System performance over a ten year planning horizon will be assessed at least annually. Such assessments will involve steady state simulations and, as appropriate, dynamic simulations. 

Steady state assessments

Steady state assessments will include consideration of the following system load conditions:

• Summer peak
• Winter peak
• Summer shoulder peak
• Fall/spring off-peak
• Summer 90/10 peak
• Light load

The first three load conditions above will be assessed in all long-range planning studies. The last three load conditions will be considered when more detailed analyses are being conducted of specific alternatives developed to solve a particular problem.  The Summer 90/10 peak load condition will be considered in the NERC Category B (loss of single element) analysis to help us determine whether extreme weather conditions may require unusual measures to meet unexpected load. The 90/10 forecast will be used to help prioritize and stage projects but it will not necessarily be used as the sole reason to justify projects. The specific criterion associated with each of the load conditions above is provided in Load forecast criteria. For each condition, wind generation is modeled at 20% of its reported output level for general planning studies and its full output level for generator interconnection deliverability studies and Power-Voltage (P-V) analysis. Generators that do not have automatic voltage regulation (AVR) or are not controllable (unmanned stations and no remote control) have been considered. When modeling these generators, special attention must be given to the limitations of these units.

Dynamic stability assessments

Dynamic stability assessments will include consideration of the following system load conditions:

• Summer peak
• Light load (50% of peak)

The first condition is typically used for voltage stability studies. The second condition is primarily used for angular stability studies. For all generator interconnection dynamic stability assessments, wind generation is modeled at its full output level.

Steady state performance assessment

Steady state performance assessments are done to identify potential transmission system vulnerabilities over a reasonable range of future scenarios. The steady state system performance criteria to be utilized by ATC shall include:

Normal conditions (NERC Category A)

• No system element (line, transformer, terminal equipment, etc.) should experience loading in excess of its normal rating for NERC Category A conditions. This criterion should apply for a reasonably broad range of generation dispatch conditions.

(Applicable NERC Standard: TPL-001-0-R1)

• The acceptable voltage range is 95 percent to 105 percent of nominal voltage for NERC Category A conditions. Such measurements shall be made at the high side of transmission-to-distribution transformers. We will consider voltage levels outside of this range, if they are acceptable to the affected transmission customer. Exceptions for certain interconnected entities are evaluated accordingly. All voltage criteria should be met with the net generator reactive power limited to 90 percent of the reported reactive power capability.(Applicable NERC Standards:  TPL-001-0-R1)

Operating procedures (operating guides) are not preferred under normal conditions, but may be employed by ATC and/or entities with generation and/or distribution facilities interconnected with the ATC transmission system to avoid transmission facility loadings in excess of normal ratings provided such procedures are practical for sustained periods, if they meet the following conditions:

• do not impose on personnel or public safety
• do not significantly degrade system reliability,
• do not result in a significant loss of equipment life or significant risk of damage to a transmission facility
• and/or do not unduly burden any entity financially.
• Supervisory switching capability is required to accomplish these operating procedures. Field switching will not be relied upon as a means to reduce facility loadings or to restore voltages to within acceptable levels.

Loss of Single Element Conditions (NERC Category B)

• No transmission element should experience loading in excess of its applicable emergency rating for applicable NERC Category B contingencies.  This criterion should be applied for a reasonably broad range of generation dispatch conditions. Load curtailment may not be utilized in planning studies for overload relief. Field switching may not be considered as acceptable measures for achieving immediate overload relief for breaker-to-breaker contingencies. For restoration after breaker-to-breaker contingencies, field switching, LTC adjustments, Operating Guides and/or generator redispatch may be considered as acceptable measures to bring element loading levels below appropriate limits.

System design should ensure that loading in excess of any Interconnection Reliability Operating Limit (IROL) can be reduced to achieve a reliable state within 30 minutes. Temporary excursions above the applicable emergency rating are acceptable if a Special Protection System (SPS) will reduce loadings automatically (i.e. no manual intervention) to an acceptable loading level in an acceptable timeframe. The acceptable loading level after SPS operation cannot exceed the applicable emergency rating and the acceptable timeframe is determined by the type of violation that will occur if left unmitigated (e.g., clearance violation may take several minutes whereas exceeding a relay trip setting may result in an essentially instantaneous trip).

