7. Assignment of Proceeding

Michael R. Peevey is the assigned Commissioner and Mark S. Wetzell is the assigned ALJ in this proceeding.

1. The assumptions, processes, and criteria used for the 2010 LCR study were discussed and recommended in a CAISO stakeholder meeting, and they generally mirror those used in the 2007, 2008, and 2009 LCR studies.

2. The Option 1 (Category B) reliability level presented in the 2010 LCR study report implicitly relies on load interruption as the only means of meeting any Applicable Reliability Criteria beyond the loss of a single transmission element, whereas Option 2 (Category C) is the local capacity level that the CAISO needs to reliably operate the grid per NERC, WECC, and CAISO standards.

3. Allowing new capacity that will become commercially operational during an RA compliance period to be counted in an LSE's compliance showing for that period could avoid unnecessarily driving up costs.

4. The portion of the interim rule adopted by D.08-06-031 for counting new capacity that provides that an LSE must claim the entire new resource and show a single local substitute unit could undermine efficient trading of local resources and reduce the options available to the LSE for fulfilling its compliance obligation.

5. Switching to monthly reallocations of CAM credits when an individual service territory has two or more operational CAM contracts, and reallocating CAM credits only when there is a change greater than 0.5 MW for any LSE, appropriately balance the need for fairly allocating CAM credits and avoiding additional administrative burdens on the Energy Division.

6. The MCC bucket approach is both a reliability measure and a cost-saving measure, and elimination of the approach without a viable replacement mechanism could increase reliability concerns and raise procurement costs.

7. The LI protocols adopted by D.08-04-050 would provide a defined, uniform standard for evaluating DR programs for RA purposes.

8. Improved consistency and accuracy in the calculation of DR load impact estimates would benefit the RA program by giving appropriate weight to the capacity value of these resources.

9. Greater transparency in the DR capacity credit allocation process would promote fairness and confidence in the RA program.

10. Since bundled service ratepayers provide funding for the benefits of certain DR programs, they effectively procure DR capacity associated with those programs.

11. The proposed "Historical Output Correction" methodology for resources whose NQC is based on a rolling average avoids double counting of schedule outages that could lead to unnecessary procurement.

12. Successful implementation of the CAISO's SCP tariff provisions is expected to facilitate capacity trading.

13. Under-forecasting by an LSE has the potential to cause cost-shifting from that LSE to LSEs that more accurately forecast their loads.

14. Requiring year-ahead load forecasts without allowing for monthly true-ups based on customer load migrations could contravene our policy to equitably allocate the cost of generation and prevent cost shifting.

15. Providing assurance of dependable physical generation resource availability to the CAISO at peak demand periods is the primary focus of the RA program.

16. The current QC counting rule for intermittent resources overstates the availability of wind resources during peak periods, and there is a negative correlation between wind production and loads on the CAISO controlled grid.

1. The CAISO's 2010 LCR study should be approved as the basis for establishing local procurement obligations for 2010 applicable to Commission-jurisdictional LSEs.

2. Application of the Option 2/Category C local area reliability standard should be continued for setting local procurement obligations for 2010.

3. Because the current Local RA program establishes procurement obligations for the following year, LSEs should only be responsible for procurement in a local area to the level of resources that exist in the area.

4. The RA program should be modified with respect to (a) new resources whose anticipated commercial operation date is after the date for annual compliance filings, (b) CAM allocations, (c) LI protocols for DR resources, (d) transparency in the DR capacity credit allocation process, (e) scheduled outages for resources whose NQC is calculated using a rolling average, and (f) the Joint Proposal for counting the QC of intermittent wind and solar resources should be adopted with a 70% exceedance factor and with modifications to aggregate the diversity benefits of wind and solar resources and to incorporate the locational diversity benefit of aggregating intermittent resource on a statewide basis.

5. The MCC bucket approach for counting use-limited resources adopted by D.05-10-042 should be continued in effect.

6. The Energy Division should convene an educational workshop and/or publish guidelines to describe and explain the LI protocols used to calculate the capacity of demand response programs.

7. It would be inequitable to bundled service customers to allocate and assign DR capacity credits to LSEs on the basis of which customers participate in the DR program.

8. Whether year-ahead load forecasts should be based on the current customer method should be reviewed in future RA proceedings.

9. The revised SES proposal for monthly true-ups of local procurement obligations, set forth in Appendix A, should be considered in a future RA proceeding subject to the qualifications and modifications stated in the foregoing discussion.

