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2007 Resource Adequacy Report

Produced by

The Staff of the

California Public Utilities Commission

April 15, 2008

2007 Resource Adequacy Report

Table of Contents

1. Executive Summary 4

2. Compliance with RAR in 2007 4

3. 2007 Load Forecast and Resource Adequacy Program Requirements 8

4. Counting Resource Adequacy Resources 17

5. Use of RA and RMR resources by the CAISO in 2007 37

6. Forced Outage Rates 44

7. Changes to the RA Program for 2008 46

Index of Tables

Table 1 2007 Aggregated Load Forecast Data (MW) 10

Table 2 Summary of Load Forecast Adjustments in 2007 (in MW) 11

Table 3 2007 RA Filing Summary for CPUC Jurisdictional Entities (MWs) 13

Table 4: Local RA procurement in 2007 14

Table 5 Total CAISO LSE Procurement as Percent of Total CAISO Obligation and Peak Demand 16

Table 6 : NQC values for 2006-2008 18

Table 7. Average and standard deviation of hourly production during HE 13-18 (MW) by month. 21

Table 8. Correlation Coefficients, Wind Production with Price and Load. Summer, 2007. 23

Table 9. HE 13-18 hours where, on average, production was below monthly NQC. 26

Table 10. Count of SO1 Peak Hours during which production was less than 10 percent of NQC. 26

Table 11. Difference in average production during 2007 relative to NQC for all windunits. 27

Table 12. Difference between average hourly production during SO1 Peak hours and all HE 13-18. 28

Table 13. Morning and Evening Wind and Load Ramp Rates 29

Table 14. Survey of wind capacity counting conventions 30

Table 15 Comparison of Calculation Methodologies (2007 Data). 36

Table 16 Import Allocations vs. Used in 2007 (MW) 37

Table 17 RMR Procurement for 2007 and 2008 39

Table 18 - Frequency of MOO by Unit Location, summer of 2006 and 2007 40

Table 19 MOO costs and PMIN by type in 2006 and 2007 41

Table 20 MOO Unit Hours by Location and Charge Code 41

Table 21 MOO Unit Hours by Charge Code and Month 42

Table 22. Forced Outage Rate (percent) 45

Index of Figures

Figure 1 2007 Aggregate Load Forecast Adjustments Reported by LSEs, by Month Showing Load Gained or Lost 12

Figure 2 Total CAISO Summer 2007 Forward Procurement Obligation and Forward Procurement vs. CEC Demand Forecast and Actual Monthly Peak Demand (MW) 15

Figure 3 2007 CAISO-wide wind production during HE 13-18, summed over all included wind generating units, both QF and non-QF. 20

Figure 4 Average production during 2007 SO1 Peak hours 22

Figure 5. 2007 NQC as a percent of nameplate capacity 22

Figure 6. Average hourly wind production during August 2007, by windzone. 23

Figure 7. Hourly Production during August, 2007, grouped by Hourly Load Percentile. 24

Figure 8. Hourly system wind production during the top 20 hours of load in 2007. 25

Figure 9. Time and Wind Production of top 50 load hours in 2007. 25

Figure 10. Different measures of central tendency 31

Figure 11. Different measures of central tendency 31

Figure 12. Normalized Hourly production (all hours) versus measures of central tendency (all measured at SO1 peak). 32

Figure 13. Normalized Hourly production (all hours) versus measures of central tendency (all measured at SO1 peak). 32

Figure 14. Comparison of Calculation Methodologies 34

Figure 15. Hourly Production Compared to Several Calculation Methodologies with August, 2007 Data. 35

Figure 16 FERC MOO and RA MOO in the summer of 2006 43

Figure 17 FERC MOO and RA MOO in the Summer of 2007 44

Figure 18 Forced Outages, 2003-2007. 45

Figure 19: Net Flows across Path 26 in Summer of 2006 and 2007 47

1. Executive Summary

This Report provides an annual review of the California Public Utilities Commission's (CPUC's) Resource Adequacy (RA) program and summarizes the program's experience in 2007. While the report does not make explicit policy recommendations, it is expected to provide factual input into the policy refinement discussions under consideration both in the CPUC's ongoing RA rulemaking, R.05-12-013 and the 2009 RA Implementation Order Instituting Rulemaking R.08-01-025

The intent of the RA program is to ensure adequate capacity is under contract to meet the needs CPUC jurisdictional load serving entities (LSEs). In 2007 the RA program was expanded from one centered on California Independent System Operator (CAISO) system-wide needs to one that also considers transmission constrained local areas.  The program has operated as designed, LSEs have generally complied with program rules, and sufficient capacity was procured to meet the identified needs both local and system.  There have been numerous minor program violations that staff has addressed through outreach, education and a limited number of enforcement actions.  In 2008 the program will be further expanded to address the path 26 transmission constraint that limits the movement of power between Pacific Gas and Electric's and Southern California Edison's service territories.

 

A key measure in evaluating the effectiveness of the RA program is the ability to meet operational needs through the RA resources rather than relying on backstop procurement such as reliability must-run (RMR) and the FERC authorized must-offer obligation (FERC MOO). In 2007 the there has been a significant reduction in the number and capacity of RMR contracts.  In addition, use of FERC MOO has also been reduced.  

