UCAN's Sixth Set of Data Requests
A. 05-12-014

At page I-2, SDG&E references the CAISO report report and recommendation adopted by the CAISO Board on August 3, 2006. The 70-page report itself is attached at Appendix I-1 to the SDG&E revised testimony. As SDG&E is the sponsoring party for this report, UCAN tenders the following questions/clarifications of the report to SDG&E. The questions contemplate that SDG&E offer its understanding of the assertions and facts contained within the CAISO report. If SDG&E does not know the answers to each these questions, please so state in response to those questions to which SDG&E is unaware of the answers.

1. App. I-1, at pp. 4 and 20, says that the 500 KV line from San Felipe Substation to Central substation will be about 10 miles long. Is this correct, and if not what is the correct value?

2. App. I-1, at pp. 4 and 20, says that the proposed project is expected to cost $1.114 billion in 2006 dollars. Is this number correct, and if not what is the correct number?

3. App. I-1, at pp. 4 and 20, indicates that IID will cover 5% of the cost of the transmission line within Imperial County and 67% of the cost of San Felipe Substation..

a. What is the source for these numbers?
b. Are they correct, and if not, what are the correct numbers?
c. What is the expected cost of the San Felipe substation?
d. In the economic analysis in Chapter IV, what Citizens Energy costs associated with San Felipe substation included in SDG&E's analysis? If none, please explain why not.
e. How much has SDG&E assumed that IID charge CAISO ratepayers for use of the project facilities that it will finance (5% of the 500 KV line in Imperial Valley, 2/3 of San Felipe substation, 100% of the Bannister-San Felipe 230 KV line to deliver geothermal generator output to San Felipe substation?

4. App. I-1, p. 6 indicates that "over 100 individual comments were considered in the studies." Please identify all comments that resulted in any actual change in the CAISO's studies, identifying the commenter, the comment, and how the study was changed in response to it.

5. Please provide the "assessment of the three transmission alternatives presented to us by the Utility Consumers' Action Network" which is referred to on p. 6 of Appendix I-1. If you are not in possession of that assessment, please describe your understanding of what that assessment contains.

6. Please provide the year-by-year costs and benefits which underlay Table 2 on p. 7 of Appendix I-1. The same table also appears on p. 18.

7. Please confirm that UCAN requested but was not permitted to attend meetings of the Transmission Planning Team referenced on p. 11 of Appendix I-1.

8. On p. 14 of Appendix I-1, the text and fn. 4 indicate that forecasted "savings in RMR payments" were used as the measure of "the reduction in payments by the CAISO Ratepayers for meeting local capacity needs due to the transmission project." Page 31 and fn. 11 repeat this statement. Please either confirm, or explain in detail why SDG&E does not agree, that:

a. The existing RMR program is expected to be replaced with locational capacity requirement programs before June 2010.

b. The program(s) that replace RMR are intended to be lower cost than RMR.

9. Appendix I-1, states on pp. 15 and 27 that the CAISO study used a 2015 base case from WECC which was then adjusted to create a 2010 base case.

a. Are these statements correct, or were the numbers 2010 and 2015 reversed?
b. Confirm that WECC does not have a 2010 economic basecase.
c. If there is a WECC 2010 basecase which was not used, please describe in detail how the WECC 2010 basecase differs from the Appendix I-1 2010 basecase constructed by working backwards from the WECC 2015 basecase.

10. Appendix I-1, p. 25, indicates that "numerous CSRTP-2006 Team meetings were held."

a. Please provide the dates and locations of all CSRTP-2006 Team meetings.
b. Please provide a list of attendees (both in person and by phone) for each meeting.
c. Please provide copies of all documents in SDG&E's possession regarding CSRTP-2006 Team meetings, including but not limited to minutes of meetings, documents distributed or discussed at meetings, e-mails among meeting participants regarding the study, internal SDG&E communications discussing the CSRTP-2006 Team meetings and/or the study itself.
d. Please provide any audiotapes of CRSTP-2006 Team meetings or audiotapes of other communications regarding the study which was eventually published as Appendix I-1.

11, Please provide all SDG&E documents regarding the study which resulted in Appendix I-1, including but not limited to all communications between SDG&E and the CAISO, SDG&E and other study participants, and internal SDG&E communications regarding the study or its various components.

12. Please explain SDG&E's understanding of what specific contingency (ies) are referred to by the phrase "only single contingency is included" at the bottom of p. 27 of Appendix I-1.