(Applicable NERC Standard: TPL-002-0-R1)

• Under applicable NERC Category B contingencies, the temporary acceptable voltage range is 90 percent to 110 percent of the system nominal voltage. Exceptions for certain interconnected entities are evaluated  accordingly. Load shedding or field switching are not acceptable measures for achieving immediate voltage restoration for breaker-to-breaker contingencies. For restoration after breaker-to-breaker contingencies, field switching, LTC adjustments, Operating Guides and/or generator redispatch may be considered as acceptable measures to bring voltage levels within appropriate limits. .

System design should ensure that voltage levels outside of any Interconnection Reliability Operating Limit (IROL) can be restored to achieve a reliable state within 30 minutes. These voltage criteria should be met with the net generator reactive power limited to 95 percent of the applicable reactive power capability. Temporary excursions below 90% or above 110% of system nominal voltage are acceptable if a Special Protection System (SPS) or control of shunt compensation will automatically (i.e. no operator intervention) restore system voltage to temporary acceptable voltage levels (i.e. 90% to 110%) within an acceptable timeframe. The acceptable timeframe will be situation dependent and may need to be reviewed with E&C Services.

(Applicable NERC Standard: TPL-002-0-R1)

• The steady state system operating point of selected ATC areas should be at least 10% away from the nose of the P-V curve to assure adequate system voltage stability and reactive power resources. This 10 percent P-V margin is chosen to reflect uncertainties in load forecasting and modeling, as well as to provide a reasonable margin of stability.

• For assessments conducted using applicable MRO and RFC region-wide firm load and interchange levels (i.e. no market or non-firm system bias), generator real power output should not be limited under NERC Category B contingency conditions. We will consider a lower level of transmission service if requested by a transmission customer.

Loss of multiple element conditions (NERC Category C)

• No transmission element should experience loading in excess of its applicable emergency rating for applicable NERC Category C contingencies. This criterion should be applied for a reasonably broad range of generation dispatch conditions. Overload relief methods may include  supervisory controlled or automatic switching of circuits, generation redispatch, or firm service curtailments, as well as minimal planned load shedding. The transmission element loading should be reduced to within the normal ratings within the time frame of the applicable ratings.

(Applicable NERC Standard: TPL-003-0-R1)

• Under applicable NERC Category C contingencies, the temporary acceptable voltage range is 90 percent to 110 percent of the system nominal voltage. Exceptions for certain interconnected entities are evaluated accordingly. Methods of restoration to normal voltage range may include supervisory control of the following: capacitor banks, load tap changers, generating unit voltage regulation, generation redispatch, line switching or firm service curtailments. Minimal planned load shedding may also be used for voltage restoration. These voltage criteria should be met with the net generator reactive power limited to 95 percent of the applicable reactive power capability. For Category C contingencies, consideration may be given to operating procedures that are designed to shed a minimum amount of load.

(Applicable NERC Standard:  TPL-003-0-R1)

Extreme disturbance conditions (NERC Category D)

• The MRO/RFC Extreme Disturbance Criteria and NERC Category D criteria should be used to assess system performance. These criteria may include examining loss of all circuits on a right-of-way and loss of an entire substation, including generation at that substation. These criteria should be used to determine system vulnerabilities, but may not necessarily dictate that potential problems identified need to be remedied with system additions.

(Applicable NERC Standard:  TPL-004-0-R1)

Transient and dynamic stability performance assessment

Transient and dynamic stability assessments are generally performed to assure adequate avoidance of loss of generator synchronism, prevention of system voltage collapse, and system reactive power resources within 20 seconds after a system disturbance. The transient and dynamic system stability performance criteria to be utilized by ATC shall include the following factors. 

