
No
HV
Yes (300 MW)
Yes (300 MW)
100%
Emergency
92%
107%
EHV,
HV
Yes (300 MW)
Yes (300 MW)
EHV
No9
No
100%
Emergency
92%
107%
Emergency
92%
107%
Emergency
92%
107%
BES
Level3
SLG
HV
3Ø
4. Single pole of a DC line
SLG
The loss of:
1. Any two adjacent (vertically
or horizontally) circuits on
11
common structure > 1 mile
2. Loss of a bipolar DC line
SLG
Yes (300 MW)
Yes (300 MW)
Yes (100 MW)
Yes (100 MW)
EHV,
HV
EHV,
HV
Up to
85%
Yes (300 MW)
Yes (300 MW)
100%
Yes (300 MW)
Yes (300 MW)
100%
Page 10 of 14
Footnotes to Table 1
1
If the event analyzed involves BES elements at multiple System voltage levels, the lowest System voltage level of the element(s) removed for the analyzed event determines the stated
performance criteria regarding allowances for interruptions of Firm Transmission Service and Non-Consequential Load Loss.
2
Unless specified otherwise, simulate Normal Clearing of faults. Single line to ground (SLG) or three-phase (3Ø) are the fault types that must be evaluated in Stability simulations for the
event described. A 3Ø or a double line to ground fault study indicating the criteria are being met is sufficient evidence that a SLG condition would also meet the criteria.
3
Bulk Electric System (BES) level references include extra-high voltage (EHV) Facilities defined as greater than 300kV and high voltage (HV) Facilities defined as the 300kV and lower
voltage Systems. The designation of EHV and HV is used to distinguish between stated performance criteria allowances for interruption of Firm Transmission Service and NonConsequential Load Loss.
4
Curtailment of Conditional Firm Transmission Service is allowed when the conditions and/or events being studied formed the basis for the Conditional Firm Transmission Service.
5
For non-generator step up transformer outage events, the reference voltage, as used in footnote 1, applies to the low-side winding (excluding tertiary windings). For generator and
Generator Step Up transformer outage events, the reference voltage applies to the BES connected voltage (high-side of the Generator Step Up transformer). Requirements which are
applicable to transformers also apply to variable frequency transformers and phase shifting transformers.
6
Requirements which are applicable to shunt devices also apply to FACTS devices that are connected to ground.
7
Opening one end of a line section without a fault on a normally networked Transmission circuit such that the line is possibly serving Load radial from a single
source point.
8
An internal breaker fault means a breaker failing internally, thus creating a System fault which must be cleared by protection on both sides of the breaker.
9
An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Firm Transmission Service following Contingency events. Curtailment of Firm
Transmission Service is allowed both as a System adjustment (as identified in the column entitled ‘Initial Condition’) and a corrective action when achieved through the appropriate redispatch of resources obligated to re-dispatch, where it can be demonstrated that Facilities, internal and external to the Transmission Planner’s planning region, remain within applicable
Facility Ratings and the re-dispatch does not result in any Non-Consequential Load Loss. Where limited options for re-dispatch exist, sensitivities associated with the availability of those
resources should be considered.
10
A stuck breaker means that for a gang-operated breaker, all three phases of the breaker have remained closed. For an independent pole operated (IPO) or an independent pole
tripping (IPT) breaker, only one pole is assumed to remain closed. A stuck breaker results in Delayed Fault Clearing.
11
Excludes circuits that share a common structure (Planning event P7, Extreme event steady state 2a) or common Right-of-Way (Extreme event, steady state
2b) for 1 mile or less.
12
An objective of the planning process is to minimize the likelihood and magnitude of Non-Consequential Load Loss following planning events. In limited circumstances, NonConsequential Load Loss may be needed throughout the planning horizon to ensure that BES performance requirements are met. However, when Non-Consequential Load Loss is
utilized under footnote 12 within the Near-Term Transmission Planning Horizon to address BES performance requirements, such interruption is limited to circumstances where the NonConsequential Load Loss meets the conditions shown in Attachment 1. In no case can the planned Non-Consequential Load Loss under footnote 12 exceed 75 MW for US registered
entities. The amount of planned Non-Consequential Load Loss for a non-US Registered Entity should be implemented in a manner that is consistent with, or under the direction of, the
applicable governmental authority or its agency in the non-US jurisdiction.
13
Applies to the following relay functions or types: pilot (#85), distance (#21), differential (#87), current (#50, 51, and 67), voltage (#27 & 59), directional (#32, &67), and tripping (#86, &
94).
14
Where Emergency rating is specified it is the long term emergency rating, with the exception that for outages expected to be short term in duration a short term emergency rating,
