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Individual or group.  (45 Responses)
Name  (29 Responses)
Organization  (29 Responses)
Group Name  (16 Responses)
Lead Contact  (16 Responses)
Contact Organization  (16 Responses)
Question 1  (45 Responses)
Question 1 Comments  (45 Responses)
Question 2  (45 Responses)
Question 2 Comments  (45 Responses)
Question 3  (43 Responses)
Question 3 Comments  (45 Responses)
Question 4  (44 Responses)
Question 4 Comments  (45 Responses)
Question 4  (43 Responses)
Question 4 Comments and/or supporting data:   (45 Responses)
Question 5  (45 Responses)
Question 5 Comments  (45 Responses)
Question 6  (45 Responses)
Question 6 Comments  (45 Responses)
Question 7  (44 Responses)
Question 7 Comments  (45 Responses)
Question 7 Comments  (45 Responses)
Question 8  (41 Responses)
Question 8 Comments  (45 Responses)
Question 9  (41 Responses)
Question 9 Comments  (45 Responses)
Question 10  (43 Responses)
Question 10 Comments  (45 Responses)
Question 11  (0 Responses)
Question 11 Comments  (45 Responses)
Question 12  (0 Responses)
Question 12 Comments  (45 Responses)
Question 13  (0 Responses)
Question 13 Comments  (45 Responses)
 
Individual
Russell A. Noble
Cowlitz County PUD
Yes
Did you mean to say above that Generator Owners typically do not have in-house expertise and would have to either hire...? YES - Cowlitz as a Generator Owner does not have the in house expertise. Delays result in our efforts to obtain modeling information as we try and find consultants willing to do the work. The Generator Operator is the entity which should be held responsible.
Yes
 
Yes
 
No
I think you meant for the Generator Operator to supply the generator data.
No
 
Yes
 
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
No
 
Yes, agree with proposed phase in period for unit excitation system verification
 
 
 
 
Group
NERC Event Analysis & Information Exchange staff
Robert W. Cummings
NERC
No
Comments: Although verification (not validation) of generator equipment settings and testing should be the responsibility of the GO, validation of generator models response to actual system events should be done by the Reliability Coordinator. This offers independent oversight of the validation. Also, validation to system events should be done for multiple events. This provides better insight to generator excitation and control performance over a wider range of conditions than a single staged test.
Yes
Ten years is an adequate backstop for re-testing. However, it should additionally be tempered by performance differences observed during validation to actual or staged system events. Repeated matching of model performance to events should also make a ten year test unnecessary.
Yes
As long as no actual differences are observed during performance comparisons to actual system events, this is an acceptable shortcut.
No
See below.
Yes
It seems that having an overall generator testing standard in place on the dynamic parameters listed in MOD-013 would be a prerequisite for an excitation testing standard.
No
The peer review process in R10 assumes that since the GOP operates the equipment, they are a technical authority on its modeling and behavior. Historically, that has been not necessarily correct, even of the owners of the equipment. Changes to excitation system models should be peer reviewed. However, a dispute resolution process would be needed for disagreements between the owners/operators and the peer team.
Yes
 
No (disagree with approach)
Units with a low capacity factor may well still be frequently needed, albeit for short but crucial periods, to support the system during peak load. Further, they may often be used in “shoulder periods” when primary resources are out on maintenance.
 
No, instead use the approach below:
There are a number of units that, through switching, can operate in multiple interconnections, making it hard to decide where they belong. To reduce complexity in administration, avoid confusion, and to have a more level playing field in North America, the standard registration thresholds of units ≥ 20 MVA per machine and ≥ 75 MVA per plant should be applied.
Yes
It is essential that the Planning Coordinator and Reliability Coordinator be allowed to designate other critical units. In some cases, despite their size, the aggregation of a number of small units can have a significant impact on the dynamics of an area. One example is the transfer capability across the state of Maine, which is influenced by the dynamics of the multiple small hydro units in the state. Similarly, the dynamic performance of small units may be critical to reliability in some local areas such as New Brunswick and Nova Scotia.
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
 
 
 
It seems that having an overall generator testing standard in place on the dynamic parameters listed in MOD-013 would be a prerequisite for an excitation testing standard.
Individual
Brent Ingebrigtson
E.ON U.S.
Yes
 
No
E.ON U.S. believes that verification data and model results should not change over time. Therefore, a re-verification schedule is not necessary. E.ON U.S recommends that verification be required whenever new equipment is installed.
No
E.ON U.S. does believe that the proxy process described is reasonable. As expressed in the response to question 2, E.ON U.S. believes that, absent installation of new equipment, a re-verification schedule is unnecessary.
Yes
 
No
E.ON U.S. believes that entities have no incentive to use inaccurate data when conducting verifications studies. Strict data verification standards are in this instance an unproductive use of resources.
Yes
 
No
While E.ON U.S. appreciates that the concern over requirements applicable to both existing and future technologies, the lack of any specific guidance on process and verification methodologies invites differing interpretations of the standard. This lack of specificity makes compliance problematic.
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
No
The generation owner/operator is in the best position to identify those facilities that require verification studies. Transmission providers should not be allowed to independently impose compliance obligations upon other parties. Any process to allow imposition of additional compliance responsibilities should be overseen by the appropriate regional reliability organization.
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
 
 
 
E.ON U.S. believes that the staggered implementation time tables for the various standard requirements could needlessly complicate initial compliance efforts. E ON U.S. requests that the SDT review these deadlines and standardize using the most lenient implementation period set forth in the current draft. E.ON U.S. recommends that the standard explicitly state in the purpose statement that voltage regulators be included in excitation system models. Voltage regulators are explicitly mentioned in R4.3 and R12. E.ON U.S. recommends that study data inputs and results only be made publicly available pursuant to Requirement 2. Depending on arrangements with vendors, actual model configuration may be proprietary and require confidential disclosure arrangements
Group
FEUS
Clinton Jacobs
FEUS
Yes
 
Yes
 
Yes
 
Yes
 
No
 
No
No, This allows for ambiguity in the interpretation of the standard by both the entity and the requlator.
No
This leaves ambiguity in the standard that can be to misinterpretation by the entity or the agency. Some guidelines should be provided for standardization to avoid confusion.
Yes agree with approach and the 5% capacity factor
 
 
No, instead use the approach below:
If the modeling methods are approved and are valid, why do entities have to prove they are right? Test the models on several units of different sizes and configurations to determine their accuracy. If modeling methods aren't accurate, fix them instead of requiring the industry go through the huge expence of testing hundreds of units that have been previously modeled. I also don't see the rationale for the differences in MVA testing requirements between RRCs. The 200 MVA rating for facilities (as specified for the eastern systems) should be the same if this standard is adopted.
No
 
Yes, agree with proposed phase in period for unit excitation system verification
 
 
 
The excitation models as currently required are comprised of testing and data collection to determine the variables for the model parameters. How does additional testing, over and above what was done to construct the model, accomplish anything and how would it be any different than original testing to complete the model?
Individual
Jianmei Chai
Consumers Energy Company
No
Generator Owners and Generator Operators do not need or use an excitation system model. This model is properly owned by those who need and use it, i.e., the Transmission Planner or Transmission Owner. The Generator Owner should be responsible only for providing input data for the model. These data include such items as: - Manufacturer (and model, if available) and type of excitation system. - Rise times, reactances, time constants, gains, and saturation factors. - Rotational inertia - Reactive compensation settings, if any. - Power system stabilizer settings, if any. - Other stability schemes, if any. Given periodic verification of these data from the Generator Operator, it should be the responsibility of the Transmission Planner to create a model that meets the needs of the Transmission Planner. Since the Generator Operator doesn't need this model, requiring the Generator Operator to hire consultants to create a model needed by other entities is simply errant nonsense. Has the SDT verified that there are adequate consultants available to meet the 2-year time window for the myriad of Generator Operators who would be tasked with creating a model they do not need?
Yes
Ten years is appropriate with the caveats listed in Requirement 12.
Yes
This looks to be a "sister unit" type of proxy. If so, it should be introduced as a new definition.
Yes
We believe that generator data must be verified; however, the concept of staged tests is troubling as such testing can provide a local challenge to the integrity of the BES. Such testing should be required to be well coordinated with the Transmission Operator. Our experience shows start-up testing of new exciters has occasionally resulted in significant local impact to the transmission system, e.g., over-voltage on 345 kV systems.
No
 
No
It is the Transmission Operator and the Transmission Planner's task to determine if the model matches. The Generator Operator is uniquely unsuited to monitor transmission lines and determine if the model works. If the Transmission Planner's model doesn't properly reflect reality, the Transmission Planner should be required to meet with the Generator Operator and discuss the issue. The Generator Operator should then be required to reverify the data in question.
Yes
Providing minimal specificity allows many approaches to meet the requirements. This accommodates the many present and future excitation technologies and monitoring techniques.
No (disagree with approach)
We disagree with the approach. Some systems have very large peaking units which arguably are more likely to be in service on days when the BES would be challenged. Thus, modeling data should be collected for these units and model cases run including these data. Additionally, the requirement should only apply to peaking units which meet the applicability criteria (i.e. Capacity factor greater than 5% for the last 3 years and greater than the MVA indicated in 4.0)
 
Yes
We believe the MVA thresholds are appropriate and pick up the vast majority of interconnection (MVA).
No
 
No, the phase in period for unit excitation system verification should be (please specify below)
The phase-in period of 2 years is likely to be insufficient unless there are significantly more consultants available than we think there are, as many Generator Operators may need to hire a severely constricted resource.
N/A
N/A
It is our opinion that the SDT made a fundamental error in assigning the modeling to an entity that doesn't need the results of the model. To correct this error, this Standard needs very significant revision. As it stands, the Draft Standard imposes irrational requirements upon the Generator Operator.
Individual
Ben Johnson
Wisconsin Public Service
Yes
The Generator Owners, instead of Transmission Planners, are the logical entities to verify the proper functioning of the excitation system functions, but not the verifications of hypothetical parameter values of a model used to emulate the exciters' function. The generator Owners should, for example, verify that the AVR holds set terminal voltages under normal operating system conditions, as well as response to system changes in conformance with the stated Response Ratios as designed. This does not mean, however, that it would be necessary to confirm forward gains, transducer time constants, excitation saturation constants, feedback-loop gains and time constants, etc. are indeed of the same value as used in a hypothetical model. This is due to two reasons: 1) the particular model chosen by the transmission planner is known to be an approximation of the facilities' functions, and therefore the parameters are not unique; 2) instrumentations necessary for verification of specific parameters are not generally available in the industry.
Yes
 
No
The sister unit philosophy should be applied to identical units within a generator operators fleet with identical settings, but not be limited to the same physical site.
Yes
 
No
The model generally in use to simulate generator dynamic responses is a hypothetical model based on fictitious parameters. For instance, the direct-axis and quadratual-axis impedances are calculated design values, and not a measurable physical quantity, as are the transient and subtransient time constances. The inertial constance involve the whole rotor and prime-mover assembly, and cannot be easily quantified.
Yes
 
Yes
I agree with the methodology of the SDT to leave the test methods required under R4 out of the standard. It is a good philosophy to not limit future advancements in testing because the standard specifially calls for a step voltage test or UEL / OEL bumps. I think the SDT should consider this methodology in future drafts as applicable.
No (disagree with approach)
Threshold should be set around 20% to remove the requirements from those operators that may have a large fleet of small CT's that operate only in minimal peakng mode, but would qualify under the multiple units on the same site provision. These units have minimal impact on the dynamic model.
 
No, instead use the approach below:
The provisions of multiple generators at one location requiring testing of units above 20MVA rating puts too much ownerous on operators at CT sites with multiple small CT's that would act differently during an event and have minimal effect on the dynamic models.
Yes
Determined critical in the model or in a constrained area of the system.
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
At the Web-ex I thought the phase in was 10% per year with 100% by end of yr 11. This makes it sound like a different phase in will be used but no details on % at the 2, 6, and 11 year windows.
 