Large disturbance stability performance assessment

• For generator transient stability, faults will be modeled on the high side bus at generating plants.
• For generating units with actual “as built” or “field setting” dynamic data, add a 0.5 cycle margin to the expected clearing time (ECT) for dynamic contingency simulations. For generating units with assumed, typical, or proposed dynamic data, add a 1.0 cycle margin to the ECT for dynamic contingency simulations. The total clearing time (ECT + margin) must be equal to or less than the calculated critical clearing time (CCT) from the simulation. 
• Generator transient stability will be demonstrated for at least one key contingency for each applicable NERC Category B contingency. These contingencies will typically be sustained three-phase faults of a single generator, transmission line, or transmission transformer with normal fault clearing.

(Applicable NERC Standards:  TPL-002-0-R1)

• Generator transient stability will be demonstrated for at least one key contingency for each applicable NERC Category C contingency. These contingencies will typically be three-phase faults of single elements with prior outage of a generator, line or transformer with normal clearing; single line-to-ground faults on a transmission bus or breaker with normal clearing; single line-to-ground faults on two transmission lines on a common structure with normal clearing; or single line-to-ground faults on a single generator, transmission line, transmission transformer or transmission bus section with delayed clearing.

(Applicable NERC Standards:  TPL-003-0-R1)

• Generator transient stability will be evaluated for at least one key contingency for two types of NERC Category D contingencies. These contingencies are three-phase faults on a transmission line with delayed clearing (D2) and three-phase faults on a transmission transformer with delayed clearing (D3). This ATC criterion is more severe than NERC Category D criteria because it requires every generating unit to maintain transient stability for this condition.

(Applicable NERC Standards:  TPL-004-0-R1)

• Generator transient stability will be reviewed for any other NERC Category D contingencies that are judged to be potentially critical to transmission system adequacy and security.

  (Applicable NERC Standards: TPL-004-0-R1)                                

• Unacceptable system transient stability performance for NERC Category A, B, and C outages and for ATC’S more severe Category D2 and D3 outages includes the following conditions:

Angular stability assessment

• Generating unit loses synchronism with the transmission system, unless it is deliberately islanded
• Cascading tripping of transmission lines or uncontrolled loss of load
• Poorly damped angular oscillations, as defined below

Voltage stability assessment

• Voltage recovery within 70 percent and 120 percent of nominal immediately following the clearing of a disturbance

• Voltage recovery within 80 percent  and 120 percent  of nominal for between 2.0 and 20 seconds following the clearing of a disturbance
• Voltage instability (collapse) at any time after a disturbance [100 percent constant current modeling for real power load and 100 percent constant impedance modeling for reactive power load may be used in areas where the steady state operating point is at least 10 percent away from the nose of the P-V curve, otherwise appropriate induction motor modeling should be used for the voltage stability assessment.]

(Applicable NERC Standard: TPL-001-0-R1, TPL-002-0-R1, TPL-003-0-R1, TPL-004-0-R1)

Small disturbance performance assessment

The small disturbance (e.g. switching) stability performance criteria to be utilized by ATC will include:  

• With all generating units at their prescribed base case (normally full) real power output, no unit will exhibit poorly damped angular oscillations [as defined below] or unacceptable power swings in response to a (non-fault) loss of a generator, transmission circuit, or transmission transformer.

(Applicable NERC Standard: TPL-002-0-R1)

• With all generating units at their prescribed base case (normally full) real power output, no unit will exhibit poorly damped angular oscillations [as defined below] or unacceptable power swings in response to a (non-fault) loss of any two transmission circuits on a common structure.

Note:  Poorly damped angular oscillations are ones that do not meet either of the following criteria:

• The generator rotor angle peak-to-peak magnitude is within 1.0 degree or less at 20 seconds after the switching event.
• The generator average damping ratio is 15.0 percent or greater at 20 seconds after the switching event.  The average damping ratio = (d1+d2+d3+d4)/4 * 100 percent.  d1 = p5-p4/p5, d2 = p4-p3/p4, d3 = p3-p2/p3, d4 = p2-p1/p2.

Voltage Flicker

The criteria for acceptable voltage flicker levels are defined by the requirements of regulatory entities in the states in which ATC owns and operates transmission facilities, IEEE recommended practices and requirements, and the judgment of ATC.