10. This proceeding should remain open for a limited time to provide opportunity for comment on SCP issues, and should be closed on July 30, 2009.

ORDER

IT IS ORDERED that:

1. The local resource adequacy program and associated requirements adopted in Decision (D.) 06-06-064 for compliance year 2007, and continued in effect by D.07-06-029 and D.08-06-031 for compliance years 2008 and 2009, respectively, are continued in effect for compliance year 2010, subject to the modifications, refinements, and Local Capacity Requirements adopted by this decision, as set forth in the ordering paragraphs below.

2. The "Option 2/Category C" Local Capacity Requirements set forth in the California Independent System Operator's 2010 Local Capacity Technical Analysis, Final Report and Study Results, dated May 1, 2009, are adopted as the basis for establishing local resource adequacy procurement obligations for load-serving entities subject to this Commission's resource adequacy program requirements.

3. The following modifications to the resource adequacy requirements adopted by D.04-01-050; D.04-10-035; D.05-10-042 as modified by D.06-02-007, D.06-04-040, and D.06-12-037; D.06-06-064, D.06-07-031; D.07-06-029; and D.08-06-031 are adopted beginning with the 2010 resource adequacy program compliance year:

a. A load-serving entity may count toward its local resource adequacy obligation all or a portion of a new generation unit that has not reached commercial operation as of the due date for submission of its year-ahead local compliance showing, provided that the load-serving entity must show a unit or units in the same local area that it will continue to list on every monthly filing to make up its local capacity obligation until the new unit has reached commercial operation.

b. For service territories with one operational Cost Allocation Methodology contract, Energy Division shall perform quarterly reallocations of Cost Allocation Methodology credits. For service territories with two or more operational Cost Allocation Methodology contracts, Energy Division shall perform monthly reallocations of Cost Allocation Methodology credits. If, for any month, a reallocation would result in no change greater than 0.5 megawatts for any load-serving entity, Cost Allocation Methodology credits would not be reallocated that month.

c. For purposes of the resource adequacy program, calculation of the capacity of demand response programs should, to the maximum extent possible, reflect the load impact protocols adopted by Decision 08-04-050.

d. In allocating and assigning demand response program capacity credits to individual load-serving entities, Energy Division should (1) provide each load-serving entity with an explicit accounting of how the megawatts associated with each demand response program were allocated to the load-serving entity, (2) provide each LSE with a preliminary assignment of demand response credits not less than 10 days prior to the final assignment, (3) publish the total qualifying capacity of demand response programs on a program-specific basis, and (4) publish information about the process and criteria used to administer the demand response credit allocation process as well as any actual data that do not inappropriately disclose market-sensitive information.

e. When the net qualifying capacity of a resource is calculated using a rolling average, scheduled outages shall be accounted for using the "Historical Output Correction" jointly proposed in workshops in Phase 2 of Rulemaking 08-01-025 by the California Independent System Operator, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company. The California Independent System Operator will provide data on historical outages subject to the scheduled outage counting criterion to the California Energy Commission. The California Energy Commission will substitute proxy data for the hours of the scheduled outage. This proxy data will be calculated by averaging the same hours for the other two years of data used in the overall qualifying capacity calculation.

f. The rules for counting the qualifying capacity of intermittent wind and solar resources set forth in Appendix C to this decision are adopted.

4. The April 14, 2009 motion of Southern California Edison Company, Pacific Gas and Electric Company, and the Utility Reform Network to supplement the record with the Energy Division's 2008 Resource Adequacy Report is granted.

5. Rulemaking 08-01-025 shall be closed on July 30, 2009.

This order is effective today.

Dated June 18, 2009, at San Francisco, California.

APPENDIX A

Excerpts from the Revised Monthly Local Capacity Proposal

of Sempra Energy Solutions, LLC (SES)14

[T]he California Public Utilities Commission ("Commission") should permit [load-serving entities (LSEs)] to calculate, using a standard methodology, Local [resource adequacy (RA)] capacity obligations for end-use customers that migrate. Annually, LSEs would assign a Local RA capacity obligation to each and every end-use customer in their service portfolio.