 
At plants with 200MW or higher capacity, it is unreasonable to assume multiple units of 20MW to malfunction simultaneously. Therefore, applying the standard to each unit of >/= 20MW if these are at the same contiguous plant of combined capacity of 200MW is placing unreasonable burden on owners of small generators. One must reason that, in the contest of the whole eastern interconnect, comprising a total capacity of 600,000MVA and higher, individual generators of less than 100MVA would not impact the system to any significant degree except for very localized regions.
Individual
Ronnie C. Hoeinghaus
City of Garland, Garland Power & Light - GOP Registered Entity
No
The Generator Owner (GO) should be responsible for model verification. The GO has direct access to the equipment - not the GOP. The GO can schedule any required operational testing with the GOP in the same way that the GO schedules any other operational testing requirement. In addition, the GOP and the GO can be two separate companies with their only relationship established by contract. In these situations this standard, as written, would place the burden on the GOP to try to renogoiate the contract with the GO to cover the expense and pursuade the GO to perform the model verification when the real responsibility belongs to the GO.
Yes
 
Yes
 
Yes
This same approach should be used for question #1. It is the Generator Owner (GO) that has this information and access to the equipment.
No
 
No
This should be the role of the Generator Owner (GO) - the GO has the data, the GO has the equipment, and the GO can schedule any required operational testing through the GOP.
Yes
 
Yes agree with the approach. But use another capacity factor (include supporting data):
Not sure which box to comment in: Strongly agree with your approach & reasons but believe that 10% should be the exemption level
Not sure which box to comment in: Strongly agree with your approach & reasons but believe that 10% should be the exemption level
 
 
Yes, agree with proposed phase in period for unit excitation system verification
Agree with both "Yes" statements - form will only allow one to be selected - if the 2 "Yes" statements are mutually exclusive, then I must not understand your statements & will go with the 1st "Yes"
 
 
 
Individual
Brendan Kirby
AWEA
Yes
 
Yes
 
Yes
 
Yes
 
No
 
Yes
 
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
No
There would have to be very clear technical justification for such a designation or it could be perceived as discriminatory and/or preferential
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
I agree with both the phase in period and allowing credit for units verified within the last 5 years via regional standards
 
 
 
Individual
Michael Goggin
American Wind Energy Association
No
Because Generator Operators typically do not have in-house expertise and would have to either hire consultants to perform model verification, or develop in-house expertise including acquiring simulation software, I think it makes more sense for Transmission Planners to perform this activity.
Yes
 
Yes
 
Yes
 
No
 
Yes
 
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
Yes
 
Yes, agree with proposed phase in period for unit excitation system verification
 
 
 
 
Group
Luminant Power
Rick Terrill
Generation Compliance
No
In ERCOT the Generation Owner should be responsible. This is a NERC Functional model issue, and I understand the GOP will be responsible in the majority of the country.
Yes
 
Yes
 
No
Luminant does not disagree that the information needs to be provided. However, the generator model data is already required in NERC Standards MOD-012 adn MOD-013 (R1.2). The Generation Owner should not be held doubly liable for the same informatin in two Standards. This requirement for the Generator data is already required elsewhere and is not needed in this standard.
No
 
Yes
 
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
No
The SDT is tasked with developing requirements for applicability across North America. Regions have the ability to develop more stringent requirements based on regional needs, and through various regional requirements development processes. Allowing the Transmission Planner or Planning Coordinator to expand the applicability of the NERC Standard on an individual resource basis (without industry input, balloting, etc.) would circumvent the FERC approved procedures for development of reliability standards.
Yes, agree with proposed phase in period for unit excitation system verification
Note that I also agree with allowing credit for verification of excitation systems within the last 5 years of the Standard's approval. The form would not let me select both yes answers.
Possible regional variance on applicability with GOP vs. GO in ERCOT.
NA
NA
Individual
James H. Sorrels, Jr.
American Electric Power
No
AEP believes that It would be more appropriate to designate the Generator Owner for these responsibilities.
No
AEP believes that the period should be longer. In fact, verification should only need to be done once on older units that do not now have good commissioning test documentation. Beyond that, it should only need to be done if there is an applicable equipment upgrade or an intentional readjustment of settings. We question predicating the periodicity on the expectation of a significant variation in equipment performance due to aging alone.
No
While AEP agrees that the proxy approach to verify multiple, identical units based on system model verification for a single unit makes sense, it is unclear why criterion "b" (the units are rated at less than or equal to 250MVA) would apply, provided criteria "a", "c", and "d" are also met. It is suggested that criterion "b" as listed in the Comment Form and as referenced in Requirement R1.2 be removed from the Standard.
Yes
 
Yes
Generator parameters are needed to support modeling. Later phases could pick-up unknowns identified by examining discrepancies between actual operation and modeling.
No
AEP does not agree that the Generator Operator should not be responsible to provide documentation that the system model matches the recorded response. That responsibility should lie with the Generator Owner to review and decide how to have that analysis performed and to what extent documentation will be prepared to provide the required verification.
Yes
We are agreeable since there are different kinds of excitation systems.
No (disagree with approach)
Seldom run units could end up being run at peak times in areas that may be stability limited. Applicability should be driven by need for verification which historically, has been tied to stability performance and constraints.
 
No, instead use the approach below:
The need for excitation data and model verification has been driven by plant and system stability needs. We believe that the applicability in the standard should be driven by the same. We would go so far as to suggest that identification of applicable units should be determined by the TP and PC through a process that includes planning study results and operating experience, and that the standard should not specify a blanket applicability unrelated to the stability driven need.
Yes
Criteria should be units or plants whose operation is limited by transient or small-signal instability, or that are located in areas that may be subject to stability constraints. Why not rather impose the applicability in the fashion of what is being asked here, that the TP and PC identify through a process which units should be verified, not a blanket applicability as is in the current draft.
No, instead of allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date, instead would recommend (please specify below)
that the areas with the greatest instability be addressed first.
No known need for regional variances
CONFLICT: The added expense posed by the requirements of this standard must be sought through tariff changes with applicable regulatory authorities. COMMENTS: A strong cost-benefit analysis is required to receive the necessary cost recovery.
(1) The added expense to fulfill the requirements of this standard where such model verification is not generally being done could be high. Since this is a new imposition on the industry in that required excitation model verification has never before been imposed in many areas, this leads to the question of cost versus reliability benefit of what is being proposed. We request that the SDT please comment more on the cost vs. reliability benefits. (2) With respect to R2, we suggest that it be revised and expanded as follows: "The Transmission Planner shall provide the Generator Operator a set of model data sheets for the acceptable excitation system models (models cannot be confidential or proprietary) for use in dynamic simulation software, with each data sheet including the excitation system model block diagram structure and data requirements and a system dynamics model, within 30 calendar days of a request from the Generator Operator." (3) With respect to R6, revise and expand the last sentence as follows: "If the TP determines the excitation system model is not useable, the TP shall provide the Generator Operator with a description of the problem and any relevant details, including the system dynamics case used in the evaluation." (4) With respect to last sentence in R9, revise and expand as follows, "…. after the receipt of a request that includes the measured data following a system disturbance and a suitable system dynamics case associated with the system disturbance.
Group
Southwest Power Pool Generation Working Group
Edmundo Toro
Southwest Power Pool
Yes
 
Yes
 
Yes
 
No
The proposed standard states Generator Operator, as opposed to Generator Owner. The Generator Owner should be the one providing the data.
No
 
No
It is understood and agreed that many differing types of units and testing exist. With that thought in mind, it is felt the standard needs to provide some guidelines of how to perform the test and what type of test results are to be reported.
No
It is understood and agreed that many differing types of units and testing exist. With that thought in mind, it is felt the standard needs to provide some guidelines on how to perform the test and what type of test results are to be reported.
Yes agree with approach and the 5% capacity factor
 
 
 
No
 
Yes, agree with proposed phase in period for unit excitation system verification
 
 
 
The SPP Generation Working Group members have several concerns related to this standard. The skill-set required to perform these tests do not currently exist among Generator Owners and there is a great concern that the limited subset of consultants that will be able to perform this verification will not be able to complete these tasks within the suggested ten year period. Given the limited subset of parties that will perform these tests, the cost will be onerous on the Generator Owners while not providing significant benefits. SPP Generation Working Group members do not know of any issue that these enhanced requirements would have helped avoid and therefore see little value, given the potentially high cost, to these expanded requirements. SPP Generation Working Group members generally oppose the current version of this standard.
Individual
Baj Agrawal
Arizona Public Service Co.
Yes
 
Yes
 
Yes
 
Yes
 
No
 
Yes
 
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
No
 
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
 
 
 
The standard appears to be too unnecessary complicated. We have the following suggestion for simplification. 1)Requirements R1, R4, R11 and R12 are the only reliability related requirements and should be kept. 2)R8 is part of providing data and should be a part of R4 3)All other requirements are simply indicate process and do not belong in the standard. They should be part of a white paper on the subject or in an appendix.
Group
Exelon Corporation
David Schooley
Exelon Corporation
No
Exelon believes that model verification should be a coordinated effort between the generator owner and the transmission planner. Transmission planning organizations have the expertise to implement and test the models in software, while the generator owners have the necessary access to the equipment in the field. Most generator owners do not have the software and the necessary personnel with the expertise to perform the modeling and model testing required by this standard.
Yes
It is difficult to determine whether or not 10 years is an appropriate period for re-verification without knowing the details of the required testing.
No
Why there is a limitation of unit size of 250MVA or less. The proxy unit approach should be extended to identical units of any size for a two unit station as half of the capacity at that station has been verified as compared to a multi unit site say having 6 250MVAs and verifying only one unit.
Yes
 
No
Verification of the generator data will be useful, but needs to be considered at a later date.
No
Exelon feels that the standard should define the acceptance criteria. If the acceptance criteria is left up to the generator owners, then the TOs may have to deal with multiple acceptance criteria within a single region. At the same time, a single generator owner may have to work with multiple TOs, which will lead to inconsistency if the definition of the acceptance criteria is left up to the TO.
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
Yes
Exelon is concerned about the use of the term "critical" in this context because it implies the same level of criticality that would be used to put a station on the critical asset list. A small generating station may be sufficiently close to another station that it affects the dynamic behavior of the generators at the second station. The Transmission Planner should be able to identify the units at the smaller station as applicable to the standard without calling them critical units. Exelon does appreciate the need for guidelines regarding the units that can be indentified as applicable to MOD-026.
Yes, agree with proposed phase in period for unit excitation system verification
 
 
 
The proposed standard and comment form presuppose the generator owners have the expertise necessary to model and simulate the excitiation systems on the units they own. They do not in most cases. Software requirements need to be considered. Not all transmission planners use the same software for dynamic simulations. A single generation owner may have units in multiple regions involving different transmission planners and would have to provide models for more than one simulation program. The standard needs to allow the Transmission Planner/Operator/Owner to provide expertise to the generator owner. The comment form and the WebEx meetings are more specific regarding software simulations than what is specified in the draft standard. The software simulations should be specified in more detail in the standard.
Individual
Dale Fredrickson
Wisconsin Electric
No
See response to Question 5. Providing model data and parameters is possible, but the requirement to validate the model for an actual switching event requires a cooperative effort between the GOP and the TP/TOP/TP. Since the stability and reliability of the overall transmission system is the goal, it is necessary for these entities to have more responsibility for proper excitation system modeling. As it stands this draft standard puts all the responsibility on the GOP.
Yes
 
No
We believe that units rated up to 850 MVA should be able to take advantage of this approach.
Yes
 
No
 
No
The requirements in R8 and R9 are not clear to us. The term "recorded response" needs to be defined, and the term "voltage excursion" needs to be quantified. These requirements infer that the GOP already has some documentation of what a "correct" response looks like, which is not the case. The requirement to validate the exciter model by monitoring its response to a real or staged event is not a simple matter. For a staged event such as switching a line, the TO or TOP will need to be actively involved in the process, and should have some responsibility assigned to it in the standard. Likewise, if an ambient switching event is used to validate the model, the TO/TOP would be the only entities in a position to know about it, since such operations may not be known by the GOP. In summary, this validation depends on shared responsibilities among the entities, and the requirements in this standard should properly reflect this.
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
No, instead use the approach below:
In light of the size and density of the Eastern Interconnection, we are of the opinion that the MVA threshold for units should be raised to 150 MVA or higher.
No
 
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
 
 
 
Please consider the use of offline measurement of generator excitation response as a possible means to comply.
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
No
The Generator Operator does not have direct access to the equipment. The Generator Owner is the correct Functional Model entity that has direct access to the equipment and the authority to perform testing of equipment. All responsibilities assigned to the Generator Operator in the proposed standard should be reassigned to the Generator Owner.
Yes
A ten-year interval is acceptable given the conditions in Requirement R12.
No
Unit testing has in the past identified different responses from identical units with common settings. All units with identical design and settings should be tested unless records of actual system events demonstrate that all of the units respond the same.
Yes
The entity specified in Question 4 does not agree with the entity specified in Requirement R4. As stated in our response to Question 1, we believe the Generator Owner is the correct entity to provide the data; not the Generator Operator. We agree with the approach subject to revising the responsible entity.
No
Expanding the scope to include verification of generator data will not provide a significant improvement in the overall modeling of excitation systems.
No
As stated in our response to Question 1, we believe that the Generator Owner is the correct entity to provide the data; not the Generator Operator. We agree with the approach subject to revising the responsible entity.
Yes
Reliability Standards should focus on what is required and not how to meet the requirement. Further, it would be impractical to specify verification details universally applicable to all situations. The peer review process provides appropriate safeguards to ensure that appropriate methods are used for verification.
Yes agree with approach and the 5% capacity factor
We agree with this approach to exclude units with low capacity factors provided that Planning Coordinators or Transmission Planners are allowed to identify additional applicable units beyond those specified in section 4.1.1 based on criticality to system reliability. Cases exist where large generating units with low capacity factors are operated only during the most stressed operating conditions. In such cases accurate modeling of these units may be critical to reliable operation of the bulk electric system.
 