The following flicker level criteria are to be observed at minimum system strength with all transmission facilities in service. Minimum system strength shall be defined as the condition produced by the generation that is in service in 50 percent peak load case models, minus any generation that is:

• Electrically close to the actual or proposed flicker-producing load
• Could significantly affect flicker levels
• Could reasonably be expected to be out of service under light system load conditions

Although the limits described below are not required to be met during transmission system outages, if these limits are exceeded under outage conditions, the flicker producing load must be operated in a manner that does not adversely affect other loads.  Planned outages can be dealt with by coordinating transmission and flicker producing load outages.   Because operating restrictions during unplanned outages may be severe, it would be prudent for the owner of the harmonic producing load to study the effect of known, critical, or long term outages before they occur, so that remedial actions or operating restrictions can be designed before an outage occurs.  During outages, actual, rather than minimum normal, system strength should be considered. 

All ATC buses are required to adhere to the following three criteria.

Relative steady state voltage change is limited to 3 percent of the nominal voltage for intact system condition simulations. The relative steady state voltage change is the difference in voltage before and after an event, such as capacitor switching or large motor starting. These events should occur at least 10 minutes apart and take less than 0.2 seconds (12 cycles) to go from an initial to a final voltage level. 

• Single frequency flicker is to be below the applicable flicker curves described in Table A.1 of IEEE 1453-2004 “Recommended Practice of Measurement and Limits of Voltage Fluctuations and Associated Light Flicker on AC Power Systems. Single frequency flicker is created by voltage affecting events that occur at a regular interval and superimpose a single frequency waveform between 0 and 30 Hz on the fundamental frequency 60 Hz voltage waveform. Depending on frequency (the human eye is most sensitive to frequencies in the 5 to10 Hz range) sub-synchronous frequencies with magnitudes from 0.5 percent to 3 percent can cause irritable flicker. ATC uses the flicker curve in IEEE Standard 141 (commonly referred to as “The Modified GE Flicker Curve”) to determine the acceptability of single frequency flicker.
• Multiple frequency flicker is to be a limited to a short term perception (Pst) of 0.8 and a long term perception (Plt) of 0.6. Pst and Plt are calculated using the calculation methods outlined in IEEE standard 1453-2004. These limits can be exceeded 1 percent of the time with a minimum assessment period of one week. Multiple frequency flicker has the same frequency range as single frequency flicker, but is more complex to analyze, especially when flicker magnitudes and frequencies change over time. Multiple frequency flicker is best analyzed using a flicker meter. 

Harmonic voltage distortion

In general, it is the responsibility of ATC to meet harmonic voltage limits and the responsibility of the load customers to meet harmonic current limits. The level of harmonics acceptable on the ATC system is defined by state regulations, IEEE Standard 519-1992 (Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems) and the judgment of ATC. Usually, if harmonic current limits are met, then harmonic voltage limits will also be met.

The observance of harmonic limits should be verified whenever a harmonic related problem is discovered or a new harmonic producing load with a reasonable possibility of causing harmonic problems is connected to the ATC system. The following process is utilized by ATC when managing an existing harmonic-related problem or a new harmonic-producing load:

• Existing problems - When a harmonic related problem is found on the ATC system, it is ATC’s responsibility to determine the source of the harmonics. If harmonic current limits are violated, the source of the harmonics will be required to decrease their harmonic currents to below the limits specified in the ATC Planning and Service Guide. If, after the harmonic current has been reduced to an acceptable level, the harmonic voltage is still causing a problem and above specified levels, it shall be the responsibility of ATC to bring the harmonic voltages within limits. If limits are not violated and there is still a harmonic related problem (an unlikely situation), it is the responsibility of the entity experiencing the problem to harden its equipment to the effect of harmonics or reduce the harmonics at their location. An existing violation of these harmonic limits that is not causing any problems does not necessarily require harmonic mitigation.
• New harmonic producing loads - It is the responsibility of any customer wanting to connect a harmonic producing load to the ATC system to determine if the proposed load will violate the harmonic current limits and, if these limits are violated, to determine and implement steps necessary to reduce the harmonic currents to acceptable levels. If harmonic voltage limits are not met after harmonic current limits have been met, it is the responsibility of ATC to determine if the harmonic voltage distortion will cause any system problems and if they will, it is ATC’s responsibility to develop and implement a plan to meet the harmonic voltage limits.