Net Qualifying Capacity (NQC) is a key component of the RA Program, measuring how much capacity can be counted for RA. The intermittent, non-dispatchable nature of wind resources complicates the calculation of NQC values for these generators. Current NQC rules often significantly overestimate wind production at hours of peak demand; wind production in California and load on the CAISO system are negatively correlated. This report explores alternative counting methodologies, but no single methodology emerges as a clearly preferred alternative

2. Compliance with RAR in 2007

Implementation of the RA program continued for 2007 and built on the experiences of 2006. In D.06-06-064, the Commission added the Local RA obligation to the RA program, and Energy Division staff developed reporting and compliance procedures accordingly. For the 2007 compliance year, LSEs were required to demonstrate compliance with both the System RA requirements, as described in the Final 2006 RA Report1, but also with the Local RA obligations that are discussed in this report. The LSEs submit compliance filings; Energy Division staff reviews the filings, locates compliance issues, and pursues enforcement of RA obligations. CPUC Staff has implemented Commission Decisions, and overall compliance has been acceptable, although minor filing errors continue to consume staff time. In general the 2007 RA process is the same as the description of the 2006 process found in the 2006 RA report, with the exception of a new Local RA program. Description follows of the new Local RA program.

2.1. Overview of the RA Filing Process

The 2007 System and Local RA filing templates and guides built on the 2006 templates and guides, adding a new template on which LSEs demonstrate procurement with the Local RA obligations as detailed in D.06-06-064. Final versions of these were issued to the LSEs on August 10, 2006. LSEs were responsible for submitting two year-ahead filings for 2007, which are described below. As with 2006 implementation, all filings continued to be submitted simultaneously to the CAISO, CPUC, and California Energy Commission (CEC).

2.2. Compliance Review Process

The CPUC checked the filings for compliance by verifying that each LSE's submittal was accurate, timely, and satisfied all requirements. The CAISO reviewed the filings to check whether the RA filings submitted by LSEs were consistent with the supply plans submitted by generators and used the submittals to let the operations staff know which units were under contract and available. The CEC reviewed the filings and the historical load information provided by the LSEs for the appropriate time period to determine the accuracy of those filings matching load forecasts.

In 2007, CPUC Staff continued to work closely with LSEs to resolve any questions regarding the RA filing process and templates. CPUC Staff has been able to develop answers to numerous questions raised by LSEs that have special or unique circumstances. Working closely with LSEs has contributed significantly to reducing errors or omissions in the filings. Examples of questions brought to CPUC Staff include: treatment of Net Qualifying Capacity (NQC) for new resources, treatment of NQC for resources when initial NQC list was inaccurate, and discrepancies between the CEC's and LSE's load forecast. It is the hope of CPUC Staff that this process of working with the LSEs to reconcile differences and make revisions will lead to fewer questions in the future and make the RA filing process smoother. CPUC Staff, in a coordinated effort with the CEC and CAISO, has reviewed all compliance filings received to date according to a comprehensive procedure that includes verifying timely arrival of the filings, matching resources listed against those of the NQC list, and requesting corrections. The CAISO collects and organizes supply plans submitted by generators, and helps Energy Division compare the supply plans to the LSE filings. Once compliance is verified, Energy Division approves filings and returns materials to the LSEs.

2.3. Compliance Issues

The essence of the RAR program is mandatory LSE acquisition of capacity to meet load and capacity reserves. The short timeframes necessary to verify adequate capacity has been procured and complete backstop procurement if procured capacity is not adequate, creates a need for filings to occur on time and correct. Errors in filings result in delays in verification of resources that can result in unnecessary backstop procurement. Non-compliance occurs if either an LSE files with a procurement deficiency, meaning they have not met their RA obligations, or does not file at all, files late, or not in the manner required. These two types of non-compliance generally lead to enforcement actions or citations respectively. In the case of enforcement cases, the CPUC has encountered a situation where an LSE has not procured sufficiently to meet their RA obligations, and the CAISO may need to procure resources via backstop mechanisms. In the case of citations, in general, the LSE has not caused deficiencies such that the CAISO must procure backstop. Additionally, errors and deficiencies require staff to spend time investigating and determining the cause of the situation, and then working with the LSE to remedy problems. Due to the administrative obligations of the RA Program, Energy Division Staff must create incentives for LSEs to file correctly and in a timely manner.

Overall compliance in 2007 has been similar to the successful pattern seen in 2006, and continued through the 2007 implementation of the Local RA Program. Through February 2008, the Commission has pursued one enforcement case which resulted in a settlement for $107,500 as well as eight citations issued for a total of $19,0003 in penalties; this totals $126,500. Three citations have been appealed, with two resulting in payment in full and the other still pending.

Enforcement action was taken against an LSE for a procurement deficiency related to their Local RA obligation, and for listing an incomplete and unexecuted contact in their filing as a valid RA resource. This represented the first enforcement action taken under the RA Program, and the Commission reached a settlement with the LSE for $107,500.