Yes
We agree with the general approach to base the number and size of applicable generating units on the objective of validating models for 80 percent of the installed capacity on an Interconnection provided that Planning Coordinators or Transmission Planners are allowed to identify additional applicable units beyond those specified in section 4.1.1 based on criticality to system reliability. In the event the Planning Coordinator or Transmission Planner is not permitted to identify additional units, the objective should be changed to validate models for a greater percentage of the installed capacity. We do not have data to verify whether the unit size thresholds specified in Requirement R4.1.1 correspond to 80 percent of the installed capacity on an interconnection, and respectfully suggest that it is the responsibility of the SDT to provide such verification.
Yes
The Planning Coordinator or Transmission Planner should be permitted to identify additional units for applicability of the Standard based on the results of generator interconnection studies or other studies that demonstrate the criticality of correct settings on system reliability, e.g. studies demonstrating sensitivity of a stability based System Operating Limit to correct equipment settings and functionality.
No, the phase in period for unit excitation system verification should be (please specify below)
The proposed impmentation plan is too long. We recommend a five-year implementation with a requirement that units representing 20 percent of installed capacity be tested each year. We are concerned that an eleven-year implementation plan does not adequeately promote system reliability, and that having only three milestones will place a burden on system operators to schedule testing because Genator Owners may wait until years two, six, and eleven to schedule testing instead of spreading the tests out over the implementation period. The form will not accept more than one box checked above, but "Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard's approval date" should be checked.
None.
None.
No.
Group
Constellation Power Generation & Constellation Nuclear
Scott Etnoyer
Constellation Power Generation
Yes
 
Yes
 
Yes
The proxy unit approach is quite appropriate for excitation system verification for multiple units.
Yes
 
No
Expanding the scope to include verification of generator data will not provide any significant improvement in the modeling of excitation systems.
No
 
Yes
 
Yes agree with the approach. But use another capacity factor (include supporting data):
 
 
Yes
We agree with the general approach to base the number and size of applicable generating units on the objective of validating models for 80 percent of the installed capacity on an Interconnection provided that Planning Coordinators or Transmission Planners are allowed to identify additional applicable units beyond those specified in section 4.1.1 based on criticality to system reliability. In the event the Planning Coordinator or Transmission Planner is not permitted to identify additional units, the objective should be changed to validate models for a greater percentage of the installed capacity. We do not have data to verify whether the unit size thresholds specified in Requirement R4.1.1 correspond to 80 percent of the installed capacity on an interconnection, and respectfully suggest that it is the responsibility of the SDT to provide such verification.
Yes
The Planning Coordinator or Transmission Planner should be permitted to identify additional units for applicability of the Standard based on the results of generator interconnection studies or other studies that demonstrate the criticality of correct settings on system reliability, e.g. studies demonstrating sensitivity of a stability based System Operating Limit to correct equipment settings and functionality.
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
 
None.
None.
The standard needs to clarify what verification of excitation system model entails; does this involve testing of excitation parameters? Online or offline. On line testing of excitation parameters will present an unacceptable tripping risk to nuclear units. Recommend nuclear units be exempt from excitation system model verification if it involves online testing.
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
 
Yes
 
Yes
 
Yes
 
No
 
Yes
This should be done in consultation with planning/operating studies groups, since invariably these groups possess the necessary expertise and are in a better position to adjust/modify the model.
Yes
 
Yes agree with approach and the 5% capacity factor
Low capacity factor units such as wind turbines which could be part of a large MVA rated farm, should be in a separate category.
 
Yes
 
No
 
Yes, agree with proposed phase in period for unit excitation system verification
 
none
none
The MOD-026 Standard uses different terminiology in two different places. In requirement 4, the fourth bullet uses the term Reactive compensation and in Requirement 12, the fourth bullet uses impedance compensator. Either term is fine to use, but should be consistent throughout the standard.
Individual
D. Bryan Guy
Progress Energy, Inc.
No
The Generator Owner is the correct entity for this responsibility. It must be the entity that would be the most able to obtain the attention of the manufacuturer and have the means to accomplish the validation. The entity must have the financial incentives to perform the function and must be knowledgable about the plant operation. The entitiy that would be the best source to coordinate the testing could be required to verify the models. In our opinion the functional model specifies Generator Owner as it requires a generator owner to "verify generating facility performance characteristics". For the foregoing reasons this responsibility should not be assigned to the Transmission Planner.
Yes
As long as there is a requirement such as R11. The second bullet of R11 might also note that the Generation Operator must verify for the model for the first time if the model was derived from a 'sister' unit or repeat the verification on one previously verified. Despite R12, some communication between the Generation Operator and the Transmission Operator within the 10 year period would be reassuring that nothing has changed. Because ten years is a long time, the Generator Owner should be required to respond upon request of the Transmission Planner confirming that nothing has changed.
No
We encourage the proxy unit approach. However, we do not agree completely to the conditions illustrating proxy unit approach. (1) MVA rating should be expanded to say "MVA nameplate rating" . We believe it would be prudent to specify that units of different manuafacturers, even if they have the same nameplate rating are not proxy units, (2) If the units are identical, we believe the 250 MVA threshold criterion is too restrictive. We believe the limit should be at least 350 MVA to cover combined cycle units of existing technology.
Yes
Since the exciter model and the generator model are components of the closed loop system being verified, the process must ensure that the Transmission Planners dynamic database is updated with the generator data and the excitation system data utilized for verification. Relying on generator data that was originally provided for MOD-012 to be the same data that was used for model verification would not be advisable. There are countless opportunties for generator data submitted for MOD-012 to be inconsistent with generator data used in models in the excitation system verification process. In order to close this loop, we suggest that R3 be slightly modified to read: "The Transmission Planner shall provide the Generator Operator the unit specific data contained in the Transmission Planner’s dynamic database from the current in-use excitation system and generator model, including the applicable generator model parameter's MVA base, within 30 calendar days of a request from the Generator Operator." AND R4 Item 2 should have an additional sentence at the end which reads: "This data only has to be provided in those instances where generator model data was changed in order to obtain a verified excitation system model". These language modifications ensure that dynamic databases are populated with the correct data for both the excitation system and generator models that have been verified while minimizing burden on the generation entity responsible for model verification.
No
To include generator data verfication beyond excitation system modeling data is a significant burden to the Generation Owner not supported by the benefits to be gained.
Yes
The functional model entity responsible for the model's verification has to be given the responsibility of demonstrating that the provided model's response matches the recorded response. The "goodness of fit" between the model response and the equipment response should be left to the generator owner but subject to Transmission Planner review ref. R10.
Yes
We agree with the SDT approach of not developing this standard like a technology specific procedural manual. The development of verification Requirements stating "what is required" and leaving the technical details up to the personnel performing the verification will result in improved dynamic models while affording sufficient technical latitude.
No (disagree with approach)
The 5% capacity factor is an inappropriate basis for an exemption since it would allow significant blocks of generation (i.e. plants of several hundred MW) to be exempt. Such amounts of generation may have a significant impact on the stability of nearby generating units or such units may themselves have stability issues that need to be understood via valid studies. Examples would be plants with multiple combustion turbine units (particularly simple cycle oil burners) that are rarely run. However, when they are run (i.e. during peak system load times), the grid may be already be stressed and operating with reduced stability margin. The possibility also exists that while the exempted generation may have a capacity factor of less than 5%, this could quickly change due to unanticipated system conditions or the extended unavailability of other generation (due to severe damage for example). Therefore, the subject generating units could end up being run for a significant length of time without the benefit of having been properly analyzed by the Transmission Planning organization. The “average over the last three calendar years” methodology further contributes to this possibility, introducing a time lag in the process. Based on the above discussion, the 5% capacity factor exemption should only be allowed when it would not be expected to significantly impact the results of stability studies. Allowing the Transmission Planner to make this judgement is most appropriate since A) that organization is in the best position to make the determination of the impact on stability and B) that organization is responsible (via TPL standards) for ensuring the stability of the grid and connected generating units. In lieu of the blanket 5% exemption, the following is proposed. 1. Delete “… and with an average Capacity Factor of greater than 5% over the last three calendar years” in all places in 4.1.1.1, 4.1.1.2 and 4.1.1.3 2. Add new Applicabilty 4.1.1.4 stating “Generating facilities with capacity factors less than 5% over the last three calendar years may be exempted with written concurrence from the applicable Transmission Planning Authority. The written concurrence provided by the Transmission Planning Authority shall include the basis for any such exemptions.” alternative to (2.) could be the reponse to Q9 below.
 
Yes
However, the MVA values MUST be coordinated with the MVA thresholds in MOD-010 to 012 and in proposed TPL-001 standards. Supporting data (circa 2003) can be found from the link below which provides a spread sheet titled “Existing Generating Units in the United States by State, Company and Plant, 2003.” http://www.eia.doe.gov/cneaf/electricity/page/at_a_glance/gu_tabs.html
Yes
Add to Applicability a 4.1.1.4 stating “Generating facilities that do not meet the applicability requirements 4.1.1.1 - .3 may be included when their performance is found to create or contribute to reduced reliability of the BES when requested by the applicable Transmission Planning Authority. The written request provided by the Transmission Planning Authority shall include the technical basis for any such inclusion (e.g. must run for reliability, voltage, or stability needs).”
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
The first time period should be 3 years (10%). It is anticipated that the first units will take significantly longer than subsequent testing. Although this factor is already being considered in proposed time periods, there will probably be a significant shortage of testing services at the beginning of the testing window.
No.
No.
Requirement 1 Item 1) should be clarified to state that "new equipment commissioning date" applies to modifications of existing units. Requirement numbering for R1, R4, R5, R7-12 needs to be revised to conform to proper format.
Individual
Greg Mason
Dynegy
No
The Generator Owner does not need or use an excitation system model. The Transmission Planner is the entity that uses and needs this model to be accurate. The Generator Owner should be responsible for collecting and providing the generator related input data forthe model to the Transmission Planner. The Transmission Planner should be responsible for running the simulations required for model verification and making the judgement if the model's response matches the actual response.
Yes
 
Yes
 
Yes
 
No
 
No
See response to Item #1.
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
We support SDT's approach to include aggregate MVA values. We also would like to suggest minor wording changes for SDT consideration to revise the language in the draft standard to better reflect an aggregate MVA approach. The word "same" is added to draft standard language as following: " Each unit ( including synchronous generators) => 100 MVA, connected at the SAME point of interconnection at 100 Kv or above and with an ……".
No
 
No, the phase in period for unit excitation system verification should be (please specify below)
If the Generator Owner is assigned the responsibility for model verification, there will not be enough consultants to handle the resulting workload placed on Generator Owners.
None at this time.
None at this time.
None at this time.
Individual
Rick White
Northeast Utilities
No
The Generator Owner is the correct Functional Model entity that has direct access to the equipment and the authority to perform testing of equipment. All responsibilities assigned to the Generator Operator in the proposed standard should be reassigned to the Generator Owner.
Yes
Consider the need to account for wind turbine generation that does not have mature models for this verification - therefore a shorter period may apply to accommodate improvements of those models.
No
Units testing has in the past identified different responses from identical units with common settings. All units with identical design and settings should be tested unless records of actual system events demonstrate that all of the units respond the same.
Yes
The entity specified in Question 4 does not agree with the entity specified in Requirement R4. As stated in our response to Question 1, we believe the Generator Owner is the correct entity to provide the data; not the Generator Operator. We agree with the approach subject to revising the responsible entity.
Yes
Consider model verification for rotational inertia, which can have a significant effect on modelling.
No
As stated in our response to Question 1, we believe that the Generator Owner is the correct entity to provide the data; not the Generator Operator. We agree with the approach subject to revising the responsible entity. Agree that peer review by TP/PC is important for verifying the match.
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
Yes
 
No, the phase in period for unit excitation system verification should be (please specify below)
We recommend a five or ten-year implementation with a requirement that units representing 20 or 10 percent, respectively, of installed capacity be tested each year. We are concerned that having only three milestones will place a burden on system operators to schedule testing because Genator Owners may wait until years two, six, and eleven to schedule testing instead of spreading the tests out over the implementation period.
 