A simple assignment methodology would be based on the end-use customer's previous year's August peak demand (2009 for the 2010 compliance year) at the time of the [California Independent System Operator's (CAISO)] August system peak, by service account, divided by the LSE's total 2009 August peak demand for all of the LSE's customers at the local area's August system peak time in that local area. This number is the customer's peak-to-load ratio, by local area aggregated by [utility distributed company (UDC)], and would be a number less than 1.00. The sum of all of an LSE's customer's peak-to-load ratios should add to approximately 1.00 for each local [investor-owned utility (IOU)] service area. Each customer's peak-to-load ratio would then be multiplied by the LSE's [California Energy Commission (CEC)]-assigned Local RA capacity obligation for 2010 (assuming a 2010 compliance year) for that customer's local IOU service area. The result of this exercise would be the end-use customer's [local procurement obligation (LPO)] based on the CEC-assigned Local RA capacity obligation for the compliance year. For simplicity's sake, or until stakeholders determine otherwise, local RA areas are aggregated by IOU service areas, and tracking and transferring monthly [LPO] is waived if, for that month, all service accounts migrating within an IOU's service area aggregate to 0.99 MW of [LPO] or less, by LSE to LSE.

For the first year of the program, or until stakeholders determine otherwise, only accounts that are demand metered will be eligible for [LPO] migration.

As end-use customers migrate during the year from one LSE to another, the losing LSE would identify the account(s) and the associated [LPO] in a tabbed sheet on the monthly RA forecast submitted to the CEC and the Energy Division of the Commission. The forecast is submitted approximately 60 days prior to the monthly RA showing. The migrating customer(s) would also be identified on the gaining LSE's monthly forecast and tabbed sheet. The Energy Division would match this migration and confirm the release of Local RA capacity obligation from the losing LSE and impose an additional Local RA capacity obligation on the gaining LSE. At the time of the monthly RA resource showing, which is approximately 30 days following the forecast, the gaining LSE would identify the additional Local RA capacity used to meet the incoming load.

If there is a dispute between LSEs as it pertains to the migration obligation, it will be the responsibility of the LSE losing the obligation to document the capacity calculations and submit to the Energy Division. Since the only component of the calculation that is potentially debatable is an account's August peak load, at the time of the 2010 Year-Ahead [LPO] showing, due in October of 2009, each LSE is shall make the account specific obligation calculations and submit the results to the Energy Division. This list should maintain customer confidentiality, yet document each [direct access (DA)]-eligible service account's 2008 August peak demand and their [LPO] for 2010, rounded to the hundredths place. An LSE that elects not to submit the list of account [LPO] will not be allowed to request a transfer of LAR Obligation as their load migrates to another LSE. However, that same LSE will still be required to assume a [LPO] from an LSE that has submitted the list if that obligation transfer is approved by the Energy Division.

To address the concerns of asymmetry, the $40.00 per kilowatt per year trigger price for Local RA capacity would remain in effect, and the three UDCs, which control the majority of Local RA capacity, should endeavor to make any excess Local RA capacity available for purchase via a monthly request for offer process or similar non-discriminatory access - as the sale of Local RA capacity reduces the costs of utility procurement for bundled customers.

This proposal is intended as a pilot for the 2010 compliance period assuming that a Standard Tradable Capacity product will likely be implemented during 2009 or sometime 2010 by the CAISO. Any extensions, changes or modifications to the process outlined herein can be proposed during the appropriate proceeding in early 2010 defining the parameters of the 2011 RA program and after parties have gained some experience with this Local RA true-up mechanism during the 2010 program year.

(END OF APPENDIX A)

APPENDIX B

Excerpts from the Joint Proposal of the California Independent

System Operator, Southern California Edison Company, and San Diego Gas & Electric Company Regarding Calculation of Quality Capacity

for Wind and Solar Resources15

1. Proposed Methodology for Counting Wind and Solar Resources
with Three or More Years Operating Data

Set forth below is the specific intermittent resource counting methodology reflected in the Joint Proposal, including the steps in the calculation and the data that must be obtained to implement the methodology.

Performing the analysis requires the following load and generation data:

1. The previous three years of wind generation energy production data (hourly integrated) for each wind resource for each of the six wind areas within California.16 Each wind resource will be assigned to one of the six wind areas within California.17

2. For each wind area and for each wind resource within that wind area, the hourly integrated generation that corresponds to the five peak hours of each day of the month. A set of about 450 data points (5 peak hours * 30 days per month * 3 years of data) will be collected for each wind area and each wind resource within that wind area. The hours for each month shall be:

Jan-Mar, Nov and Dec HE17-HE21 (4:00 p.m.-9:00 p.m.)

Apr-Oct HE14-HE18 (1:00 p.m.-6:00 p.m.)