Commission Decision 05-10-042 established a baseline penalty of 150 percent of the monthly cost of new capacity for 2006 and a baseline penalty of 300 percent of the monthly cost of new capacity for compliance year 2007 system filings. D.06-06-064 established a penalty structure for the Local RA Program. The factors leading to enforcement for RA non-compliance as indicated in D.05-10-042 include:

CPUC Staff is responsible for enforcing the obligations of the RA program for any LSE's failure to comply. If necessary, CPUC Staff will draft an Order Instituting Investigation or other appropriate proceeding to enforce the Commission rules. Although 2007 saw a large improvement in the quality of the RA filings, recurrent minor errors still consume staff time and delay the processing of filings. For this reason, CPUC Staff is very interested in minimizing the occurrence of errors. These errors include: filing late, listing units that are within 60 days of commercial operation date, filing information for the incorrect month, filing units that were affected by the outage counting protocol, inaccurate reporting of demand response, RMR, or import allocations, incorrect CAISO resource IDs, and a number of other small errors. There is also the continued need to monitor administrative issues such as filing dates and filing procedures.

The Energy Division receives 210 Advice Letters each year, including 12 monthly filings as well as the Preliminary and Final System and Local RA Filings for each of 15 LSEs. In addition the CAISO and CEC perform monthly review in support of the program such as load forecasting duties and validation of generator supply plans. As knowledge in the market has increased, time and work requirements have decreased. However with the possible reopening of the DA market as well as the inclusion of the small and multi-jurisdictional LSEs in the RA program, there is the possibility of a growth in that burden as the Energy Division would need to educate new LSEs upon entrance into the program.

After the compliance year, the CEC has also reviewed load forecasts for 2006 against the actual historical loads for each LSE submitted in 2007. The CEC has located several instances of significant difference between LSE historical loads for a period and the prior load forecasts submitted by LSEs for that period. The CEC has noted that this is a possible compliance violation, and has pursued resolution with a number of LSEs to ensure that their load forecasts are as correct and accurate as possible. These differences have been resolved to the satisfaction of the CPUC, CEC, and LSEs so as to make future forecasts more accurate, but this review will continue; the CEC will receive and review 2007 historical information and compare it to 2007 load forecasts done in 2006 to verify accuracy within a tolerable margin. This is in addition to the review the CEC performs for plausibility adjustments and demand response impacts. In the future LSEs may be subject to penalties if a pattern emerges of continued significant differences between actual historical information and load forecasts.

3. 2007 Load Forecast and Resource Adequacy Program Requirements

Implementation of the RA program continued for 2007 and built on the experiences of 20064. This section describes the new Local RA program instituted for 2007 compliance year and provides updates on the 2007 Yearly and Monthly load forecast processes for CPUC jurisdictional LSEs and the subsequent use of the load forecasts to establish Resource Adequacy Requirements (RARs) for each LSE in 2007. The section also describes the total RA resources procured to meet aggregate System and Local RAR in 2007 for CPUC jurisdictional LSEs. From analysis of the RA program throughout the summer of 2007, CPUC Staff found that CPUC jurisdictional LSEs have developed an understanding of the 2007 Local RA program and complied with the Local RA obligation instituted in D.06-06-064, and in aggregate demonstrated compliance in all Local Areas. LSEs continued that pattern in 2008.

CEC load forecasts and forecast adjustments in 2007 created a system RAR peaking at 49,491 MW for August. LSEs adjusted their forecast loads significantly between the Year-Ahead forecasts and the RA filing month, but the adjustments were largely concentrated in six Electric Service Providers (ESPs) that saw increases of nearly 800 MW in the summer of 2007. This pattern was similar to 2006. CPUC-jurisdictional LSEs procured resources to meet load in all summer months, with total RA procurement ranging from 102 percent of RAR to 141 percent of RAR. As a body, LSEs within CAISO (both CPUC- jurisdictional and non-CPUC jurisdictional) collectively procured resources sufficient to meet the actual peak loads plus reserves in all months of 2007. CPUC jurisdictional LSEs procured Local RA Resources sufficient to meet Local RA in all Local Areas as defined in the CAISO LCR study in 2007.

3.1. Yearly and Monthly Load Forecast Process

The RA program relies on load forecasts supplied and checked by the CEC as the foundation for each LSE's RAR. The load forecast used in the RA program is the most recent CEC "1 in 2" load forecast that is available as of the time the RAR is established for the year.

In order to establish the System RAR, CEC reviewed load forecasts submitted by each LSE, reconciled those load forecasts against its own forecast (from May 2006) for the entire Investor Owned Utility (IOU) service territories, and generated an individual load forecast for each LSE for each month of 2007. For the 2007 Year-Ahead System RA filings due in October of 2006, the CEC mailed an individual load forecast to each LSE by certified mail in June of 2006. This is summarized in Table 1 below.

According to the RA program rules, LSEs can submit monthly load forecasts to the CEC to show any changes in load expected due to load migration. The CEC then checks the revised load forecasts to make sure they remain plausible and are within a tolerance level to the statewide forecast, then supplies each LSE with its adjusted monthly load forecast. The monthly load forecast adjustments are summarized in Table 2.