 
 
Group
SERC Dynamics Review Subcommittee (DRS)
Rick Foster
Ameren Services
No
The Generator Owner is the correct entity for this responsibility. It should be the entity that would be able to obtain the attention of the manufacuturer and have the means to accomplish the validation. The entity should have the financial incentives to perform the function and should be knowledgable about the plant operation. The entitiy that would be the best resource to coordinate the testing should be required to verify the models. In our opinion the functional model specifies the Generator Owner as it requires a generator owner to "verify generating facility performance characteristics". For the foregoing reasons this responsibility should not be assigned to the Transmission Planner.
Yes
We agree as long as there is a requirement such as R11. The second bullet of R11 might also note that the Generation Operator (Owner) must verify the model for the first time if the model was derived from a 'sister' unit or repeat the verification on one previously verified. Despite R12, some communication between the Generation Operator (Owner) and the Transmission Operator, within the 10 year period stating that nothing has changed would be reassuring. Because 10 years is a long time, the Generator Owner should be required to respond if requested by the Transmission Planner confirming that nothing has changed.
No
We encourage the proxy unit approach. However, we do not agree completely to the conditions illustrating the proxy unit approach. (1) "MVA rating" should be changed to say "MVA nameplate rating". We believe it would be prudent to specify that units of different manuafacturers are not proxy units, even if they have the same nameplate rating, (2) If the units are identical, we believe the 250 MVA threshold criterion is too restrictive. We believe the threshold should be at least 350 MVA to cover combined cycle units using existing technology.
Yes
Since the exciter model and the generator model are components of the closed loop system being verified, the process should ensure that the transmission planners dynamic database is updated with the generator data and the excitation system data utilized for model verification. Relying on generator data that was originally provided for MOD-012 to be the same data that was used for model verification would not be advisable. There are countless opportunties for generator data submitted for MOD-012 to be inconsistent with generator data used in the excitation system verification process. In order to close this loop, we suggest that R3 be slightly modified to read: "The Transmission Planner shall provide the Generator Operator with the unit-specific data contained in the Transmission Planner’s dynamic database from the current in-use excitation system and generator model, including the applicable generator model parameter's MVA base, within 30 calendar days of a request from the Generator Operator." AND R4 Item 2 should have an additional sentence at the end which reads: "This data only has to be provided in those instances where generator model data was changed in order to obtain a verified excitation system model". These language modifications will help ensure that dynamic databases are populated with the correct data for both the excitation system and generator models that have been verified while minimizing burden on the generation entity responsible for model verification.
No
 
Yes
The entity responsible for the model's verification has to be given the responsibility of demonstrating that the model's response matches the recorded response. The "goodness of fit" between the model response and the recorded response should be left to the generator owner but subject to Transmission Planner review ref. R10.
Yes
We agree with the SDT approach of not writing this standard like a technology specific procedural manual. The development of verification Requirements stating "what is required" and leaving the technical details up to the personnel performing the verification will result in improved dynamic models while affording sufficient technical latitude.
No (disagree with approach)
The 5% capacity factor is an inappropriate basis for an exemption criteria since it would allow significant blocks of generation (i.e. plants of several hundred MW) to be exempt. Units in this class of generation may have a significant impact on the stability of nearby generating units or may have stability issues that need to be understood via valid studies. Examples would be plants with multiple combustion turbine units (particularly simple cycle oil burners) that are rarely generating. However, when they are generating (i.e. during peak system load times), the grid may be already be stressed and operating with a reduced stability margin. The possibility also exists that while the exempted generation may have a historical capacity factor of less than 5%, this could quickly change due to unanticipated system conditions or the extended unavailability of other generation (due to severe damage for example). Therefore, the subject generating units could generate for a significant length of time without the benefit of having been properly analyzed by the Transmission Planning organization. The “average over the last three calendar years” methodology further contributes to this possibility, introducing a time lag in the process.
Based on the above discussion, the 5% capacity factor exemption should only be allowed when it would significantly impact the results of stability studies. Allowing the Transmission Planner to make this judgement is most appropriate since A) this entity is in the best position to make the determination of the impact on stability and B) this entity is responsible (via TPL standards) for ensuring the stability of the grid and connected generating units. In lieu of the blanket 5% exemption, the following is proposed. 1. Delete “… and with an average Capacity Factor of greater than 5% over the last three calendar years” in all places in 4.1.1.1, 4.1.1.2 and 4.1.1.3 2. Add a new section under Applicabilty 4.1.1.4 stating “Generating facilities with capacity factors less than 5% over the last three calendar years may be exempted with written concurrence from the applicable Transmission Planning Authority. The written concurrence provided by the Transmission Planning Authority shall include the basis for any such exemptions.” alternative to (2.) could be the reponse to Q9 below.
Yes
The MVA values should be coordinated with the MVA thresholds in MOD-10 to MOD-12 and in proposed TPL-001 standards. Supporting data (circa 2003) can be found from the link below which provides a spreadsheet titled “Existing Generating Units in the United States by State, Company and Plant, 2003.” http://www.eia.doe.gov/cneaf/electricity/page/at_a_glance/gu_tabs.html This spreadsheet can be sorted and summed to get an estimate of the percentage generation that would be included. A preliminary look by the DRS suggests that 80% or more would be included.
No
Add a new section under Applicability 4.1.1.5 stating “Generating facilities that do not meet the applicability requirements of 4.1.1.1 - .4 may be included when their performance is found to reduce the reliability of the BES by the applicable Transmission Planning Authority. A written request provided by the Transmission Planning Authority shall include the technical basis for any such inclusion (e.g. must run, reliability, voltage, or stability needs).”
No, the phase in period for unit excitation system verification should be (please specify below)
The first time period should be 3 years (10%). It is anticipated that testing of the first units will take significantly longer than subsequent testing. Although this factor may have been considered in the proposed time periods, other factors such as the potential shortage of testing services at the beginning of the testing window may not have been considered.
 
 
Requirement 1 says testing should occur "for new or existing units within 180 days of commerical operation". We believe the testing should be done before commerical operation.
Group
Dominion
Jalal Babik
Dominion Resources Services, Inc.
No
In general, there should be collaborations between the Generator Owner, Transmission Planner, Generator Operator, and Transmission Operator to meet the intent of model and data verification. However, the requirements of this standard should apply to the Generator Owner and the Transmission Planner. We have reviewed the NERC Functional Model and believe that the Generation Owner should be responsible for those requirements assigned to the Generator Operator in this draft standard. We are concerned that Generator Owners may have to acquire outside sources or develop in-house skills in order to meet the requirements of this standard. However, we feel that the proposed effective date(s) allows adequate time to address these concerns.
Yes
 
Yes
 
Yes
We believe that all requirements of this standard should apply to the Generator Owner, not the Generator Operator.
No
MOD-024 and MOD-025 address a generator's real and reactive capability verification and MOD-026 addresses the excitation system verification. It seems desirable to have a MOD standard that address the verification of generator data by the Generator Owner (not the Generator Operator). This can be handled by a new SAR since the scope change of the current SAR could delay the process. In scoping the verification of the generator dynamic data: a) If the existing generator dynamic model data is backed by documentation provided by the generator manufacturer or previous test(however old it is), no verification would be required. b) If there is no documentation (from manufacturer or previous test) supporting the existing generator dynamic model data, saturation, inertia & D-axis parameters (time constants and impedances) have to be verified at the minimum. If the measured D-axis parameters show reasonable agreement with the existing generator dynamic data, it is not required to verify the Q-axis parameters; otherwise the Q-axis parameters need to be verified as well.
Yes
 
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
The proposed threshold captures at least 80.5% of the generators owned by Dominion.
Yes
If a unit exhibits transient or dynamic instability for an event but the simulation did not show the same then the excitation system shall be tested for units beyond those specified section 4.1.1.
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
 
SERC - supplement requires members to validate the excitation system model parameters of their generating units within 7 years (dated 2007). MRO –draft guideline in field test, not currently in effect.
 
The SDT should define exactly what the "excitation model" means. At a minimum it should include the AVR, exciter, PSS (if installed) and voltage compensator (if installed). The current document appears to imply that the minimum and maximum excitation limiters (if installed) are not part of the "excitation model." 2. We are concerned that, in order to meet this standard, applicable entities may have to share data and software that may be proprietary and which may vary depending upon vendor(s) selected by the Transmission Planner. R2 states that “models cannot be confidential or proprietary”. 3. We believe that applicabilty section should be modified so that it only includes entity(ies) defined in the NERC Functional Model. At 4.1.1 it states “Generator Operators of generating facilities:” We believe it should state Generator Owner (the term used in functional model). a. We can support 4.1.1.1 if the language is revised to read “With generators that are connected to Eastern or Quebec Interconnections with the following characteristics……………” 4. The requirement R2 should be restated to read: The Transmission Planner shall provide the Generator Owner a set of model data sheets for the standard (as opposed to acceptable)excitation system models for use in dynamic simulation software, with each data sheet including the excitation system model block diagram structure and data requirements, within 30 calendar days of a request from the Generator Owner. If the excitation system characteristic is such that it cannot be represented by one of the Standard models, the Generator Owner shall be obligated to have a user-written model developed and made it available to Transmission Planner for use in the dynamic simulation software used by the Transmission Planner.
Individual
Tom Bradish
Reliant Energy
Yes
Unit operation not unit ownership impacts the reliability of the grid.
No
The period for re-verification should be based on observed performance, by activities that could result in an alteration of equipment performance or as listed in Requirement R11 which could trigger a review includes Plant Digital Control System (DCS) additions, replacements, or software alterations. Plant DCS activities would only be relevant to excitation system modifications if they involved the addition, deletion, or modification of an outer loop control (such as power factor or reactive power set point) that alters automatic voltage regulator action. If it ain't broke don't fix it!
Yes
I can not see any reliability benefit to requiring the verification of sister units.
Yes
But to be consistant I think it should be the GOP not the GO.
No
 
No
It should be the TP working with the GOP.
Yes
I susgest that the SDT consider a white paper expounding how the verification can be performed.
Yes agree with approach and the 5% capacity factor
 
 
Yes
The SDT at least has done an engineering analysis in developing the MVA thresholds. I am not sure that registration criteria was done in the same manner.
Yes
Units that have an RMR. If they do not have an RMR (in unorganized markets) then how can they be called critical?
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
 
 
 
 
Individual
Patrick Farrell
Southern California Edison
Yes
 
Yes
 
Yes
 
Yes
 
No
 
Yes
 
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
No
 
Yes, agree with proposed phase in period for unit excitation system verification
 
 
 
 
Group
Southern Company
Hugh Francis
Southern Company Services, Inc.
No
The Generator Owner appears to be the logical choice. GO has the access to the equipment records, GOP may not.
Yes
Years of operating experience has shown that existing excitation systems that are properly maintained typically do not deteriorate to the point where performance is noticeably impacted in less than 10 years.
No
Agree with all requirements except b and d. If the GO/GOP has duplicate units at multiple sites , a re-verification test of one unit should apply to all provided they meet items a and c. The size of the unit (b) nor the physical location (d) do not matter. The MVA rating of the machine should not be an excluding factor for units of the same vintage, rating, manufacturer, and with the same type of excitation system and settings.
No
Since the exciter model and the generator model are components of the closed loop system being verified, the process should ensure that the transmission planners dynamic database is updated with the generator data and the excitation system data utilized for model verification. Relying on generator data that was originally provided for MOD-012 to be the same data that was used for model verification would not be advisable. There are countless opportunities for generator data submitted for MOD-012 to be inconsistent with generator data used in the excitation system verification process. In order to close this loop, we suggest that R3 be slightly modified to read: "The Transmission Planner shall provide the Generator Operator with the unit specific data contained in the Transmission Planner’s dynamic database from the current in-use excitation system and generator model, including the applicable generator model parameter's MVA base, within 30 calendar days of a request from the Generator Operator." AND R4 Item 2 should have an additional sentence at the end which reads: "This data only has to be provided in those instances where generator model data was updated during the process of obtaining a verified excitation system model". These language modifications will help ensure that dynamic databases are populated with the correct data for both the excitation system and generator models that have been verified while minimizing burden on the generation entity responsible for model verification.
No
As a general rule the industry has not demonstrated a need to validate OEM supplied generator data.
Yes
 
Yes
 
Yes agree with approach and the 5% capacity factor
 
The idea that this standard should not be applicable to low capacity factor seems perferable. However, 5% capacity factor may be too high. For instance, there are 8760 hours in a year. A 5 % capacity factor could mean a unit running its at nameplate MW for 438 hours. Or, it could mean more than 438 hours if the unit is not running at its nameplate all the time when running. For Southern Company Generation, the current criteria would result in the standard applying to at least 80% of our generation capacity.
Yes
See comment on 7 above.
No
 
Yes, agree with proposed phase in period for unit excitation system verification
We agree with both Yes statements above. The software will only allow one to be marked.
 