applicable to the expected outage duration, may be used for limiting elements with appropriate documentation as to applicability.
Page 11 of 14
11.ShortCircuitCriteria
Short circuit currents shall not exceed the interrupting capability of circuit breakers or other fault interrupting devices
for faults these devices will be expected to interrupt based on the System short circuit model, with any planned
generation and Transmission Facilities in service which could impact the study area. The capability of circuit
breakers and other fault interrupting devices will be the manufacturer’s nameplate rating, unless reduced to account
for reclosing times.
12.PowerQuality/ReliabilityCriteriaforDeliveryPoints
Voltage distortion (harmonics) is limited per IEEE 519. Voltage flicker due to flicker loads are limited by the more
stringent of the 230 V flicker curve described in Table A.1 of IEEE 1453-2004, and 5% of nominal. The maximum
voltage deviation limits at a transmission bus during normal system conditions are provided in Section 7 of this
document.
Voltage unbalance shall not exceed 1.0% at the POI as measured by the formula:
Voltage Unbalance (%) = 100 X (Magnitude of the Maximum Voltage Deviation from Average Voltage) / Average Voltage.
[Average Voltage = (Sum of the three Phase Voltages) / 3]
13.FacilityConnectionsandTransmissionServiceRequests
Consumers Energy Facility Connection Requirements provide consistent procedures and technical requirements for
Generation, Transmission, or End-users desiring to interconnect Facilities to the Consumers Energy transmission
system. The Facility Connection Requirements comply with and refer to this Planning Criteria.
Page 12 of 14
CE_Transmission_Planning_Criteria.docx
14.Definitions,Abbreviations,andAcronyms
In general refer to the NERC Glossary of Terms Used in Reliability Standards, Updated July 7, 2014. Certain
particular definitions as used by Consumers Energy in this document are as follows:
Annually – Once per calendar year, not to exceed 15 months between occurrences.
BES – Bulk Electric System
Consumers Energy – Consumers Energy Company
Corporate Load Forecast – The peak demand forecast developed by the Consumers Energy Planning and Analysis
department.
Emergency Rating – The rating as defined by the equipment owner that specifies the level of electrical loading,
expressed in megavolt-amperes (MVA) or other appropriate units, that a system, facility, or element can support or
withstand for a finite period. The rating assumes acceptable loss of equipment life or other physical or safety
limitations for the equipment involved.
Long-Term Transmission Planning Horizon – The transmission planning period that covers years six through ten or
beyond when required to accommodate any known longer lead time projects that may take longer than ten years to
complete.
MISO (Midcontinent Independent System Operator, Inc.) – The Transmission Planning Coordinator for Consumers
Energy.
MTEP (MISO Transmission Expansion Plan (or Planning process)) – Per the MISO, this is “Value-based Planning
that focuses on maximizing value to consumers while minimizing the total energy, capacity and transmission costs”.
Near-Term Transmission Planning Horizon – The transmission planning period that covers years one through five.
Normal Rating – The rating as defined by the equipment owner that specifies the level of electrical loading,
expressed in megavolt-amperes (MVA) or other appropriate units that a system, facility, or element can support or
withstand through the daily demand cycles without loss of equipment life.
ReliabilityFirst (ReliabilityFirst Corporation) – The compliance monitor for Consumers Energy. ReliabilityFirst's
mission is to preserve and enhance electric service reliability and security for the interconnected electric systems
within the ReliabilityFirst geographic area.
Transmission Planning – The Consumers Energy transmission planning group which: 1) applies the Planning Criteria
to identify system needs; 2) applies ingenuity, experience, and judgment in developing Corrective Action Plans to
address system needs; and 3) applies the Planning Criteria to evaluate Corrective Action Plans to assure the desired
result.
Page 13 of 14
CE_Transmission_Planning_Criteria.docx
DocumentReviewandApproval
Responsible Parties and DOET Management
I approve this Consumers Energy Distribution Operations & Engineering and Transmission, Transmission
Planning Criteria document.
Donald A. Lynd
Director, Electric Transmission Planning and Protection
James R. Anderson
Executive Director, Electric Transmission and High Voltage Distribution Engineering
***
The electronic approval of this document, by the above-named individuals, is on file.
RevisionHistory
Revision
Approval Date
0
January 10, 2015
1.0
June 25, 2015
2.0
2.1
Implementation
Date
Upon
Registration as
TO/TP
Revision Description

Original Documentation
Upon
Registration as a
TO/TP

Revised to align with TPL-001-0.1; TPL-002-0b; TPL-0030b; and TPL-004-0a
September 21, 2015
January 1, 2016

Revised to align with TPL-001-4
December 17, 2015
January 1, 2016

Revised Category P6 Criteria
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CE_Transmission_Planning_Criteria.docx