3.1.1. Yearly Load Forecast in 2007

The CPUC RA obligation is based on two levels of load forecasting done by the LSEs and the CEC. D.05-10-042 requires LSEs to submit historical sales figures and a projected forecast for the following year, based on a reasonable assumption of load growth and customer retention. These forecasts are submitted to the CEC and CPUC for evaluation. The CEC worked to clean the data, adjust for transmission losses, and adjust the IOU load for customers returning from direct access. The CEC developed a trigger for a plausibility adjustment when the aggregate of LSE load forecasts in an IOU service area failed to match the CEC's own load forecast for that IOU service area. As specified by D.05-10-042, adjustments were made to account for the impact of energy efficiency (EE) and distributed generation (DG) and coincidence of peak. Table 1 shows the aggregate LSE submissions for 2007 and any adjustments that were made across all three IOU service areas.

Because the historic and forecast data submitted by participating LSEs contain market sensitive information, results are discussed and presented in aggregate. A more complete description of the methodology, along with more supporting data specific to each LSE, was made available to the LSEs in June of 2006.

Table 1 2007 Aggregated Load Forecast Data (MW)

Line

Element

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

1

Submitted LSE Forecasts

30,076

29,134

28,026

29,188

34,732

37,826

40,712

43,832

39,296

34,443

29,277

30,672

2

Adjustment for Residential Load (IOUs only)

179

179

179

179

179

179

179

179

179

179

179

179

3

CEC Adjustment for Plausibility

357

354

383

438

502

496

523

529

521

537

500

452

4

Net EE/DG Adjustment

-21

-23

-25

-26

-22

-22

-22

-21

-22

-22

-23

-20

5

Pro rata adjustment to Match Energy Commission forecast within 1%

5a

Sum of CEC Service Area Forecasts (Noncoincident)

31,018

30,041

28,870

30,154

35,967

39,334

42,351

45,593

40,891

35,760

30,386

31,809

5b

Net Adjustment

117

129

91

164

207

456

516

600

490

251

177

252

6

Coincidence Adjustment

-442

-474

-1,064

-449

-287

-2,124

-893

-519

-1,253

-969

-530

-575

7

Final Adjusted Forecasts to be Used for Compliance

30,265

29,290

27,588

29,500

35,323

36,816

41,034

44,618

39,229

34,433

29,577

30,949

Source: CEC staff Load Forecast Methodology Letter mailed to LSEs in June, 2006.

3.1.2. Monthly Load Migration Adjustments in 2007

D.05-10-042 outlined a process to adjust an LSE's load forecast on a monthly basis. The CEC and CPUC administered the program through 2007. The LSEs were directed to submit revised forecasts two months prior to the filing month, which is one month prior to the RA Monthly filing due date. These load forecast adjustments were to be solely for the purposes of accounting for load migration. Table 2 shows that the adjusted forecasts each month consistently represent a one to three percent increase over the year-ahead forecasts, or between 270 to 859 MW each month. Energy Division Staff also observed that the adjustments tended to grow as the year progressed, illustrating the increased uncertainty as lead time got longer.

Table 2 Summary of Load Forecast Adjustments in 2007 (in MW)

Line

Description

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

1

Total Forecasts mailed out in Jun. 2006

30,265

29,290

27,588

29,500

35,323

36,817

41,034

44,618

39,229

34,433

29,578

30,949

2

Monthly Load Forecast adjustments through 2007

270

407

550

578

470

711

480

705

853

774

859

717

3

Total forecasts used in monthly RA filings in 2007

30,535

29,696

28,138

30,078

35,792

37,527

41,514

45,323

40,083

35,207

30,437

31,665

4

Line 3 as percent of Line 1

101%

101%

102%

102%

101%

102%

101%

102%

102%

102%

103%

102%

Source - Aggregated Load Forecast Adjustments submitted to the CEC and CPUC through 2007

As with many other aspects of RA implementation in 2007, there has been a learning curve on which both the LSEs and CPUC Staff have developed and refined the RA program. In general LSEs sometimes struggled with maintaining current information in their filings regarding outages on units with which they contract to provide RA capacity, and Energy Division staff spent considerable time in the off peak months informing the LSEs of outages. Advances were made in communication and coordination within each LSE, and in general there has been significant improvement in the ability of LSEs to report filings that do not need as much correction.

Further, there has been a growth in the number of third party transactions for RA contracts made with generators that are subsequently resold to LSEs. In some cases, LSEs resell excess capacity, and in other cases a third party non-LSE purchases capacity for the purpose of resale. Some ESPs are beginning to use these third party marketers, particularly in procurement of Local RA capacity. Finally there are still large positive adjustments made to load forecasts in the month-ahead filings that indicate some load that was probably unaccounted for in the year-ahead forecasts.

Figure 1 below depicts the magnitude and diversity of monthly load forecast adjustments as reported by the ESPs and IOUs. Much like 2006, four ESPs reported minimal adjustments of around two percent or less each month, while six of the twelve ESPs reported adjustments in excess of ten percent of their load each month. The IOUs also adjusted their load to account for load migration, and the size of those adjustments did not exceed two percent of their load. However, that is not a good comparison due to the large size of IOUs relative to the pool of direct access customers that migrate. IOU load forecast adjustments are included in the total in Figure 1 however. Load forecast increases were not balanced by decreases, indicating that the yearly load forecasts underestimated ESP load while in general correctly estimating IOU load.

