Attachment III: 2012 Long-Term Reliability Assessment – Methods and Assumptions (PART II)

Methodology

For purposes of reliability assessments, the WECC region is divided into the 19 zones. The zones are configured around demand centers and transmission hubs. The subregionswith associated zones and Balancing Authorities (BA) are identified below.

A production cost model is used to calculate a supply/demand balance and the associated power transfers among the zones. The resource allocation seeks the lowest overall cost, while maintaining resource adequacy within the subregions. Data elements needed for the model to calculate the WECC-wide, and subregional reserve margins include: monthly and annual peak demand and energy forecasts, expected generation availability, annual energy for energy limited resources, coincident hourly shaping data for loads and energy-limited resources, and a simplified transmission interconnection that reflect nominal power transfer capability limits. This data is collected from the 37 BAsin WECC.

The assessment model is designed to measure the supply/demand margins based on the forecasts of monthly peak demands and expected available resources. While peak demand forecasts for several future years are readily available for BAs, the forecast for future resources additions are more dynamic. Therefore, the certainty associated with the results decrease as one looks further into the future.

Planning Reserve Margins

The seasonal reserve margin calculations in this assessment reflect seasonal ratings for Existing-Certain, Future-Planned,and Conceptual resources. WECC’s assessment modeling process does not make a distinction between Energy-Only resources and any other resource. Capabilities for Transmission-Limited resources would be reduced to reflect the transmission limitation but presently WECC does not report any such resources. Demand-Side Management is treated as a reduction to Total Internal Demand. Behind-the-meter generation is excluded from the model, as is any associated load. The model assumes that there are no transactions with entities external to WECC. Demands are modeled as BA-level hourly load shapes that are scaled to reflect the BA-level monthly peak demand and energy load forecasts. Subregion demands reported in this assessment reflect sums of the internal BA demands coincident to thesubregion-wide coincident peak demand.

Region and subregion Target Reserve Margins are calculated using a building block methodology created by WECC’s Loads and Resources Subcommittee. As such, they do not reflect a criteria-based margin determination process and do not reflect any BA or Load Serving Entity (LSE) level requirements that may have been established through other processes (e.g., state regulatory authorities).Moreover, they are not intended to supplant any of those requirements.

The building block methodology is comprised of four elements:

  1. Contingency Reserves – An additional amount of operating reserve sufficient to reduce area control error to zero in 10 minutes following loss of generating capacity, which would result from the most severe single contingency. The BA-level contingency reserve is equal to the percent required in BAL-STD-002-WECC-1, or approximately six percent of Total Internal Demand for all BAs. (Footnote BAL-STD-002-WECC-1)Contingency Reserves are required to be carried by BAs (individually or through reserve sharing pools) by NERC and WECC Standards.
  2. Regulating Reserves – The amount of spinning reserves responsive to automatic generation control that is sufficient to provide normal regulating margin. The regulating component of the guideline was calculated using data provided in WECC’sannualloads and resources data request responses. The BAs are asked how much Regulating Reserve they expect to carry during the current year, as either a Megawatt (MW) value or as a percentage of load. MW responses are converted to a percentage of load by dividing the MW provided by the forecasted peak demand. A "sanity" check is done for all responses and those that seemed unreasonably low or high are replaced by the subregional weighted average of reported regulating reserves. This component also includes reserves to balance variations in output from variable resources (such as wind) and may be significant for some BAs. The BAs are required to carry Regulating Reserves by NERC and WECC Standards.
  3. Additional Forced Outages – Reserves for additional forced outages, beyond what might be covered by operating reserves in order to cover second contingencies, are calculated using the forced outage data supplied to WECC through the loads and resources(L&R) data request responses. Ten years of data are averaged to calculate both a summer (July) and winter (December) forced outage rate. (The actual calculation is total forced outages divided by total resources reported in the loads and resourced data request responses.) The same forced outage rate is used for all BAs in WECC when calculating the building block margin. Neither NERC nor WECC standards require these reserves.
  4. Temperature Adders – Using historic temperature data for up to 20 years, the annual maximum and minimum temperature for each BA’sarea was identified. That data was used to calculate the average maximum (summer) and minimum (winter) temperature and the associated standard deviation. The standard deviation was multiplied by a 90 percent probability factor, and added to the average historic temperature to convert from a 1-in-2 temperature (50 percent exceedence) condition to a 1-in-10 (10 percent exceedence) condition. The 1-in-2 temperature was subtracted from the 1-in-10 temperature to calculate the temperature change associated with the 1-in-10 outlook. The temperature change was then multiplied by the MW per degree change supplied by the individual BAs to arrive at a MW increase associated with converting from a 1-in-2 temperature related forecast to a 1-in-10 forecast. This MW change was divided by the forecast peak demand to create a percentage change to be applied to future demand forecasts to convert from a 1-in-2 forecast to a 1-in-10 forecast. Neither NERC nor WECC standards require these reserves.