 
Paragraph 4.1.1.1 3rd Section: The plant criteria should be assessed on a switchyard basis instead of all inclusive. For example: 5 unit station with 4 units > 100 MVA each connected at 500 kV and one unit <50 MVA connected at 115 kV. Why do I need to do the small unit? Paragraph R1.2: See discussion in question 3 above regarding the criterion of 'sited at the same physical location and MVA ratings.' We see no need for these restrictions. Paragraph R7: A third option is to do more testing/technical assessment with a longer time allowed (>90 days) should be included. Paragraph R8: The last part of this requirement is unclear: '….within 90 calender days …. verification.' Change the wording from 90 calendar days of competion to 90 calendar days after completion. The requirement will than read, " The Generator Operator shall provide to the Transmission Planner documentation demonstrating that the excitation's system model's response matches the recorded response for a voltage excursion at the generator from either a staged test or a measured system disturbance (i.e., an ambient event) within 90 calendar days after completion of the excitation system model verification." Paragraph R12: The second and third bullets should be combined to cover any DCS/AVR inter-actions.
Individual
Scott Berry
Indiana Municipal Power Agency
Yes
IMPA recognizes that the Generator Operator can work with the Transmission Planner when it comes to using the verified data in a proper model or simulation software program. This assistance from the Transmission Planner might mean that the Generator Operator does not need to purchase modeling software.
Yes
 
Yes
 
No
IMPA believes the generator data is important and that it is currently being provided per MOD-010 (static) and MOD-012 (dynamic). Another standard requiring this information would put the stakeholder at a double risk factor, and FERC does not believe in this double risk factor.
No
 
Yes
 
Yes
 
Yes agree with approach and the 5% capacity factor
 
A small utility owns a GE 7EA Turbine/Generator with a nameplate rating of 101 MVA in the Eastern Interconnection. The utility uses it as a peaking unit and the capacity factor for the unit averages less than five percent over the last three years. Obviously, this unit does not play a vitale role in maintaining the reliability of the BES. Therefore, why make this utility spend thousands of dollars on testing a machine that is not important to reliability. By using a capacity factor of 5%, this unit will be exempt from this standard.
Yes
 
No
 
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
IMPA is concerned about the implementation plan. The 10 percent in two years seems feasible, but what if companies decide to test all their units to save on travel cost of a contractor. Has the SDT looked at the total number of units that are covered by this standard and how many contractors can do this work? For example, if a company owns five or more peaking units in one location or in close proximity, they may decide to test all their units at the same time and pay for only one trip by the contractor. Then the next Generator Operator does the same with its units and this continues to occur throughout the two year time period. This type of mentality may hurt the Generator Operator who owns only one unit and has to wait on an available contractor to perform the test. If the Generator Operator does not get that one unit tested within the first two years, it will be non-compliant with this standard (the Generator Operator only owns one unit that this standard applies).
 
 
 
Group
Kansas City Power & Light
Don Brown
Kansas City Power & Light
Yes
 
No
The Electric Power Research Institute has issued a report, "Power Plant Modeling and Parameter Derivation for Power System Studies", number 1015241, Final Report, June 2007; a reasonable interpretation of that work is that there may not be sufficient benefits from using a highly complex model to overcome the potential risks of the testing needed to verify the most complex models. Prototype test data obtained by manufacturers to provide the initial data, in many cases, simply can not be duplicated on operating / operational equipment. The 10 year re-verification requirement, as presently written, does not appear to allow generator owners the necessary flexibility to determine, similar to the regulatory model of 10 CFR 50.59 "Changes, Tests, and Experiments", how detailed the "re-verification" activities need to be. The requirement to re-perform the same bank of physical tests used to originally validate the generator model, absent a physical modification, does not allow sufficient flexibility to perform only those "re-verification" activities for those model parameters whose change due equipment aging has discernable effect on the outcome of the analysis using the generator model. Please note that the concern for performance of tests with little discernable analytical benefit was previously voiced in the "MAAC Position Paper on Generator Testing to Verify Data Required for System Modeling" in the Phase III-IV Planning Standards comments, which can be found on the NERC www site, where the issue of testing nuclear units in compliance with the regulatory requirements of 10 CFR 50.59 was also noted. As a result, it is recommended the SDT consider removing all references in the requirements for periodic testing when no physical changes have taken place and clarify R12 reflects to reverify the parts of the modeling affected by a change and not a reverification of the entire model. In addition, although the reason to verify generator modeling is logical, it is requested the SDT consider the references stated above and consider the removal or modification of requirements involving testing that place an unncessary risk of generator damage. As an example, allowing vendor simulations or other testing methods by the Vendor in a suitable testing environment to suffice for obtaining generator response characteristics.
Yes
 
Yes
 
No
There are clearly benefits to having as much verified operational characteristic data as possible, however, as previously noted in response to question #2, the equipment risks associated with obtaining those benefits should be a consideration. Considering an aging generation infrastructure, the risk of obtaining parts for equipment damaged in the pursuit of modeling verification can be extremely costly in extended downtime and the availability of parts is also a concern. Again, it is recommended the SDT consider the removal or modification of requirements involving testing that place an unncessary risk of generator damage. As an example, allowing vendor simulations or other testing methods by the generator Vendor in a suitable testing environment to suffice for obtaining generator response characteristics.
Yes
 
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
Yes
 
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
 
Not aware of any regional differences.
Not aware of any conflicts.
Where specific codes and standards are referenced as either the technical basis for, or an acceptable means to comply with the NERC requirements, such as IEEE 421 referenced directly in Draft 1 of MOD-026-1, or IEEE 1110 and IEEE 415, please clarify these are references only and the content of these references in no way add to the requirements proposed here.
Individual
Kathleen Goodman
ISO New England Inc.
No
The Generator Operator has the greatest ability to develop and/or provide accurate models and model parameters for its equipment. The Generator Owner should also be involved in the verification process as required. The process should ideally allow interations between the GO and TO to allow for needed adjustments to model compatability issues and settings with the GO, It should be field verified data not just a self certification of data without the field verification.
No
We recommend validation on a 5 year scale. 10 years is too long if changes are made to settings during annual outages. The whole approach of the draft standard is a bit flawed because once the model and tuned parameters are verified, no control setting changes should be made to the physical equipment without consulting with the TO to determine their acceptability. Additionally, updates should be provided if the manufacturer or GO identify improvements to the model in regard to matching the actual equipment. Having a verification in addition to the preceding is acceptable and would provide the benefit of having a written documentation from the GO and better assure that acccurate models are being used for planning the system.
Yes
 
Yes
 
No
Manufacturer's estimates of generator characteristics appear to be generally accuracte and relatively easy to obtain.
No
The generator should provide the data to Reliability Coordinators, Transmission Operators and Planning Coordinators for verification. Generator Owners should provide factory models for excitation systems to Reliability Coordinators, Transmission Operators and Planning Coordinators and these models should be verified with the field data.
No
This may lead to "weak" submittals from certain entities.
No (disagree with approach)
These low capacity factor units may be critical during peak conditions and are almost certain to be older units that have the least accurate factory excitation system models. It is felt that having accurate models for these older units is required. Generators under 100 MVA make up about 15% of capacity in New England. Excluding low capacity factor large units may exclude more than 20% of the generators from model verification.
 
Yes
Currently generators over 100 MVA make up about 85% of the installed generator capacity in New England. Concentration on these units should provide an accurate representation of the system. Efforts to verify lower MVA capacity units would provide limited benefit for the work involved.
 
No, the phase in period for unit excitation system verification should be (please specify below)
2-1/2 years with a 5 year overall renewal of verification.
 
 
 
Group
MRO NERC Standards Review Subcommittee
Michael Brytowski
MRO
No
To help differentiate the BES model from the unit specific excitation system model. The MRO NSRS suggests a change in R1 to read; "The Generator Operator shall verify their applicable excitation control system model…"
Yes
 
Yes
 
Yes
 
No
 
Yes
 
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
No
 
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
 
No
No
 
Individual
Kirit Shah
Ameren
No
(1)Generator Operators and Generator Owners both should be included in this standard. The entitiy that would be the best source to coordinate the testing could be required to verify the models. It is possible that all functions can not be performed by the Generator Operator alone. Therefore it would be prudent to include the Generator Owners within MOD-026-1. (2) Additionally, the GO would be able to obtain the attention of the manufacuturer than GOP. In our opinion the functional model specifies Generator Owner as it requires a generator owner to "verify generating facility performance characteristics". In any case, this responsibility should not be assigned to the Transmission Planner. (3) On the other hand, GO/GOP should not perform the function of modeling or verifying dynamic simulations on the Bulk Electric System which generally is done by Transmission Planners. Generator Operators/Generator Owners should provide the data needed for model simulation. Generator Operators/Generator Owners do not possess the expertise or have the resources to perform modeling simulations.
No
(1) Many generating units are now on six year outage cycles, therefore we recommend the interval is changed to 12 years or more. (2) Concerns regarding excitation equipment are that someone at the plant may inadvertently modify settings on dials/potentiometers at some point within a 10/12 year period (or other interval that would be considered appropriate) that would cause the performance of the exciter to vary from what was originally specified in the dynamic model representation. Also, it is possible that, through aging, electrical values of circuit components in the excitation equipment could drift, even with no external change to the settings. It is uncertain what the re-verification period should be to minimize these effects, so we support the caveats listed in Requirement 11 and 12. However, despite R12, some communication between the Generation Operator and the Transmission Operator within the 10/12 year period would be reassuring that nothing has changed. Because 10/12 years is a long time, the Generator Owner should be required to respond upon request of the Transmission Planner confirming that nothing has changed. Further, the second bullet of R11 might also note that the Generation Operator must verify for the model for the first time if the model was derived from a 'sister' unit or repeat the verification on one previously verified.
Yes
We encourage the proxy unit approach. However, we do not agree completely to the conditions illustrating proxy unit approach. (1) MVA rating should be expanded to say "MVA nameplate rating" . We believe it would be prudent to specify that units of different manuafacturers, even if they have the same nameplate rating are not proxy units. Further, turbine rating should also be considered as appropriate. (2) If the units are identical, we believe the 250 MVA threshold criterion is too restrictive. We believe the limit should be at least 350 MVA to cover combined cycle units of existing technology.
Yes
(1) Generator Operators and Generator Owners should be included in this standard. It is possible that all functions can not be performed by the Generator Operator. Therefore it would be prudent to include the Generator Owners within MOD-026-1. (2) If the generator has not been modified, and the manufacturer's data is available, then there should be no need for retesting of the generator. However, if the generator has been modified since the last data set was established for the generator, (stator or rotor turns shorted, rotor replaced, etc.) then re-testing of the generator would be in order. If the turbine has been replaced, then an updated value for rotational inertia would be needed. (3) The concept of staged tests is troubling as such testing can provide a local challenge to the integrity of the BES. Such testing should be required to be well coordinated with the Transmission Operator. (4) Relying on generator data that was originally provided for MOD-012 to be the same data that was used for model verification would not be advisable. There are countless opportunties for generator data submitted for MOD-012 to be inconsistent with generator data used in models in the excitation system verification process. In order to close this loop, we suggest that R3 be slightly modified to read: "The Transmission Planner shall provide the Generator Operator the unit specific data contained in the Transmission Planner’s dynamic database from the current in-use excitation system and generator model, including the applicable generator model parameter's MVA base, within 30 calendar days of a request from the Generator Operator." AND R4 Item 2 should have an additional sentence at the end which reads: "This data only has to be provided in those instances where generator model data was changed in order to obtain a verified excitation system model". These language modifications ensure that dynamic databases are populated with the correct data for both the excitation system and generator models that have been verified while minimizing burden on the generation entity responsible for model verification.
No
None
No
(1) Generator Operators and Generator Owners should be included in this standard. It is possible that all functions can not be performed by the Generator Operator. Therefore it would be prudent to include the Generator Owners within MOD-026-1. The Generator Operator or Generator Owner should verify the model but should not be responsible for the model. (2) No issues with peer-to peer review, as this would help drive what are necessary and sufficient conditions for matching the responses. (3) The functional model entity responsible for the model's verification has to be given the responsibility of demonstrating that the provided model's response matches the recorded response. The "goodness of fit" between the model response and the equipment response should be left to the generator owner but subject to Transmission Planner review ref. R10.
Yes
We agree with the SDT approach of not developing this standard like a technology specific procedural manual. The development of verification Requirements stating "what is required" and leaving the technical details up to the personnel performing the verification will result in improved dynamic models while affording sufficient technical latitude.
No (disagree with approach)
(1) Some systems have very large peaking units which arguably are more likely to be in service on days when the BES would be challenged. Thus, modeling data should be collected for these units and model cases run including these data. (2) The 5% capacity factor is an inappropriate basis for an exemption since it would allow significant blocks of generation (i.e. plants of several hundred MW) to be exempt. Such amounts of generation may have a significant impact on the stability of nearby generating units or such units may themselves have stability issues that need to be understood via valid studies. Examples would be plants with multiple combustion turbine units (particularly simple cycle oil burners) that are rarely run. However, when they are run (i.e. during peak system load times), the grid may be already be stressed and operating with reduced stability margin. (3) The possibility also exists that while the exempted generation may have a capacity factor of less than 5%, this could quickly change due to unanticipated system conditions or the extended unavailability of other generation (due to severe damage for example). Therefore, the subject generating units could end up being run for a significant length of time without the benefit of having been properly analyzed by the Transmission Planning organization. The “average over the last three calendar years” methodology further contributes to this possibility, introducing a time lag in the process. Based on the above discussion, the 5% capacity factor exemption should only be allowed when it would not be expected to significantly impact the results of stability studies. Allowing the Transmission Planner to make this judgement is most appropriate since A) that organization is in the best position to make the determination of the impact on stability and B) that organization is responsible (via TPL standards) for ensuring the stability of the grid and connected generating units. (4) In lieu of the blanket 5% exemption, the following is proposed. (a) Delete “… and with an average Capacity Factor of greater than 5% over the last three calendar years” in all places in 4.1.1.1, 4.1.1.2 and 4.1.1.3 (b)Add new Applicabilty 4.1.1.4 stating “Generating facilities with capacity factors less than 5% over the last three calendar years may be exempted with written concurrence from the applicable Transmission Planning Authority. The written concurrence provided by the Transmission Planning Authority shall include the basis for any such exemptions.” (5) alternative to (b) could be the reponse to Q9 below.
 