Figure 1 2007 Aggregate Load Forecast Adjustments Reported by LSEs, by Month Showing Load Gained or Lost

Source: Monthly load forecast adjustment filings submitted by LSEs to CEC

3.2. 2007 System RA Requirements for CPUC Jurisdictional LSEs

For every month of 2007, CPUC-jurisdictional LSEs have satisfied their individual and collective system RAR. The total MWs of RA resources5 procured exceeded the total System RAR by between 2 percent and 41 percent, depending on the month. Please note that the Total CEC Load Forecast is the same forecast as applicable to the Monthly Filings, from Line 4 in Table 2.

During the forecasted and actual peak month of August 2007, the CPUC's jurisdictional LSEs were collectively required to procure 49,491 MW of resources. Collectively, the LSEs procured 102 percent of the total System RAR, or 50,319 MW, which represents 828 MW in reserves beyond that required by the RA program.

Table 3 2007 RA Filing Summary for CPUC Jurisdictional Entities (MWs)

A

B

C

D

E

F

G

H

2007

Demand Forecast1

Demand Response2

Net Demand

RAR3

Total Resources Reported4

Resources Reported as % of RAR

Resources Reported as % of Net Demand

 

 

 

D=B-C

E=D*115%

 

G=F/E

H=F/D

Jan

30536

1361

29175

33551

44124

132%

151%

Feb

29696

1361

28335

32585

42339

130%

149%

Mar

28138

1361

26777

30794

43295

141%

162%

Apr

30078

1361

28717

33025

42413

128%

148%

May

35792

1724

34068

39178

44482

114%

131%

Jun

37527

2201

35326

40625

49061

121%

139%

Jul

41514

2286

39228

45112

48821

108%

124%

Aug

45323

2287

43036

49491

50319

102%

117%

Sep

40083

2288

37795

43464

49151

113%

130%

Oct

35207

1738

33469

38489

43102

112%

129%

Nov

30437

1419

29018

33371

41514

124%

143%

Dec

31665

1420

30245

34782

40199

116%

133%

Source: Aggregated LSE Monthly RA Filings

3.3. Adoption of Local RAR Program

Beginning in 2007, LSEs demonstrate annually that they have acquired adequate generation capacity within defined, transmission-constrained areas. A new local procurement obligation was established and required for Commission jurisdictional LSEs in D.06-06-064 applicable for compliance year 2007 that included the following requirements:

· LSEs shall demonstrate they have acquired one hundred percent of their Commission determined year-ahead local procurement obligation for the calendar year of 2007.

· A waiver of penalties provision that relies in part on a threshold price of $40 per kilowatt-year. If an LSE demonstrates that a waiver is justified, it will pay for backstop procurement but will not be penalized.

· In the event that an LSE does not meet its local procurement obligation and the LSE has not been granted a waiver, it will be subject to a penalty of $40 per kW-year on the amount of its deficiency, in addition to backstop procurement costs.

3.4. Local RA Procurement in 2007

The CPUC instituted a new Local RA obligation as part of the evolving Local RA Program for 2007 compliance year in D.06-06-064. The first Local RA filings were due November 2nd, 2006. Pursuant to the CAISO 2007 Local Capacity Technical Analysis6, LSEs were ordered to procure Local RA capacity in each of four Local Areas defined by the CPUC in fulfillment of their Local RA obligations within those four Local Areas. CPUC jurisdictional LSEs procured Local RA Resources sufficient to meet Local RA in all Local Areas of California in 2007, with procurement exceeding Local RA by two to nine percent across Local Areas. A new Local Area in Big Creek/Ventura was added for 2008 compliance year.

Table 4: Local RA procurement in 2007

Local Areas in 2007

Total LCR

CPUC jurisdictional Local RAR

Total Minimum Physical Resources Reported by month

Local RMR/DR Allocation

Minimum monthly procurement as percent of Local RAR

LA Basin

8843

7963

8132

0

102%

San Diego

2781

2781

915

2129

109%

Greater Bay Area

4771

4325

3797

618

102%

Other PG&E Local Areas

6073

5897

5979

121

103%

Totals

22468

20966

18824

2868

103%

Source: Aggregated 2007 LSE RA filings

3.5. Total RA Resources Available to CAISO in 2007

The CAISO administered their Interim Reliability Requirements Program Tariff in coordination with the CPUC's RA Program beginning in 2006 and continuing into 2007; in addition to CPUC jurisdictional LSEs, the CAISO also received RA filings from non-jurisdictional LSEs that added to the capacity available to the CAISO to provide reliable service.

Figure 2 compares the total CEC forecast (1 in 2) for the CAISO, the CAISO actual peak load, and the total CAISO Summer Forward Commitment Obligation (including the obligation upon the CPUC jurisdictional entities) for the summer months of May through September, 2007. In all months, the procurement demonstrated through the CAISO's Forward Commitment Obligation exceeded the load forecast and the actual load. Total procurement across the CAISO was well above the procurement obligation and actual peak load was comparable to the CEC 1 in 2 load forecast in all summer months of 2007. In the peak month of August 2007, capacity resources procured by all LSEs (CPUC jurisdictional and non-CPUC jurisdictional) totaled 54,584 MW of resources to meet 48,490 MW of actual CAISO peak load. System RA procurement across the CAISO ranged between 48,449 MW (May) and 54,584 MW (August), or between 117 percent and 138 percent of CEC 1 in 2 demand forecast minus Demand Response.