The Joint Proposal is based on establishing an appropriate level of confidence that intermittent RA resources will be generating at (or above) their RA capacity value during the peak demand period through the use of an exceedance methodology. The Joint Proposal also captures the diversity benefit of aggregating multiple intermittent resources in a wind resource area. The diversity benefit is a result of higher output from some wind resources offsetting lower output of other resources in the same wind area. As a result, the QC value for the wind area will generally equal or exceed the sum of the individual wind resource QCs at a given exceedance level. The initial proposal served on January 15, 2009 provided a means to allocate this diversity benefit across individual resources within a wind area. Following the initial filing, the CAISO, SCE and SDG&E worked with the California Energy Commission ("CEC") to refine the calculation procedure to fairly allocate diversity benefits. This procedure is as follows:

Using the data identified above, the following would be determined for each resource and the six wind areas within California:

1. Calculate the exceedance (70-80% as appropriate) QC for each resource in the wind area for each of the three years of the data period. These are referred to as the initial QCs for each resource; Save these values.

2. Calculate the exceedance QC for the entire wind area for each year of the data period; these are the wind area QCs.

3. Calculate the diversity factor for each wind area for each year of the data period. The diversity factor is the wind area QC divided by the sum of all initial QCs for that month; a value greater than 1 implies a positive diversity benefit. These are the annual diversity factors for each wind area. Save these values.

4. Calculate the percentage of nameplate by dividing wind area QC by total nameplate capacity for each year of the data period. These are the annual wind area % nameplate ratings. Save these values.

5. Calculate the future NQC for each resource by multiplying each year's initial QC (from Step #1) by that year's annual diversity factor (from Step #3); this is the annual calculated QC for each resource.

6. If there are less than three years of data, estimate the resource's NQC for the missing year(s) by multiplying the resource nameplate capacity by the annual wind area % nameplate rating (from Step #4); this is the annual estimated NQC.

7. For each resource, average the annual calculated QCs and annual estimated QCs (if any) together. This average is the final QC for each resource that would be used for the following year's RA requirements.

8. QC values are calculated by the CEC and published on the CAISO website.

As a general matter, the Wind Area QC will be greater than the sum of the wind resource QCs within that wind area due to the diversification benefit described in section III.C. The positive delta will be added to each wind resource's Initial QC on a pro rata basis. An example of this allocation is provided below:

o For a given exceedance factor, Wind Area A (containing three wind resources) has a Wind Area QC of 75 MW. Each wind resource (at the same exceedance factor) has Initial QCs as follows:

    Wind Resource 1: 30 MW Initial QC

    Wind Resource 2: 20 MW Initial QC

    Wind Resource 3: 10 MW Initial QC

o The positive delta of 15 MW (Wind Area QC minus sum of Wind Resource Initial QCs) is allocated in proportion to each wind resource's Initial QC; 7.5 MW or 50% of the positive delta is added to Wind Resource 1's Initial QC, 5 MW or 33% is added to Wind Resource 2's Initial QC and 2.5 MW or 17% is added to Wind Resource 3's Initial QC.

o The final QC for each wind resource is as follows:

    Wind Resource 1: 37.5 MW final QC

    Wind Resource 2: 25 MW final QC

    Wind Resource 3: 12.5 MW final QC

2. Proposed Revisions To The Methodologies for Counting Wind and Solar Resources with Less than Three Years of Operating Data

a. Wind Resources

The rules for counting wind resources with less than three years of operating history were established under Decision (D.) 07-06-029, June 21, 2007. These rules provide as follows:

For new units: The average wind production factor of all units within the Transmission Access Charge ("TAC") area where the unit is located will be used. For example, for a new unit, if the average wind unit production as a percent of Net Dependable Capacity ("NDC") in the TAC area during June of year 1 was 23%, year 2 was 22%, and year 3 was 24%, the new unit's QC for June would be 23% of its NDC: (23 + 22 + 24) / 3 = 23%.

For units with some operating experience, but less than two years of data: The average wind production factor of all units within the TAC area where the unit is located will be used in place of the missing data in the three-year formula. For example, if the average wind unit production in the TAC area as a percent of NDC during June of year 1 was 23%, year 2 was 22%, and year 3 was 24%, and the new unit production for June was 21% of NDC for year 3, the unit's QC for June would be 22% of its NDC: (23 + 22 + 21) / 3 = 22%.

For units with at least two years of operating experience, but lessthan three years of data: The unit's actual operating experience will be used. In some months, the QC value will be based on two years of data rather than three years of data (as established in the counting convention).