Yes
(1) We believe the MVA thresholds are appropriate and pick up the vast majority of interconnection (MVA). However, the MVA values MUST be consistent with the MVA thresholds in other stanadrds, such as MOD-10 to 12. and in proposed TPL-001 standards. (2) Supporting data (circa 2003) can be found from the link below which provides a spread sheet titled “Existing Generating Units in the United States by State, Company and Plant, 2003.” http://www.eia.doe.gov/cneaf/electricity/page/at_a_glance/gu_tabs.html The spreadsheet can be sorted and summed to get an estimate of the percentage generation that would be included. A preliminary look suggests that 80% or more would be included.
No
However, add 4.1.1.5 stating “Generating facilities that do not meet the applicability requirements 4.1.1.1 - .3 may be included when their performance is found to create or contribute to reduced reliability of the BES when requested by the applicable Transmission Planner. The written request provided by the Transmission Planner shall include the technical basis for any such inclusion (e.g. must run for reliability, voltage, or stability needs).”
No, the phase in period for unit excitation system verification should be (please specify below)
(1) The term "verification" should be defined. Defining "verification" would give Generator Operators/Generator Owners a clearer understanding of what data should be verified in the model. (2) The first time period should be 3 years (10%). It is anticipated that the first units will take significantly longer than subsequent testing. Although this factor is already being considered in proposed time periods, there will probably be a significant shortage of testing services at the beginning of the testing window. (3) The last period for 100% of appliable units should be 12 years to match with 12 years of outage cycle.
None
None
(1) Requirement 1 states that testing should occur "for new or existing units within 180 days of commerical operation". We believe the testing for the new units should be done before commerical operation. (2) In Requirement R2, the Transmission Planner would not necessarily have any idea which model would best fit the installed equipment. The only workable way to comply with this requirement is for the Transmission Planner to give the Generator Operator the data sheets for the entire library of available exciter models. The Generator Operator would then need to determine which of these models would provide the best fit for the excitation system equipment to be modeled. We believe that this requirement should recognize that deriving "acceptable" model for a specific excitation system is a cooperative effort between manufacturer, GO/GOP, and TP. (3) While wind generators would generally fall below the unit size thresholds as specified in Requirement 4.1.1, it would be very helpful in conducting dynamic simulations involving wind generators if their dynamic representations would be fit into one of the standard library models. (4) There are several 90 day periods mentioned in the Requirements. It might be helpful to be more specific as to which 90 day interval is meant. For example, Requirement R8 should read something like "…within 90 days of completion of the excitation system model verification as specified in Rx." (5) This comment is in reference to MOD-026-1, R.12. We believe that Digital Control Systems do not effect excitation systems models. Therefore we suggest removing requirements associated with Digital Control Systems.
Individual
Armin Klusman
CenterPoint Energy
Yes
CenterPoint Energy concurs with the SDT that this is a reasonable approach.
Yes
CenterPoint Energy concurs periodic verfication every ten years is appropriate.
Yes
 
 
 
Yes
 
Yes
 
 
 
 
 
 
 
 
 
Individual
Mark Thompson
AESO
No
The AESO agrees with the SRC ISO/RTO comments.
No
The AESO agrees with the SRC ISO/RTO comments. We would also like to add: WECC requirements state every 5 years. 5 years seems more resonable than 10 years to ensure that the generating unit is still performing as intially sepceified and there has been no no component degradation causing the settings to drift.
No
The AESO believes that using a single unit’s actual excitation system verification to be a proxy for multiple units will not pick up errors in settings, component failures, alterations to units, etc. Each unit should be tested individually.
Yes
The AESO agrees with the SRC ISO/RTO comments.
Yes
The exciter is only one component of the generator, testing all components (generator, exciter, PSS and governor/prime mover) is imperative so a complete picture of how the unit will react within the electrical system can be modeled. For the same reason units such as wind facilities and other types of generation that do not have an exciter must be modeled and verified.
No
The AESO agrees with the SRC ISO/RTO comments.
Yes
The AESO agrees with the SRC ISO/RTO.
No (disagree with approach)
The AESO agrees with the SRC ISO/RTO comments.
 
No, instead use the approach below:
Section 4.1.1.2 directly references the Western Interconnection but then uses equipment sizes as a base that far exceeds the ones used by WECC in the Generating Unit Model Validation Policy. 75 MVA units vs 10MVA by WECC 20 MVA units in a 150 MVA facility vs. 20 MVA facility by WECC 100 kV interconnection vs. 60 kV by WECC Perhaps the standard can reference the WECC guidelines.
The AESO agrees with the SRC ISO/RTO comments.
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
The AESO agrees with the SRC ISO/RTO comments.
The ones we are aware of have been noted in the responses previous questions.
 
The AESO agrees with the SRC ISO/RTO comments. We would also like to empahsize the importance of complete unit testing as noted in our response to Question 4.
Individual
Greg Rowland
Duke Energy
No
Based on Responsibilities in the Functional Model, responsibility for determining maintenance and verification activities is clearly assigned to the Generator Owner. It should also be noted that in some cases the GO may be able to obtain additional expertise from their TP, RTO, or Region, which adds other resource options.
No
It would seem that the need to revalidate is driven by technical issues (analog controls drift, digital doesn't). There is an EPRI guide (1004556) that specifies a 5 year frequency for analog AVR calibrations. The SDT should discuss different periods based upon different control technologies (e.g. digital versus analog). In addition to R12, some communication between the Generation Operator and the Transmission Operator within the 10 year period would be reassuring that nothing has changed.
Yes
If it could be verified that the Gains and TCs are exactly the same, but just reading dial settings on analog controls might not suffice. For digital, the gains are the number programmed in, so the proxy approach is more reasonable. Also, recommend changing MVA rating to 350 MVA so that combined cycle steam units are included.
Yes
Supplying the data itself is appropriate. Industry experience has shown that simply assuring the generator data in the model is the right data for the installed equipment is adequate for assuring the validity of the Generator Parameters, additional testing is not typically needed and any inappropriate data would show up in voltage bump test comparisons needed for AVR models validations. Also, R4.4, should say The GO shall provide the Compensation Function used on the unit (Droop, Reactive Line Drop or Resistive Line Drop) and the amount of compensation provided (% of generator voltage at rated MVA).
Yes
Per the title, this is a standard applicable to the verification of excitation system models and the industry understands this to be different than the generator parameters. Requiring testing to specifically validate that generator data might require more than a bump test, which is currently thought to be adequate to address the issues currently in this standard. The generator reactances and time constants should not need verification as long as there is valid manufacturer supplied data and the generator has not been modified (rotor replacement, etc.) or condition has not degraded, such as the unit has been identified to have shorted rotor turns which would be expected to impact saturation curves and several of the reactance modeled. Additional testing might be appropriate when it is identified that a unit is operating with shorted turns, or if changes are made if a bump test cannot revalidate what is needed (such as a rotor replacement - do you need to verify saturation curves? or when you remove a rotating exciter, do you need a load rejection test?). NERC should consider establishing and documenting requirements for when model data validation should be re-verified and minimum tests needed for partial unit upgrades – (e.g. what testing is required for a rotor replacement?). Thus, it would seem a supplementary SAR to include generator parameter validation is needed. NERC should also consider developing a guide that provides input on these issues, especially if the responsibility is assigned to a GO/GOP without the technical background in models and validation. SERC developed a guide on this subject that could be leveraged for a NERC guide.
Yes
We agree the standard should not set criteria for evaluating the match, but industry guidance on acceptable criteria would be helpful.
Yes
We agree, but industry guidance on acceptable criteria would be helpful.
No (disagree with approach)
Regarding Section 4 Applicability, drop the reference to Capacity Factor of 5% over the past 3 years. This makes no sense, because for a variety of reasons the unit’s capacity factor in the very next year may be significantly higher, and having an accurate assessment of the unit’s performance would be important. The units with low capacity factor would likely be on line during a peak load period when the system is most stressed and stability issues are most likely. Also, these units could be relevant to sensitivity studies. The larger units should have a model. Additionally, MMWG requires models for all units whether they are on or off in the case. Each one must have a model if the modeling criteria is satisfied. If the unit is a reasonable size and connected to the BES like others, we don't see how you can exclude testing.
 
Yes
We agree with the approach, but would also caution the team to consider the future composition of the Interconnection MVA. Possibly the team already considered newer types of generation and the benefit of a verified model rather than just ‘estimated or typical manufacturer’s dynamics data’ (MOD-013). The team should consider clarifying the relationship between the terms in MOD-013 and MOD-026. Is ‘unit-specific dynamics data’ equivalent to a ‘verified model’? Even in the case of a sister unit? If a unit does not meet the applicability for MOD-026, would they then follow MOD-013 to determine the applicable model to provide?
Yes
Add a similar requirement to R11 that allows the TO or RC to add a generator that does not meet the applicability criteria when their performance is found to create or contribute to reduced reliability. No one can foresee all future system configurations and operating conditions. This type of requirement is fundamental to analyzing and resolving issues. Additional Comment on R11 and R12. When system or plant events occur impacting transient voltage response, the GOP should evaluate actual unit/plant performance against expected performance. This is especially important when taking credit for sister units to avoid testing of similar units at the same site. With the long time between verification testing (10 years) and even longer time frame when allowing for claiming sister units, it is important to assess actual versus predicted performance. It is not sufficient to have only the TO or RC identify potential issues because they would normally only recognize issues that negatively impact the entire system and only for the specific event. Individual generating stations may have not behaved as modeled due to protection/control problems but the overall system met requirements.
Yes, agree with proposed phase in period for unit excitation system verification
We wanted to also check "YES" on allowing credit for verification of excitation systems within the last 5 years of the Standard's approval date, but this electronic form wouldn't allow us to do that.
None
None
Section 4.1 Should the standard be revised to include small units that are part of an aggregate 200 MW facility? For example : wind farms with many 1.5 MW turbines Recommend changing R5.1) to read “The model initializes properly and a no-disturbance simulation contains no transients.” The second bullet of R7 allows an unusable model to not be corrected. Unless the point is that the unit would be out of compliance, this seems to negate requiring verification. Recommend the team to consider that all units that meet the applicability have usable models. For R12, rather than only listing the high level components, we recommend the team also note that other generator components such as a new excitation system power transformer (not a like-for-like changeout) can have an impact on aspects of the model.
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
Yes
Although we ultimately agree, we have the following comments: 1. The Generator Operator should be responsible to verify the dynamic data is accurate for the Generator, Turbine and Excitation system. The ultimate responsibility for the usability and accuracy of the dynamic models and how they perform in relation to the overall system model is the responsibility of the Transmission Planner. 2. Genertor operators in a centrally located dispatch office would not have direct access to the equipment. They can only arrange an actual verification test. Details of the units response to a disturbance would need to be gleaned from the Generator Owner's data. It is not appropriate to burden one entity with a potential compliance violation when another entity controls the data. Relying on agreement coordination between the two entities may not be sufficient to ensure the entity with responsibility to comply is able to comply with an uncooperative entity with data control.
No
10 years for digital excitation systems and 5 years for non-digital excitation systems.
No
1. While we agree with this approach, we do not agree it should be limited to 250 MVA units. It should allow it for any identical units of any size. Also, the requirement could be written more clearly by revising it to make it clear that verification is for similar units only and not all units owned. Based on these comments, we suggest re-wording R1 (2) to state: "For an existing unit, once in a ten calendar year period. If multiple units have identical applicable components and settings and are sited at the same physical location, verification of one unit is sufficient for all of these units. Verification shall be performed on a different unit each ten calendar year cycle." 2. This is a lot like the "Sister Unit" concept developed in the recent RFC generator verification standards. It may be helpful if this term was defined and described in more detail in the standard to allow for ease of compliance verification.
Yes
The question above has a typographical error. We assume the team means "Generator Operator".
No
 