Figure 2 Total CAISO Summer 2007 Forward Procurement Obligation and Forward Procurement vs. CEC Demand Forecast and Actual Monthly Peak Demand (MW)

Source: Aggregated data compiled from CAISO RCST Analysis

Table 5 shows total procurement for all LSEs within CAISO as a percent of both the total procurement obligation across the CAISO and the actual peak load across the CAISO during the summer of 2007. The data represented in Figure 2 is the same data as is represented in Table 5. Significantly, 61 percent to 64 percent of all resources demonstrated in 2007 were unit specific non-DWR physical resources within the CAISO and only 7 percent to 9 percent were imports and 7 percent to 8 percent were non-DWR (Department of Water Resources) Liquidated Damages contracts. The remaining 20 to 23 percent is comprised of DWR and other resources.

Table 5 Total CAISO LSE Procurement as Percent of Total CAISO Obligation and Peak Demand

Month

Peak Load (MW):

Demand Response [@ 115%] (MW):

Demand forecast - DR (Net Demand)

Forward Commitment Obligation Minus Demand Response (MW):

I. Physical Resources in ISO Control Area

II. Unit Contingent Resources from Outside the ISO Control Area

III. Non-Unit Contingent Resources from Outside the ISO Control Area

IV. LD

V. DWR

Other or non-specified

Total RA Capacity

RA Capacity Relative to Commitment Obligation (100% is Compliant)

RA Capacity Relative to Net Demand (115% is compliant)

May-07 - PUC

35,792

1,724

34,068

39,178

30,570

2,152

140

3,800

6,946

875

44,482

114%

131%

Non-PUC

3,086

132

2,954

3,397

424

855

407

204

 

2,077

3,967

117%

134%

Total

38,878

1,856

37,022

42,575

30,994

3,007

547

4,003

6,946

2,952

48,449

114%

131%

Percent of Total

 

 

 

 

64%

6%

1%

8%

14%

6%

100%

 

 

June-07 PUC

37,527

2,202

35,325

40,624

31,955

2,201

430

3,808

9,794

875

49,063

121%

139%

Non-PUC.

3,315

186

3,129

3,599

448

857

495

272

 

1,810

3,882

108%

124%

Total

40,842

2,388

38,455

44,223

32,403

3,057

925

4,080

9,794

2,685

52,944

120%

138%

Percent of Total

 

 

 

 

61%

6%

2%

8%

18%

5%

100%

 

 

July-07 PUC

41,514

2,286

39,228

45,112

31,830

2,408

430

3,496

9,783

873

48,821

108%

124%

Non-PUC

3,681

185

3,497

4,021

521

875

441

467

 

1,969

4,274

106%

122%

Total

45,195

2,471

42,725

49,133

32,351

3,283

871

3,964

9,783

2,842

53,094

108%

124%

Percent of Total

 

 

 

 

61%

6%

2%

7%

18%

5%

100%

 

 

Aug-07 PUC

45,323

2,287

43,036

49,492

33,191

2,408

1,280

3,492

9,776

173

50,319

102%

117%

Non-PUC

3,674

182

3,491

4,015

478

904

429

513

 

1,941

4,265

106%

122%

Total

48,997

2,469

46,527

53,506

33,669

3,312

1,709

4,005

9,776

2,114

54,584

102%

117%

Percent of Total

 

 

 

 

62%

6%

3%

7%

18%

4%

100%

 

 

Sept-07 PUC

40,083

2,289

37,794

43,453

32,029

2,408

1,280

3,486

9,776

173

49,151

113%

130%

Non-PUC

3,388

182

3,206

3,686

517

908

346

468

 

1,771

4,010

109%

125%

Total

43,471

2,471

40,999

47,139

32,546

3,316

1,626

3,954

9,776

1,944

53,162

113%

130%

Percent of Total

 

 

 

 

61%

6%

3%

7%

18%

4%

100%

 

 

Source: Aggregated RA data collected by CPUC along with RCST data from CAISO for the summer of 2007.

4. Counting Resource Adequacy Resources

During the development of the RA program, the Commission established counting conventions for the different resource types which are summarized in previous Commission decisions. The NQC for each resource is computed based on the counting conventions for the applicable resource type. Once each year, the CAISO posts on their website the NQC for each resource that is eligible to sell NQC to CPUC jurisdictional LSEs. This has been done for 2006, 2007, and now for 2008 compliance years7. Significant new resources were added to the NQC list this year, highlighted by the addition of the Long Beach generating units, as well as the peakers built by SCE. In total, over 1,500 MW of NQC was added to the NQC list for 2008, including both new resources and incremental additions to existing resources.