Below is an example of the temperature adder calculation.

The following table relates the building block elements to a hypothetical total forecasted demand.

Demand

Actual-year Total Internal Demands are coincident sums of BA-level hourly demands. For future year Total Internal Demands, BA historical hourly load shapes are averaged and scaled by BA-level peak demand and energy load forecasts (1-in-2) that are aggregated to create Region and subregion load projections. The Total Internal Demands (firm and non-firm) presented in this assessment reflect extractions of the monthly demands coincident with the WECC Region and subregion monthly maximum demands. The BA-level peak demand and energy load forecasts are based on assumed average weather and expected economic conditions. It should be noted that the BA-level forecast submittals to WECC are generally based on the most recently approved forecast and, as such, may reflect a significant time laps between expected conditions at the time the forecast preparation was initiated and the expected conditions as of the publication of this assessment. This time lag effect may result in apparent over-forecasts during declining economic conditions and under-forecasts during periods of rapid economic expansion.

Demand-Side Management

WECC neither tracks nor assesses energy efficiency and conservation programs. WECC does collect monthly dispatchable and controllable demand response (CDR) information for inclusion in this assessment but notes that the activation of the CDR is generally at the discretion of the LSE. CDR programs in WECC often have limitations such as having a limited number of times they can be called on and some can only be activated during a declared local emergency. Consequently, an individual LSE may not activate its CDR in response to a request for assistance from an LSE in a different part of the Interconnection and CDR should not be considered aswidely sharable. Thus, total Region and even subregion margins may be overstated by an undetermined amount.

Generation

Resources represented in the WECC assessment model are limited to generation that is available, or is expected to be available, to serve the forecasted load. Any load that is not to be metered by a BA’s energy management system is excluded, as is the generation that is serving that load. Hence, distributed generation, such as residential rooftop solar facilities and behind-the-meter generation are not included in this assessment.

The expected output to the grid of existing generation is reported in this assessment as Existing-Certain capacity while the derated portion of variable resources is reported as Existing-Other capacity. Existing-Inoperable resources are excluded from the reporting. All future resources are reported as Future-Planned or Conceptual as WECC does not classify any resources as Future-Other. WECC uses the NERC definitions for Future-Planned resources and Conceptual resources when classifying those capabilities. Confidence factors that units classified as Future-Planned and Conceptual will be built are determined by the resource reporting entities.

Hydro generation in the model is constrained by annual energy limits that are based on actual energy production from 2003 for Northwest Hydro generation and from 2002 forCalifornia Hydro generation. These two years were selected by WECC’sTransmission Expansion Planning Policy Committee (TEPPC) Data Work Group as low water years that would best reflect adverse hydro conditions.

Scheduled Maintenance and Inoperable Generation as reported in the Loads and Resources data are included in the studies as a reduction in available capacity. The majority of the July outages are scheduled for generation in the Canada and Northwest subregions. Other areas try to have all their units available for the summer peak. The generation owners in the summer peaking zones usually schedule their maintenance in the fall or spring.

Variable generation modeling of wind resources is based on wind curves created using three years worth of one-hour interval wind speed data. Solar resource output curves were created using two years of synthetic data.

On-Peak Capacity Transactions

WECC’s assessment process is based on a system-wide modeling that aggregates BA-based load and resource forecasts by geographic subregions with conservatively assumed power transfer capabilitylimits between the zones. The model calculates transfers between the subregions based on assumed economic dispatch criteria. This modeling approach excludes a representation of contractual commitments by individual entities and assures that capacity margins reflect potential forecast conditions that are independent of variable contractual transfer assumptions.

However, resources that are physically located in one BA area but are owned by an entity, or entities, located in another BA’s geographic footprint, are modeled as “forced transfers”. These resources are “moved” into the owners BA with a corresponding reduction in transfer capability between the locations. The net effect of this treatment is an increase in generation in the receiving BA and reduction in generation in the sending BA.

Transfers with other regional councils, such as the Midwest Reliability Organization and the Southwest Power Pool, are ignored in this assessment as this would require an assumption regarding the amount of surplus or deficit generation in those councils.