Yes
1. For many GOP's, a testing contractor with experience in model fitting and selection will need be hired to do the verification. 2. The team may want to add an additional requirement for the Transmission Planner to review and confirm acceptability of the Generator Operator's excitation system model verification documentation within 90 days of submittal. This would preceed the R10 requirement.
Yes
While we agree with the approach of staying away from being too prescriptive, it may add guidance if the term "verify" (i.e. in R1) was clarified. We ask the team to consider adding "such as operational tracking or testing" after verify.
Yes agree with approach and the 5% capacity factor
 
 
No, instead use the approach below:
We feel that 80% of the Interconnection MVA is not high enough. The issue might be not including many of the CC/CT units that have a low capacity factor (above 5%). The team may want to consider 90% or further validate the 80% value.
No
 
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
 
 
 
1. In R1.4 it should be clear that the unit is achieving the 5% capacity factor for the first time over the last three calendar years. 2. R9 states that the Generator Operator shall make documentation demonstrating the excitation system model's response is appropriate available for inspection and technical review 'to' the RC, TOP, and PC. The term "make available" is vague and should be revised to provide more specifics as to how this information is to be made available for inspection and technical review 'by' the RC, TOP, and PC. 3. The term "Capacity Factor" is not NERC defined and is shown as capitalized in the standard. We suggest the team develop either a standard-specific or NERC Glossary definition. The following is a suggestion: "Capacity Factor (expressed as a percent) - The net actual energy generation (MW-hours) divided by the product of the period (hours) and the net maximum nameplate rating (MW)." 4. Sec. 4 Applicability - We do not agree with the criteria proposed for the Eastern Interconnection and believe it may leave out some important or critical units. Also, it may be better to just have one criteria throughout the interconnections. We recommend the SDT consider using the NERC Registry Criteria for all units based on plant aggregate of 75 MVA or greater and unit size of 20 MVA or greater. 5. Per Question 10 above, why wouldn't the Regional Entity procedures or guidelines be allowable for compliance after the first 5 years? [Note: It is assumed that the SDT intended to say "first" 5 years, not "last" five years in the description after Box 3 of that question]
Individual
Roger Champagne
Hydro-Québec TransÉnergie (HQT)
No
The Generator Operator does not have direct access to the equipment. The Generator Owner is the correct Functional Model entity that has direct access to the equipment and the authority to perform testing of equipment. All responsibilities assigned to the Generator Operator in the proposed standard should be reassigned to the Generator Owner.
Yes
ten-year interval is acceptable given the conditions in Requirement R12.
No
Units testing has in the past identified different responses from identical units with common settings. All units with identical design and settings should be tested unless records of actual system events demonstrate that all of the units respond the same.
Yes
The entity specified in Question 4 does not agree with the entity specified in Requirement R4. As stated in our response to Question 1, we believe the Generator Owner is the correct entity to provide the data; not the Generator Operator. We agree with the approach subject to revising the responsible entity to be the GO.
No
Expanding the scope to include verification of generator data will not provide a significant improvement in the overall modeling of excitation systems. However, these data should be provided as part of an existing Standards or from another Standards if not already existing.
No
As stated in our response to Question 1, we believe that the Generator Owner is the correct entity to provide the data; not the Generator Operator. We agree with the approach subject to revising the responsible entity.
Yes
Reliability Standards should focus on what is required and not how to meeet the requirement. Further, it would be impractical to specify verification details universally applicable to all situations. The peer review process provides appropriate safeguards to ensure that appropriate methods are used for verification. As an alternative, a technical white paper could be developped for reference.
Yes agree with approach and the 5% capacity factor
 
We agree with this approach to exclude units with low capacity factors provided that Planning Coordinators or Transmission Planners are allowed to identify additional applicable units beyond those specified in section 4.1.1 based on criticality to system reliability. Cases exist where large generating units with low capacity factors are operated only during the most stressed operating conditions. In such cases accurate modeling of these units may be critical to reliable operation of the bulk electric system.
Yes
We agree with the general approach to base the number and size of applicable generating units on the objective of validating models for 80 percent of the installed capacity on an Interconnection provided that Planning Coordinators or Transmission Planners are allowed to identify additional applicable units beyond those specified in section 4.1.1 based on criticality to system reliability. In the event the Planning Coordinator or Transmission Planner is not permitted to identify additional units, the objective should be changed to validate models for a greater percentage of the installed capacity. We do not have data to verify whether the unit size thresholds specified in Requirement R4.1.1 correspond to 80 percent of the installed capacity on an interconnection, and respectfully suggest that it is the responsibility of the SDT to provide such verification.
Yes
The Planning Coordinator or Transmission Planner should be permitted to identify additional units for applicability of the Standard based on the results of generator interconnection studies or other studies that demonstrate the criticality of correct settings on system reliability, e.g. studies demonstrating sensitivity of a stability based System Operating Limit to correct equipment settings and functionality.
No, the phase in period for unit excitation system verification should be (please specify below)
The proposed impmentation plan is too long. We recommend a five-year implementation with a requirement that units representing 20 percent of installed capacity be tested each year. We are concerned that an eleven-year implementation plan does not adequeately promote system reliability, and that having only three milestones will place a burden on system operators to schedule testing because Genator Owners may wait until years two, six, and eleven to schedule testing instead of spreading the tests out over the implementation period. Credit could be allowed for verification of excitation systems within the last five years of the Standards approval date.
Yes, we have a modification to propose to the Applicability section which list different value for diffferent Region or Interconnection. We propose that the two paragraphs in Applicability 4.1.1.1 be modified to: «Each unit (including synchronous condensers) ≥ 50 MVA, connected at the point of interconnection at 100 kV or above and with an average Capacity Factor greater than 5% over the last three calendar years.» «Each unit (including synchronous condensers) ≥ 20 MVA within a plant ≥ 100 MVA, connected at the point of interconnection at 100 kV or above and with an average Capacity Factor greater than 5% over the last three calendar years.»
 
 
Group
Pepco Holdings, Inc (PHI) - Affiliates
Richard Kafka
Pepco Holdings, Inc (PHI)
No
PHI believes that the Generator Owner should be responsible, but recognizes that the GO and GOP may be the same in most cases.
Yes
 
No
A GOP (or GO) may have sister units (identical units) at diffrent locations. This should not be restricted to one location.
Yes
 
No
 
Yes
 
Yes
 
Yes agree with the approach. But use another capacity factor (include supporting data):
 
PHI does not see a substantial difference in reliablity if the capacity factor is increased to 10%
Yes
 
No
 
Yes, agree with proposed phase in period for unit excitation system verification
 
 
 
 
Individual
Alice Murdock
Xcel Energy
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
Yes
Yes, we agree, however the SDT needs to give consideration to whether the Generator Owner has any rights to dispute such designation from its TP or PC.
Yes, agree with proposed phase in period for unit excitation system verification
 
 
 
Capacity Factor needs to be defined.
Individual
Dan Rochester
Independent Electricity System Operator
No
This responsibility rests with the Generator Owner. As indicated in the Background Information Section, Generator Owners may be responsible for providing accurate generator data including the excitation data for system modeling. Although it does not operate the generator, verification testing does not need to be performed under operating conditions only. The input/output measurements of the excitation system could suffice to verify the excitation system model, which may be performed during commissioning testing or under other non-production conditions. If the generator must be run by the Generator Operator to enable testing, the Generator Owner can make such an arrangement with the Generator Operator under an agreement, as the Background Information so suggests.
No
We believe a 10 year re-verification period is adequate for those exciters whose settings do not tend to drift over time. However, a shorter period, say 5 years, should apply to the analog or rotating type of exciters.
Yes
We agree with the proxy unit approach only if these units' excitation systems show identical performance based on the results of a limited number of tests. On the other hand, we do not agree with the 10-year cycle. Accurate excitation system data and verification that it performs as designed are critical to accurate modeling and simulation to support a wide range of reliability activities, including the determination of SOLs and IROLs. The 10 year recycle period is too long that risks changes to excitation system characteristics undetected. We suggests this period be shortened to 5 years.
Yes
We agree with the approach of requiring the Generator Owner to supply the data listed. We also suggest that since this data is required within 90 calendar days of completion of the excitation system model verification - the same condition for providing documentation demonstrating that the excitation system model’s response matches the recorded response for a voltage excursion at the generator as stipulated in R8 - we suggest R8 be combined with R4. Note that "Generator Owner" instead of "Generator Operator" is used in this question. While we view this as a typo, as indicated in our comment under Q1 we think it is appropriate that the Generator Owners be held responsible for the majority of the requirements in this standard.
Yes
We think that at a minimum, the generator's basic characteristics such as inertia constant, damping coefficient, saturation parameters, and direct and quadrature axes reactances and time constants), voltage regulators, turbine-governor systems, etc. as stipulated in MOD-013 that support modeling for dynamic simulations should be verified. A good excitation system model without a valid generator model will not provide the assurance that the simulation results are valid, which may hurt reliability.
No
We have difficulty with the concept since the GOP's determination of a "match" can be subjective and subsequent peer review is time consuming and unnecessary if some matching criteria is developed up front. While we are not in a position to suggest what that criteria should be, we tend to think that a certain percentage of deviation in some output parameters may serve to provide this measure. Also, as indicated under Q4, we suggest R8 be combined with R4. It may be a moot point if some criteria are developed but if not, there are inconsistencies among R4, R8, R9 and R10 on the recipients of the documentation that the Generator Operator must provide and the feedback to be received. We suggest the SDT review the list of recipients, and if peer review is still required then the recipients/commenters should include Transmission Planners, Planning Coordinators, Transmission Operators and Reliability Coordinators since they all are users of the data and model.
Yes
The SAR could be expanded by making it more clear that it applied not only to the excitation systems on conventional synchronous generation units but also to the equipment that performs this role on non-conventional facilities such as wind-farm voltage management systems.
No (disagree with approach)
a. The Term Capacity Factor is capitalized but this term is not defined. Suggest to use lower case, or define it. b. Capacity factor reflects a generating unit's real power generation frequency and duration, but does not provide the assurance that when the generator is on line, it's excitation system has been modeled accurately such that its expected performance matches simulation results. There are generating units that are often on line but do not generate at high capacity since they provide ancillary services including operating reserve and hence tend to have a low capacity factor. There are also sizable "mothballed" units or the entire plant of multiple sizable units that, due to various reasons, were put off line for a long period but return to service when the need for capacity so dictates. Not having their data verified based on a low capacity factor and on the assumption that they constitute a small portion of the interconnection MVA may leave room for unreliability. Further, low capacity factor is a historical value which may not be a good indicator of the future. If and when these low-capacity generators are put to high capacity usage, and particularly when the system is being stressed, the non-verified excitation systems can give rise to unpredictable system performance. Moreover, having to track a unit's capacity factor for the past 5 years to determine the need for verification is an unnecessary administrative burden.
 
Yes
We do not have any technically sound alternatives to suggest.
Yes
In some areas on the interconnection, such as those that are sparsely populated, performance of generating units at less than 100 MVA might be critical to reliability. The criteria to allow the TP and PC to identify these units could include: a. A 5% or 10% deviation of any or several of the excitation system's parameters/settings could make an otherwise stable simulation to be unstable; b. Use of generic models for the excitation system or generator would make an otherwise stable simulation to be unstable. c. Other changes or incorrect assumptions for the excitation system or generator would make an otherwise stable simulation to be unstable.
No, the phase in period for unit excitation system verification should be (please specify below)
10 years is too long a period to phase in full compliance with this standard. We recommend this be shortened to no more than 5 years so that the continent can have a fully verified set of excitation system data by that time to support modeling and simulation. This has been long overdue, and allowing the 10-year phase in period prolongs achieving the desriable reliability objectives. We also suggest the SDT to consider shortening the re-verificaiton cycle to 5 years.
Variances are already provided in the Applicability Section (for the 3 Interconnections).
None
We offer the following comments: a. A number of points/bullets in several requirements need to be performed to meet the intent of the main requirements, even though some of them are mutually exclusive (i.e. either/or). As such, they should be labeled subrequirements. These include: - R1: Points number 1 and 2 - R4: Points number 1 to 5 - R11: All bullets - R10: Both bullets - R12: The last 2 bullets b. R5: The condition that "if the excitation system model is useable" needs further elaboration. Evidence showing either Conditions (1) or (2) may suggest that either the model incorrectly reflects the excitation system or the excitation system itself, despite being modeled correctly, gives rise to the observed condition. The word "useable" thus needs to be expanded to more properly indicate whether the data is not useable or the excitation system is not useable. c. R6: The above comment on R5 also applies to R6.
Group
Entergy Fossil Operations
Stan Jaskot
Entergy Fossil Operations
No
Gnerator Owners are responsible for the maintenance of the units. This testing is not an on-line normal test. It is more of a maintenance/engineering task that would use 3rd parties to help perform. This would also require special budgeting and running a unit with off normal conditions which an owner would have to approve and sanction. Generator Owners are responsible for other Modeling standards, so wht would they not be responsible here. This is also providing data that is of no use to the Generator Owner or Operator and they will not have any expertise with this work. Only the Transmission Planner needs this data and should understand it. In that aspect, they should take some responsibility for it.
No
I am OK with 10 years for analog systems. Newer digital systems should not change over time, so they should be tested upon commissioning and that should be adequate for the life of the unit.
Yes
I agree with this except for the less than or equal to 250 MVA. It should apply to all units meeting the sister unit criteria regardless of MVA. If you want a limit, then make it something higher like 80% of the single largest generator in the system.
No
I may agree if it is reasonable and list exactly what data can be requested by the TP. Remember, the GO is dependent on contractors for doing this, it costs them money, and is of no benefit to the GO, so the listing need to be specific so it can be listed in the job scope of the work and reasonable.
No
 
No
This should be the Transmission planner's job. The GO or GOP does not use this data or the software or the expertise and may not be aware of disturbances on the system. The TP should compare this data and furnish it to the GO if there is an issue.
No
I do agree with not making the standard too large, but somewhere the GVSDT needs to provide this detailed data or training to the GO/GOP. You are requiring them to provide things that they do not have expertise in and this will lead to problems with getting this done correctly and for a reasonable price. I'm sure the contractors that do with work see a big opportunity to make money on this.
Yes agree with approach and the 5% capacity factor
 
 
Yes
 
No
 
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date
I vote yes on both of the questions.
 