Transmission Planning Assessment Practices

American Transmission Company generally subscribes to the zone approach to transmission planning assessment using a multi-level planning concept. Diagrams of the planning zones for which regional plans have been developed by ATC are attached in response to Part 3 of this FERC Form 715 and show the existing transmission facilities, 100 kV and above, within ATC’s transmission system.

The concept behind the zone approach to transmission planning is to develop plans that consider all of the needs, problems and developments within each zone and develop an overall plan for the zone (that is, a plan that emphasizes projects that serve multiple purposes or solve multiple problems within the zone). In addition, ATC’s transmission planning philosophies incorporate the concept of multi-level transmission planning. When carrying out a comprehensive transmission planning process, consideration must be given not only to individual transmission needs, zone needs, and ATC-wide needs, but also to plans of other transmission providers. Solutions identified via planning activities within each level are vetted against those in adjacent levels until the most effective overall comprehensive plan is developed. ATC’s planning process will continue to develop the first three levels (individual, zone, ATC-wide). ATC is participating with other transmission owners within and affected by the MISO territory in assessing regional needs.

ATC is employing the long-standing practice of using power flow analysis to identify needs and problems and to evaluate alternative mitigation measures. ATC identifies problems and needs by simulating non-simultaneous outages of each line, transformer, bus section, and generator. ATC does implement operating guides, such as opening lines and bus sections, to mitigate problems (overloads, low voltages, etc.) during extreme flow conditions.

ATC is also conducting dynamic stability analyses within each of its zones to assess the ability of its system to withstand power system disturbances. Many of these analyses have been or are being conducted in conjunction with proposed generation interconnections. Other independent analyses are being conducted to assess dynamic and/or voltage stability performance.

Further, ATC develops transmission projects to address the congestion issues in its footprint. ATC uses the PROMOD model to analyze congestion across the ATC footprint and develop projects that will relieve the congestion. ATC submitted to the Public Service Commission of Wisconsin the first economically justified project in MISO and an order was received in the first half of 2008.

As part of the Midwest Independent System Operator, Inc. (MISO), ATC is participating in the MISO Transmission Expansion Plan process. ATC participates actively in all portions of MISO’s planning efforts, including numerous committees and task forces, in regional and economic study efforts and in development of the Midwest Transmission Expansion Plan (MTEP).

The MAIN organization ceased to exist at the end of 2005 and ATC became a member of the two subsequent regional reliability organizations, the Midwest Reliability Organization (MRO) and the ReliabilityFirst Corporation (RFC). ATC participates in regional transmission assessments conducted by the MRO Transmission Assessment Subcommittee (TAS), the RFC Transmission Performance Subcommittee (TPS), the MAPP Transmission Reliability Assessment Working Group (TRAWG), the ERAG Reliability Assessments and MISO Reliability Assessments.

In addition to the planning criteria, ATC considers a number of other factors in its transmission planning process. Following is a description of such factors.

Public/Stakeholder Input

ATC solicits public and other stakeholder input on the identification of ultimate solutions through its iterative planning process. Projects may be modified as potential solutions listed in this plan are further developed to address the specific needs identified by all stakeholders. The solutions selected to address the needs and limitations identified will reflect the input of transmission planning process stakeholders, including customers, state and local officials, the public, and coordination with other planning processes, to the extent possible.

Specific opportunities for public and stakeholder participation in the planning process are provided in accordance with ATC’s tariff Attachment FF filed at the FERC in response to the portion of FERC’s Order 890 calling for open, inclusive and transparent planning processes. The filing was made on December 7th to be effective February 7th. ATC is implementing the tariff provisions as we await FERC’s order response. ATC’s Attachment FF covers six separate planning processes and the opportunities stakeholders have to participate in the processes. The six planning processes include:

• Network adequacy planning
• Economic project planning
• Generation-transmission interconnections
• Transmission-distribution interconnections
• Transmission-transmission interconnections
• Transmission service requests.

Provisions include opportunities for stakeholders to provide input to the planning processes in terms of assumptions and projects, provide review of interim results and see final results.