4.1. Introduction to Net Qualifying Capacity

NQC is the amount of a resource's capacity that can be counted for resource adequacy compliance filings. NQC counting conventions vary by resource type, as described throughout this section, but it is intended to reflect the expected capacity value that will be available to the CAISO during periods of system peak demand. An overview of Net Qualifying Capacity can be found in the 2006 RA report. NQC counting conventions and the Planning Reserve Margin are closely related concepts. For example, one could interpret the PRM to include an adjustment for any deviations of actual production from NQC values.

4.2. Establishment of CAISO'S NQC Values for 2007

Significant changes have occurred to the NQC list since posting the list began for the 2006 compliance year. Several new resources have been added, the format of the list has changed, and now there is more information posted on the list such as Zonal and Local Area designation. On July 14, 2006, the CAISO updated the NQC list to be used for the compliance year 2007. The update of the NQC list was completed for the following adjustments:

The CAISO has stated that it will continue to publish an annual NQC list on or about July 1st of each year for the following RA compliance year. The CAISO has not yet developed procedures or metrics for evaluating a unit's actual performance, and the CAISO is committed to doing so within one year of the introduction of MRTU. 2007 NQC values were not adjusted for performance such as excessive outages.

4.3. Aggregate NQC Values 2006, 2007, and 2008

Table 6 shows aggregate NQC values from the CAISO NQC list for 2006-2008. In compiling the totals, most facilities were given a single, year-round NQC value. Some facilities such as wind and solar units without backup were given twelve monthly NQC values due to performance variations between months. For those facilities that were given monthly NQC values, this table uses August NQC values for the annual total.

Table 6 : NQC values for 2006-2008

Year

Total NQC

Total Number of Scheduling Resource IDs

NQC change

Scheduling Resource ID additions

2006

46687

563

 

 

2007

46504

572

-183

9

2008

48056

600

1552

30

Source: CAISO NQC lists, 2006-2008

While the total NQC available for purchase decreased between 2006 and 2007 due to the re-calculation of wind and solar resources and other NQC adjustments made by the CAISO, the NQC for 2008 increased by approximately 1552 MW due primarily to over 1000 MW of new resources from approximately 30 new generating units that were added to the NQC list for 2008, as well as an incremental 400 MW of added NQC from existing resources.

The NQC list as of August 9, 2006 was applicable for compliance year 2007. The NQC list published on July 6, 2007 is applicable for 2008.

4.4. NQC for Thermal Generation Units

The counting conventions for thermal generation units are perhaps the most straightforward application of NQC. The NQC is defined as the maximum dependable capacity available from the unit. The NQC identified for most thermal units on the NQC list is simply the PMax, or the amount of MWs available when the unit is at its "maximum performance". Although the capacity of thermal units is in part dependent on the ambient temperature at the generator site when the unit is in operation, there is no current NQC derating methodology to adjust for ambient temperatures throughout the course of the year. Generation owners are expected by the CAISO to report ambient temperature induced reduction in generation capability via the CAISO's reporting mechanisms as they occur. Some generator owners have voluntarily provided NQC values that are adjusted to account for ambient variations, but there is no systematic approach or rule to adjust NQC based on ambient conditions yet. Ambient conditions tend to lower a generator's actual output during the summer months.

4.5. NQC for Wind Resources without Backup

The intermittent nature of a wind power plant, without integrated storage or other backup generation, presents a complex challenge to represent by a single annual NQC value, or even twelve monthly NQC values. On the other hand, a daily or hourly NQC would be difficult or impossible to calculate in advance and would be inconsistent with the current RA paradigm. Thus, monthly or annual NQC values must be calculated for wind and solar resources in order for their capacity to be properly valued by the RA program, even though such values will not represent actual production at many specific times.

A wind generator's typical or average production is a function of at least two factors: location and wind turbine technology, while it's time-specific production is only a function of technology and current wind velocity. There is no clear industry consensus on a methodology to predict a generator's hourly production based on location and technology alone. In order to best represent the hourly variability of wind production, the Commission has chosen to base the NQC counting rules for wind on historical production8. Staff believes that continuing to use historical production as the basis for calculating NQC is appropriate, but investigates the implications of the current methodology in the analysis below. This analysis compares the current counting rules to many other methodologies, but no single methodology emerges as a clearly preferred alternative. Instead, the different methodologies merely emphasize different components of the historical data.

Data used in this analysis generally reflects hourly purchase data reported by the three IOUs for all wind units (QF and non-QF) during the first nine months of 2007 and some data from earlier years is also used. Purchase data for the remainder of 2007 was not available to Staff in time for inclusion in this report. Hourly load and price data were obtained from the CAISO's OASIS database. The CEC and the CAISO both group wind resources into "windzones" for analysis. This grouping is intended to help clarify the differences between wind production patterns in different regions of California. Some of the windzones (e.g. San Gorgonio, Tehachapi) have substantially larger installed wind capacities than others (e.g. Pacheco, Solano).

 

Survey of the Data & Assessment of Current NQC Counting Conventions

Current CPUC rules dictate that monthly NQC is calculated based on a three year average of hourly production during SO1 peak hours. Figure 3, below, depicts the daily production during hours ending (HE) 13-18 for each day in the first nine months of 2007 and the 2007 monthly NQC values, which are based on historical production during 2003-2005. Based on the graph, it is evident that daily production deviates broadly, in both directions, from the established NQC.