The CAISO, SCE and SDG&E have proposed that the current RA provisions for wind units with less than three years of operating data (copied below in section C.1.a.), be changed as follows:

o Use a wind production factor calculated on a wind area basis as described in this proposal, instead of using the wind production factor of all wind units within the TAC area; and

o Determine the production factor using the exceedance approach described above for resources with three years of operating data, instead of using the average wind production factor of all units within the area where the unit is located.

Specifically, for new wind resources without three years of operating data, the QC value would be determined using "proxy" data derived on a wind area basis for the years for which actual operating data is not available. Thus, until the particular resource has three years of historic production data, the amount of capacity that a new wind resource can be counted for RA purposes would be determined by using the Wind Area QC (the calculation of which is described above in the proposal for how to treat resources with three years of operating data) of the particular wind area in which the resource is located to "fill in" the missing years of data.

The "missing data" for a particular year for a new resource would be derived as follows. Note that a Wind Area QC value will be determined each year by the CEC and CPUC. The nameplate MW of a new resource that does not have three years of operating data would be multiplied by the following factor:

Factor = Wind Area QC in MW .

    Sum of Nameplate MW of All Wind Resources in Wind Area

Example:

Nameplate MW of all RA resources in Wind Area A = 1,000 MW

CEC calculated Wind Area QC MW value = 100 MW

Factor = 100 MW/1000 MW = 10.0%

QC value for this year for a 150 MW new resource is 150 MW x 0.100 =15 MW

b. Solar Resources

The CAISO, SCE and SDG&E have proposed that the exceedance methodology described above for use with wind resources also apply to solar resources with less than three years of operating data. However, the CAISO notes that there are two significantly different categories of technology in the solar resources. First, "photovoltaic" technologies typically receive the solar radiation and directly convert this to electricity. This approach is highly responsive to sunlight and therefore can have rapid and significant fluctuations with broken cloud cover. Second, the thermal solar technologies receive solar radiation to heat an intermediate substance before producing electricity through a thermal conversion such as a steam turbine connected to an electric generator. This technology is able to maintain more stable electric output and is less susceptible to cloud cover changes. Thus, the CAISO supports dividing solar resources into two categories -- "thermal solar" and "photovoltaic" - because they are sufficiently different technologies.

The CAISO has not recommended using the wind area for determining the proxy value to use in the years where there is no actual data, but instead recommend that the proxy be calculated using an exceedance methodology focused on the production of all solar units within each technology category within the TAC area where the solar unit is located. The CAISO proposes that this approach be used as the starting point for a methodology that would be in effect starting in 2010. However, the CAISO recognizes that as more solar resources come on line over the next few years the methodology may need to be revisited. The TAC area is a sufficiently vast geographic area that it will capture a reasonable amount of solar resources to serve as "proxy" resources for the QC determination. At this time, given the limited number of solar resources that have come on line, there is no option comparable to a "wind area" in which like solar resources can be grouped.

(END OF APPENDIX B)

APPENDIX C

Adopted Methodology for Counting Wind and Solar Resources

Set forth below is the specific intermittent resource counting methodology adapted from the Joint Proposal, including the steps in the calculation and the data that must be obtained to implement the methodology.

Performing the analysis requires the following load and generation data to calculate a monthly QC:

1. The previous three years of wind/solar generation energy production data (hourly integrated) for each wind/solar resource within California.

2. For each wind/solar resource, the hourly integrated generation that corresponds to the five peak hours of each day of the month. A set of about 450 data points (5 peak hours * 30 days per month * 3 years of data) will be collected for each wind/solar resource. The included hours for each month shall be:

Jan-Mar, Nov and Dec: HE17-HE21 (4:00 p.m.-9:00 p.m.)

Apr-Oct: HE14-HE18 (1:00 p.m.-6:00 p.m.)

The Joint Proposal is based on establishing an appropriate level of confidence that intermittent RA resources will be generating at (or above) their RA capacity value during the peak demand period through the use of an exceedance methodology. The Joint Proposal also captures the diversity benefit of aggregating multiple intermittent resources in California. The diversity benefit is the result of higher output from some wind/solar resources offsetting lower output of other resources. As a result, the wind/solar QC value for California will generally equal or exceed the sum of the individual wind/solar resource QCs at a given exceedance level. The initial proposal served on January 15, 2009 provided a means to allocate this diversity benefit across individual resources within the state. Following the initial filing, the California Independent System Operator Corporation (CAISO), Southern California Edison Company, and San Diego Gas & Electric Company worked with the California Energy Commission (CEC) to refine the calculation procedure to fairly allocate diversity benefits.