Transmission

For modeling purposes,the western interconnection is separated into 19 load area zones. These zones are used in a simplified transmission model to calculate potential transfers between zones. The simplified model reflects transfer capabilities between the 19zones used in the studies, wheeling costs, and loss factors. The wheeling costs for each path are used to calculate the transfer costs for any imports into a zone. The wheeling costs range from $0.00 to $6.48 per MWh. Since the L&R data request specifies that line losses be included in all demand forecasts, a loss factor of zero (0) percent is used in the model. Note that neither the wheeling cost nor the loss factor impedes the model from importing surplus resources to meet load.

These diagrams represent the seasonal capacity limits between zones.The colors of the zones in the diagrams also identify the aggregatedsubregions.

WECC entities, recognizing the need for a regional approach to transmission expansion planning, organized the TEPPC to provide transmission expansion planning coordination and leadership across the Western Interconnection. TEPPC works in close coordination with subregional planning groups, transmission operators, and others in order to facilitate regional economic transmission expansion planning. The functions performed by TEPPC complement, but do not replace the responsibilities of WECC members and stakeholders regarding the planning and development of specific projects.

Each year TEPPC develops a study program that details the transmission system expansion studies they will perform. The program is based on study requests received during TEPPC’s open season request window (November 1st – January 31st). Any interested party can submit a study request to TEPPC for consideration. Analysis and studies performed by TEPPC focus on plans with interconnection-wide implications and include a high-level assessment of transmission congestion and operational impacts. Results from TEPPC’s studies provide useful insight into transmission expansion needs within the Western Interconnection. TEPPC’s Annual Report, and other documents produced by TEPPC are located in the “Documents” section of the TEPPC webpage.[1]

Funded through a grant from the Department of Energy, awarded on December 18, 2009, TEPPC is undertaking additional transmission planning activities under the Regional Transmission Expansion Planning (RTEP) project. All information about this effort is on the RTEP web page.[2]

WECC’s website provides links to the nine regional transmission planning groups that cover the Canadian and U.S. portions of the interconnection.[3] The geographic coverage of each of the nine groups is depicted in the attached graphic. It should be noted that generally the transmission planning groups themselvesdo not have a responsibility regarding implementation of transmission plans in their respective areas. That responsibility is left to the individual planning group member and its appropriate oversight entity (e.g., state utility commission).State/provincial oversight activities vary widely within the West. In conjunction with commission oversight activities, individual entities may prepare long-term transmission planson a regular basis. For example, the Arizona Corporation Commission collects entity-level biennial transmission plans and published a biennial transmission assessment report.[4]

WECC’s TPL-001-WECC-CRT2 System Performance Criterion, requirement R 3.2.[5] addresses reactive power and voltage stability margins. It specifies that voltage stability is required for an area modeled at a minimum of 105 percent of the reference load level for system normal conditions and for single contingencies. For multiple contingencies, post-transient voltage stability is required with the area modeled at a minimum of 102.5 percent of the reference load level. For this criterion, the reference load level is the maximum established planned load limit for the area under study.Summary guidelines as to how the analysis should be conducted are presented in a Summary of WSCC Voltage Stability Assessment Methodology document.[6]

WECC is a large and geographically diverse area with significant distances between several generation areas and load areas. The transmission interconnections between these geographically dispersed areas are generally voltage stability limited, not thermally limited. The System Performance Criterion cited above also addresses transmission system operating limit determination for these interconnections.

Most load centers in the West are largely served from remote generation resources through voltage stability limited transmission interconnections. Consequently, most load within the Interconnection may be considered to be reactive power-limited. LSEs typically address reactive power issues through the installation of local controllable compensation, strengthening interconnections with high-voltage transmission system, and maintaining local must-run generation to provide local voltage support.

WECC’s voltage stability margin process is centered on meeting certain voltage dip criteria based on certain equipment outage and peak demand assumptions. Consequently, the process indirectly establishes a voltage stability margin that Transmission Planners and LSEs are expected to apply when planning transmission and distribution facility additions. Section II of the CISO’s annual transmission plan provides excellent examples of the application of the WECC Regional Criteria and associated NERC Reliability Standards in the transmission planning arena.[7]

As noted previously, nine subregion groups are involved in transmission planning for the Western Interconnection. Studies that have resulted from their planning work are available on their individual websites.[8]

[1]TEPPC Documents

[2]RTEP Web Page

[3]WECC Regional Planning Groups

[4]ACC Biennial Transmission Assessment Information

[5]TPL-001-WECC-CRT-2 System Performance Criterion

[6]Summary of WSCC Voltage Stability Assessment Methodology 7-11-01-Guideline

[7]California ISO 2011-2012 Transmission Plan

[8]WECC Regional Planning Groups