Figure 3 2007 CAISO-wide wind production during HE 13-18, summed over all included wind generating units, both QF and non-QF.

Wind production is extremely variable. As shown in Table 7 below, the standard deviation of production during peak often exceeds the average production, indicating that there is a large spread in the data and the possibility of a bi-modal distribution. The minimum hourly production for a windzone-month combination occurred during HE 13-18 17 times out of 45 combinations (Pacheco was not considered in the minimum production analysis because for all months the minimum production rounded to zero); the maximum production occurred during HE 13-18 eleven times of 54 combinations.

Table 7. Average and standard deviation of hourly production during HE 13-18 (MW) by month.

Month

Altamont

Pacheco

San Diego

San Gorgonio

Solano

Tehachapi

1

16.4 (35.7)

0.9 (2.3)

69.2 (69.9)

109.1 (118.3)

15.8 (22.2)

57.4 (71.3)

2

19.8 (29.4)

2

(2.9)

114.5 (105.8)

166.5 (142.3)

20.6 (23)

87.8

(79)

3

68.2 (89.2)

2.2 (3.4)

90.1 (82.6)

178.9 (141.7)

23.2 (26.5)

111.6 (100)

4

96.6 (105.3)

3.5 (4.1)

135.4 (106.7)

236.5 (138.4)

40.2 (33.4)

153.8 (105)

5

175.7 (123.9)

6.1 (4.1)

116.2 (93.5)

198.9 (134.8)

66.7 (34.1)

107.8 (96.6)

6

155.4 (119.1)

5.4 (3.9)

139 (87.5)

252 (129.1)

54.5 (31)

130.7 (90.1)

7

150.1 (105.2)

5.1 (3.6)

80.5 (84.1)

153.2 (107.1)

60.7 (29.9)

85.5

(74)

8

114.4 (107.8)

3.5 (3.5)

77.3 (75.3)

150.5 (117.3)

52.5 (33.8)

72.7 (67.7)

9

92.7 (109.1)

3.4 (3.9)

115.9 (97.9)

151 (112.2)

37.8 (35.9)

69.3 (75.1)

Wind production varies in a number of ways over the course of the year. In general, average production during peak hours is highest during the spring and lowest during late fall and early winter. The 2007 NQC values reflect this pattern, as shown in Figure 5 below. For instance, NQC values during the peak summer months (7-8) is between 15-30 percent of nameplate capacities, down from 20-60 percent in June (month 6). The additional two years of data reflected in Figure 5 serve to "smooth" the curves relative to Figure 4.

Figure 4 Average production during 2007 SO1 Peak hours

Figure 5. 2007 NQC as a percent of nameplate capacity

Figure 6. Average hourly wind production during August 2007, by windzone.

Note: Fraction of NQC, on the vertical axis, indicates the ratio of average hourly production to the NQC of the resources in the windzone (the vertical axis could be read as a percentage of NQC by multiplying by 100).

Table 8. Correlation Coefficients, Wind Production with Price and Load. Summer, 2007.

 

All Hours, May-September

HE 13-18, May-September

Correlation with Load

-0.32

-0.30

Correlation with Price, NP15

-0.11

-0.15

Correlation with Price, SP 15

-0.10

-0.13

Correlation with Price, Average

-0.11

-0.15

Wind production does not conveniently match the variation of load and electricity prices. Table 8 shows that wind production is negatively correlated with CAISO system load and prices in both zones (North of Path 15 {NP15} and South of Path 15 {SP15}) during the summer months, indicating that wind production is generally lower during the periods of high prices and high demand. Figure 7 demonstrates this correlation graphically by grouping hours by load and showing the hourly production for each hour in August, 2007. Most of the highest load hours fall in the lower right hand corner of the graph, during several high load days late in the month when wind production was low. Figure 7, shows that during August, 2007, the highest five percent of load hours almost all had production levels below 600 MW and most of these 38 hours were even below 200 MW.

Figure 7. Hourly Production during August, 2007, grouped by Hourly Load Percentile.

Note: The horizontal axis in this chart is time, i.e. on the left hand side of the figure are hours from the early part of the month while the end of the month is on the right.

Wind production at super-peak hours very often falls below NQC. Figure 8 shows that in only one of the twenty hours of highest load during the summer of 2007 did the actual hourly wind production exceeded NQC. Figure 9 shows that production exceeded NQC eleven of fifty highest load hours. Of these fifty hours, production exceeded fifty percent of NQC in 23 hours. Although the effect is small, note that the hours later in the afternoon tend to have a higher production level than the early hours. This is consistent with the upward slope of the curves depicted in Figure 6 from approximately HE 13 to HE 19. Figure 8 and Figure 9 also reconfirm that the highest load hours of the summer tend to occur during HE 13 to HE 18, (84 percent of the fifty hours in Figure 9 fall within that range) suggesting that this timeframe is an appropriate period of data to use for NQC calculations for summer months.

Figure 8. Hourly system wind production during the top 20 hours of load in 2007.

Note: All 20 top hours occurr