Using the data identified above, the following would be determined for each calendar month of each included year (therefore, steps 1-7 will be repeated 36 times {3 years * 12 months} and step 8 will be repeated twelve times {once for each month}) for each resource individually or for California as a whole:

1. Calculate the exceedance (70%) QC for each resource for each month of each of the three years of the data period. These are referred to as the initial QCs for each resource. As described above, a resource with at least three years of operational history will have 36 initial QCs. Save these values.

2. Calculate the exceedance QC for the entire state for each month of each year of the data period; these are the 36 wind/solar state QCs.

3. Calculate the diversity benefit for each month of each year of the data period. The diversity benefit is the difference between the wind/solar state QC and the sum of all initial QCs for that month these are the diversity benefits. Save these 36 values.

4. Calculate the percentage of capacity18 by dividing wind/solar state QC by total capacity for each month of each year of the data period. For this step, all wind and solar resources are treated together. For each of the 36 included months, only the units with production (MWh) for at least 15 days during the month should have their capacity (MW) included in the denominator. These are the wind/solar state% capacity ratings. Save these 36 values.

5. Calculate the 36 diversity shares for each resource by dividing the total energy produced during included hours by the resource for each month of each year by the total energy produced by all wind/solar resources during included hours each month of each year.

6. Calculate the future QC for each resource by multiplying the diversity share (from Step #5) by the diversity benefit (from Step #3); this is the calculated QC for each resource. This is done for each month of each year, resulting in 36 future QCs for each resource with at least three years of data.

7. For each calendar month, if there are less than three years of data, estimate the resource's QC for the missing year(s) by multiplying the resource capacity by the wind/solar state% capacity rating (from Step #4); this is the estimated QC.

8. For each resource, average the calculated QCs (if any) and estimated QCs (if any) together. This average of the three most recent calculated or estimated month specific QCs is the final QC for each resource that would be used for the following year's RA requirements. Twelve monthly QC values are calculated for each resource and published on the CAISO website.

As a general matter, the wind/solar state QC will be greater than the sum of the wind/solar resource QCs due to the diversity benefit described in section III.C of the Joint Proposal. The positive delta (diversity benefit) will be added to each wind/solar resource's Initial QC on a pro rata basis (based on the fraction of total MWh produced, i.e. diversity share). An example of this allocation is provided below, using three wind/solar resources:

· For a given exceedance factor, the wind/solar state QC is 75 MW. Each wind/solar resource (at the same exceedance factor) has Initial QCs as follows:

o Resource 1: 30 MW Initial QC; 50% Diversity Share

o Resource 2: 20 MW Initial QC; 30% Diversity Share

o Resource 3: 10 MW Initial QC; 20% Diversity Share

· The diversity benefit is 15 MW (wind/solar state QC minus sum of wind/solar Resource Initial QCs) is allocated in proportion to each wind/solar resource's diversity share. Note that this is achieved by multiplying the diversity share (resource MWh/{sum of state MWh} as described in Step 5, above) by the diversity benefit. The product of the diversity share and diversity benefit is added to the Initial QC.

· The calculated QC for each wind/solar resource is as follows:

o Resource 1: 37.5 MW calculated QC

o Resource 2: 24.5 MW calculated QC

o Resource 3: 13 MW calculated QC

To calculate each month's final QC of a wind/solar resource, three most recent calculated QCs are averaged together. Or, in the case of a resource with fewer than three years of operating history, any calculated QCs are averaged with one to three estimated QCs. Three QC values (either calculated or estimated, or a combination) are averaged to calculate the final QC. For example, to calculate the 2010 QC of a unit that first operated during 2008, one calculated QC (2008) will be averaged with two estimated QCs (2006-7).

(END OF APPENDIX C)

14 These excerpts are copied from Appendix 2 of the February 6, 2009 Energy Division Workshop Report.

15 These excerpts are copied from the opening comments of CAISO, pp. 14-21.

16 The CAISO, SCE and SDG&E have proposed that the CPUC establish the following six wind areas within California for purposes of this proposal:

17 The wind areas may change over time to the extent wind resources are constructed in areas other than those previously defined.

18 Nameplate capacity values will be used for 2010 compliance, but due to concerns about the validity of reported nameplate capacity data, another approach (e.g., maximum reported production) may be adopted for 2011.

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