 
In Requirement R5 in the event that a model is determined to be unusable and is returned to the Generator Owner for further action the transmission operator should be required to also provide the steps he has taken to exercise due diligence in the integration of the exciter system model into the over all model. This should take the form of review of data inserted against data provided, model name reviewed against model provided, etc. The transmission operator should also provide the Generator operator witih text copy of the actual exciter and generator portion of the overall model.
Individual
Tony Kroskey
Brazos Electric Power Cooperative
No
Even though a Generator Operator could possible supply and verify the information, it should be the Generator Owner who owns equipment design information that is responsible for it and be directly responsible for compliance with the requirements.
Yes
 
Yes
 
Yes
 
 
No
The Generator Owner should be responsible.
Yes
 
Yes agree with approach and the 5% capacity factor
 
 
 
No
 
 
 
 
 
Group
IRC Standards Review Committee
Ben Li
IESO
No
This responsibility rests with the Generator Owner. As indicated in the Background Information Section, Generator Owners may be responsible for providing accurate generator data including the excitation data for system modeling. Although it does not operate the generator, verification does not need to be performed under operating conditions only. The input/output measurements of the excitation system could suffice to verify the excitation system model, which may be performed during commissioning testing or under other non-production conditions. If the generator must be run by the Generator Operator to enable testing, the Generator Owner can make such an arrangement with the Generator under an agreement, as the Background Information so suggests. Further, we believe both the Transmission Planner and the Planning Coordinator are primary users of the model. We suggest that the Planning Coordinators be added to the Applicability Section, and at places where Transmission Planners are assigned a responsibility.
No
While a 10 year re-verification period may be adequate for those exciters whose settings do not tend to drift over time, a shorter period, say 5 years, should apply in general since there are analog and rotating type of exciters whose settings tend to drift from time to time.
Yes
We agree with the proxy unit approach.
Yes
We agree with the approach of requiring the Generator Owner to supply the data listed. We also suggest that since this data is required 90 calendar days of completion of the excitation system model verification - the same condition for providing documentation demonstrating that the excitation system model’s response matches the recorded response for a voltage excursion at the generator as stipulated in R8, we suggest R8 be combined with R4. Note that "Generator Owner" instead of "Generator Operator" is used in this question. While we view this as a typo, as indicated in our comment under Q1 we think it is appropriate that the Generator Owners be held responsible for the majority of the requirements in this standard.
No
This standard should focus on the excitation system only. If the industry sees a need for such verification, the requirements could be added to another MOD standard or a separate standard be created through a separate SAR.
No
As the facility owner, the Generator Owners should have the authority to confirm the accuracy of the model, which when supported by documentation, should suffice. A peer review is not necessary, and if "match" must be quantified, the industry may develop a set of criteria based on historical verification test data, and add this to the standard at a later stage.
Yes
 
No (disagree with approach)
a. The Term Capacity Factor is capitalized but this term is not defined. Suggest to use lower case, or define it. b. Capacity factor reflects a generating unit's real power generation frequency and duration, but does not provide the assurance that when the generator is on line, it's excitation system has been verified such that its model is accurately represented in simulations. There are also sizable "mothballed" units that, due to various reasons, were put off line for a long period but return to service when the need for capacity so dictates. Not having their data verified based on a low capacity factor and on the assumption that they constitute a small portion of the interconnection MVA may leave room for unreliability. Moreover, having to track a unit's capacity factor for the past 5 years to determine the need for verification is an unnecessary administrative burden.
 
Yes
We do not have any technically sound alternatives to suggest.
Yes
In some areas on the interconnection, such as those that are sparsely populated, performance of generating units at less than 100 MVA might be critical to reliability.
No, the phase in period for unit excitation system verification should be (please specify below)
We suggest that the usual implementation language be used. Requirement R1 sets the schedule for verification even for the first time based on a 10-year cycle (we suggest to be shortened to 5 years, especially for the analog and rotating type exciters). We agree with allowing credits for verification of excitation systems within the last 5 years of Standard's approval date.
None
None
We offer the following comments: a. The proposed standard lacks clarity needed for implementation as a mandatory standard. Specifically, there are different views in the industry as to what exactly is a model data sheet. Is it the block diagram of the excitation system's control system and parameters, or is it the simulation software's model sheet such as, for example, a vendor's data sheet for a specific type of exciters which it is capable of modeling in its simulation software, say, IEEEST, EXST1, or whatever name it may be, etc. We suggest clearer language be used to more specifically describe what a model data sheet means. Also, verification is subject to interpretation: is it a comparison of the expected input/output response of the excitation system versus actual response, or the expected performance of the generators when a computer simulation is conducted? b. A number of points/bullets in several requirements need to be performed to meet the intent of the main requirements, even though some of them are mutually exclusive (i.e. either/or). As such, they should be labeled sub-requirements. These include: - R1: Points number 1 and 2 - R4: Points number 1 to 5 - R11: All bullets - R10: Both bullets - R12: The last 2 bullets c. R5: The condition that "if the excitation system model is usable" needs further elaboration. Evidence showing either Conditions (1) or (2) may suggest that either the model incorrectly reflects the excitation system or the excitation system itself, despite being modeled correctly, gives rise to the observed condition. The word "usable" thus needs to be expanded to more properly indicate whether the data is not usable or the excitation system is no useable. d. R6: The above comment on R5 also applies to R6.
Individual
Jason Shaver
American Transmission Company
Yes
 
No
The 10 year period is too long and should be changed to 5 years in order to ensure greater model accuracy.
 
Yes
It provides confirmation of whether the data being used to model the generator and the generator data used in the verification test are the same.
Yes
 
Yes
 
No
Standard testing procedures should be provided as a minimum with the caveate "that the testing procedures include but are not limited to these procedures" to cover future technologies. An example would be a step response test for the exciter; swept frequecy (0.1 t0 10 Hz) response test for a PSS.
Yes agree with approach and the 5% capacity factor
 
 
No, instead use the approach below:
The threshold should be based on NERC registration criteria for Generator Owners/Operators. See Appendix 5 Organization Registration and Certification Manual. (Version 3.3) This criteria should apply across NERC. Item 2 in Requirement 1 should be set to the same level used by NERC's registration criteria for plants.
No
This standards should apply to all registered GO's and GOP's. A requirement as suggested puts the TP or PA in the position of telling NERC who should be registered. This responsibility that clearly falls to NERC and the Regional Entities and should not be expanded to any registered entity.
No, the phase in period for unit excitation system verification should be (please specify below)
20% per year for the next 5 yesrs.
 
 
ATC disagrees with portions of Requirement 2 which stipulates that the TP shall provide the excitation system model block diagram (block diagram) structure and data requirements. Many manufactures currently make their block diagrams and data requirements available to the GO/GOP. In addition, IEEE Standard Definitions for Excitation System for Synchronous Machines allows a GO/GOP to identify the type of exciter and/or PSS installed on their units along with the corresponding block diagrams and data requirements. Recommend that the words following "… dynamic simulation software." be deleted.
Individual
Jay Seitz
US Bureau of Reclamation
No
We believe the Generator Owner should be responsible for model verification. The existing NERC Standard, MOD-012-0 requires the Generator Owner to provide dynamic system modeling and simulation data to the RRO. In addition, MOD-013-0, RRO Dynamics Data Requirements and Reporting Procedures (not FERC approved), requires the RRO to coordinate with the Generator Owner to develop comprehensive dynamics data requirements and reporting procedures needed to model and analyze dynamic behavior. As such we believe this standard should be consistent and apply to Generator Owners. In addition, the NERC Reliability Functional Model - Version 4 describes the Generator Owner relationships with other entities including "Provides generator information to the Transmission Operator, Reliability Coordinator, Balancing Authority, Transmission Planner, and Resource Planner."
No
We believe the 10 year period is too long. It is hard to make the case for reliability-based need for this standard when 10 years are allowed to complete the modeling. Suggest changing the initial implementation period to 5 years which is the implementation period provided in the WECC regional policy. Ten years may then be appropriate for re-validation.
 
Yes
We agree the Generator Owner should provide the data and also be resposible for performing the model validation/verification.
Yes
Yes, we believe other accurrate dynamic models (e.g. generator model, governor model) are needed for valid computer simulations and should be required. Existing standards, MOD-012-0 Dynamics Data for Transmission System Modeling and Simulation and MOD-013-0, RRO Dynamics Data Requirements and Reporting Procedures (not FERC approved) already require each reliability region to determine comprehensive dynamics data requirements and Generator Owners to provide such modeling data. If these standards are being performed it is questionable what additional reliability concern is served by draft PRC-026-1.
No
Again we think the Generator Owner should be the responsible entity. This standard applies to only two entities, the Generator entity and the Transmission Planner; however actions by other entities , Reliability Coordinator and Transmission Operator, are required to accomplish the goals of the standard. The exact requirements of these entities should be described in the Standard.
Yes
 
No (disagree with approach)
Capacity Factor (capitalized) is not defined in the standard nor is it defined in the NERC Glossary; we think we know what it means but if the term is used in the standard it should be defined. However we believe Capacity Factor, should not be used to exempt generators. Those times when generators of low Capacity Factor are in operation will most likely be those times when the power system is most stressed and the performance of the machines should be modeled in system studies.
 
No, instead use the approach below:
We believe the NERC Compliance Registry Criteria should be used as the threshold.
Yes
If a unit or facility is critical to reliability and the Transmission Planner, Planning Coordinator, Reliability Coordinator, or Transmission Operator can present convincing evidence, the plant should be included. The criteria to use should be developed by the above entities.
No, the phase in period for unit excitation system verification should be (please specify below)
We recommend a 5-year phase in period.
WECC has developed a comprehensive regional machine testing and model validation policy that includes dynamic models for all the major generation components and the applicability thresholds are much more strict than those proposed in the draft MOD-026-1.
 
We see a blurring of the requirements between Standards MOD-012-0-Dynamics Data for Transmission System Modeling and Simulation; MOD-013-0- RRO Dynamics Data Requirements and Reporting Procedures; and the draft of MOD-026-1 - Verification of Models and Data for Generator Excitation System Functions. If entities are in compliance with MOD-012-0 and MOD-013 we see no additional enhancement to reliability by the addition of this draft standard.
Individual
Daniel J. Hansen
Reliant Energy
No
Generator Operators should not have the sole responsibility alone. With the Generator Operators typically not having the in-house expertise for the model verification, they must not only pay the cost of hiring consultants, but will also carry the burden of significant costs for low capacity factor units when trying to schedule the consultants for unpredicable run times. WECC unit verification testing has resulted in very expensive startup costs for low capacity factor units just to perform a test. There is no cost recovery method for running a unit out of the money to perform this testing.
Yes
 
Yes
Proxy unit ratings should go up to 500 MVA.
Yes
 
No
 
No
Peer review works well when performed by reasonable professional with the right motives. The only disagreement is that the Transmission Planner can arbitrarily reject the model and data without assuming any responsibility for the corrections or the cost.
Yes
 
Yes agree with the approach. But use another capacity factor (include supporting data):
Capacity factor should be raised to 15%.
 
No, instead use the approach below:
Each unit (including synchronous condensers) ≥ 100 MVA, connected at the point of interconnection at 100 kV or above and with an average Capacity Factor greater than 15% over the last three calendar years. Each unit (including synchronous condensers) ≥ 50 MVA within a plant ≥ 250 MVA, connected at the point of interconnection at 100 kV or above and with an average Capacity Factor greater than 15%
No
 
Yes, agree with allowing credit for verification of excitation systems within the last 5 years of the Standard’s approval date