13. Appendix I-1 states, on p. 28, that "gaps in the transmission plans were identified and solutions were proposed and tested. Please identify:

a. All "gaps" that were identified.
b. All "solutions" that were proposed.
c. All "solutions" that were tested.
d. All "solutions" that were adopted into the "CAISO transmission plan that is expected to meet reliability criteria once all identified solutions are implemented." (Appendix I-1, p. 28)

14. Appendix I-1 indicates at p. 28 that a base database from the SSG-WI was "modified ... to reflect several changes due to generation additions and retirements. Please identify all changes made to the SSG-WI base database to:

a. Retire units included in the SSG-WI database.
b. Add units not included in the SSG-WI database
c. Change the assumed technology type (e.g., from simple cycle to combined cycle) of units in the SSG-WI database).
d. All other changes made to the SSG-WI database not already identified.

15. Appendix I-1 indicates at p. 28 that the study assumptions about future generation additions "included new generation projects that were either filed with the CEC and either received CEC license to construct and/or under construction." Please indicate:

a. Which CEC-licensed projects that are licensed but not under construction were included, which were not, and what were the reasons for treating some licensed-but-not-under-construction projects differently from others?

b. Which proposed California projects not subject to CEC permitting (hydro, wind, under 50 Mw) were included and which were not, and what were the reasons for treating some proposed projects differently from others?

c. Which projects filed with the CEC but not yet approved were included, which were not, and what were the reasons for treating some filed projects differently from others?

d. Which non-California projects which have not yet received regulatory approval were included?

e. Which non-California projects which have not yet begun construction were included?

f. Which projects subject to CEC jurisdiction (thermal projects over 50 Mw within California) which have not yet applied for CEC permits were included, and why?

16. Appendix I-1 indicates at p. 28 that it "used the California Energy Commission" forecast. Please:

a. Identify the CEC document from which the forecast was drawn, and provide copies of the page(s) containing the 2010 and 2015 forecasts for SCE, SDG&E, PG&E, LADWP, and IID (the California utilities for which load forecasts are shown in Table 3.1 on p. 29).
b. Identify how much the CEC-forecasted peak load was "adjusted to model the "90/10" or one out of ten conditions" (Appendix I-1, p. 28).

17. Appendix I-1 indicates at p. 29 that "50/50" loads were used for its economic analysis. Please:

a. Identify the CEC document from which the forecast was drawn, and provide copies of the page(s) containing the 2010 and 2015 forecasts for SCE, SDG&E, PG&E, LADWP, and IID (the California utilities for which load forecasts are shown in Table 3.1 on p. 29).
b. Identify how much the CEC-forecasted peak load was modified.
c. Provide the total annual load (in gwh) used in the economic analysis for each of the 5 California utilities listed on p. 29.
d. Provide the CEC's 50/50 forecast of total annual load for each of the 5 utilities listed on p. 29.

18. Appendix I-1 indicates on p. 33 that if a proposed alternative had an acceptable impact on meeting the State RPS goal and an acceptable reliability impact and a larger net economic benefit than the proposed project, it would be recommended in lieu of the proposed project. With regard to economic benefits, does SDG&E construe "larger" to mean larger in absolute value or larger in benefit/cost ratio?

19. Please explain what "significant short-term market distortions" would occur if the LEAPS power plant were operated by the CAISO (Appendix I-1, p. 34).

20. Appendix I-1, p. 35, states that SDG&E "intends to rely on this line to reach planned renewable resources in the Salton Sea area without curbing economic imports into California."

a. Is the phrase "without curbing economic imports into California" a correct description of part of SDG&E's intent in developing the Sunrise project (i.e. does SDG&E agree with this assertion)?
b. If SDG&E had a way to "reach planned renewable resources in the Salton Sea area," that also had the effect of "curbing economic imports into California," would that be an acceptable way for SDG&E to meet the renewable energy goals served by the Sunrise project?

21. Appendix I-1, p. 36, states that "To meet CAISO Grid Planning criteria for G-1 (system readjusted), all of the basecases were prepared with the largest combined cycle unit out of service with system readjustment." Please explain your understanding of:

a. Why is an outage of Otay Mesa considered a G-1 event, when Otay Mesa will consist of three separate generators (2 combustion turbines and a steam turbine)?
b. If Otay Mesa were operating at full power and the steam turbine or the HRSG tripped off-line, what generating capacity would still be available from the remaining combustion turbines? (The answer to this question should take into account the previous answer to UCAN data request 1-91, indicating that both Palomar and Otay Mesa are designed to allow continued CT operation after a steam generator trip)
c. If Otay Mesa were operating at full power and one of the two combustion turbines tripped off-line, what generating capacity would still be available from the remaining combustion turbine and the steam turbine?
d. Is it SDG&E's position that it wants the CAISO to consider a complete outage of its largest combined cycle plant to be counted as the G-1 event for reliability planning purposes?
e. For SDG&E's now-operating Palomar combind cycle, if Palomar were operating at full power and the steam turbine tripped off-line, what generating capacity would still be available from the remaining two combustion turbines?
f. For SDG&E's now-operating Palomar combind cycle, if Palomar were operating at full power and one of the two combustion turbines tripped off-line, what generating capacity would still be available from the remaining combustion turbine and the steam turbine?
g. Please provide any past communications between SDG&E and the CAISO regarding the determination of the G-1 event for SDG&E upon commercial operation of the Palomar combined cycle.
h. Please identify any occasions when the full capacity of Palomar (both combustion turbines and the steam turbine) has been forced off-line by a single event.

22. Appendix I-1 indicates at the bottom of p. 36 that under G-1/N-1 conditions with no Sunrise "the import to SDG&E under this condition is primarily through the South of SONGS." (Emphasis added). Please:

a. Indicate where else imports come from under this condition, other than South of SONGS?
b. Provide a list of all transmission facilities which exceed their emergency ratings for this condition (2010 loads and resources, initial imports of 2803 Mw, Otay Mesa completely out, SWPL trips).
c. For each year from 1984-2006, provide a list of all historic hours when SWPL has been on a forced outage while SDG&E loads were within (i) 10 percent, or (ii) 20 percent of the SDG&E peak load for that year. For 2006, assume the annual SDG&E peak load will turn out to be the 4502 Mw reported on p. I-7, fn. 13.

23. Appendix I-1 asserts at p. 37 that "With the addition of the Sun Path Project, both the SIL and NSIL are increased to 4000 MW and 3500 MW, respectively." Please provide the analysis which forms the basis for this sentence. In particular:

a. Please identify how many hours per year in 2010 and 2015 the Gridview economic modeling showed imports of 4000 Mw, and whether each such hour occurred with no overloads under N-0 conditions of any facility's normal rating?

b. Please provide powerflow diagrams for a situation, in both 2010 and 2015, where SG&E is importing 3500 Mw with both Otay Mesa and SWPL out of service and no facilities are loaded over their emergency ratings. Such powerflow diagrams should cover, at a minimum, Orange, San Diego, and Imperial Counties, as well as the relevant portions of CFE.

c. For both 2010 and 2015, for the situation where SG&E is importing 3500 Mw with both Otay Mesa and SWPL out of service and no facilities are loaded over their emergency ratings, please indicate whether the subsequent loss of the San Felipe-Central line would cause any facilities to overload or any path limits to be exceeded, including particularly the 2500 Mw South-of SONGS path limit and the Path 45 path limits.

d. For both 2010 and 2015, please provide a powerflow diagram for the situation where SG&E is importing 3500 Mw with both Otay Mesa and SWPL out of service and no facilities are loaded over their emergency ratings, and then San Felipe-Central trips.

e. What is the emergency rating for flows on the south-of-SONGS path?

f. Explain why both Tables 4.1 and 4.2 have footnotes saying that "This table is not intended as a rigorous import analysis or verification of any import limits.

g. Please confirm that the "Total Import Capability" numbers shown on the bottom lines of both Tables 4.1 and 4.2 are assumptions, not calculated numbers (or, in the alternative, provide the analysis underlying the numbers shown)

h. To the extent to which SDG&E understands, please explain why some of the documents provided in response to UCAN discovery regarding the December 2005 CPCN filing showed an increase in NSIL due to Sunrise of 700 Mw (from 2500 Mw to 3200 Mw) and not 1000 Mw, and what has changed since then.

i. Page 61 of Appendix I-1 says that the estimated 1000 Mw increase in import capability due to Sun Path is "SDG&E's estimate." Is this attribution to SDG&E correct?

24. Please confirm that:

a. Table 4.1 on p. 37 of Appendix I-1 shows that, with all transmission lines in service, adding the "Sun Path" project increases SDG&E system losses in 2010 from 77 Mw to 80 Mw.
b. Table 4.2 on p. 38 of Appendix I-1 shows that, with all transmission lines in service, adding the "Sun Path" project increases SDG&E system losses in 2015 from 91 Mw to 100 Mw.

25. Confirm that the economic costs of line losses included in the economic assessment in Appendix I-1. If so, please describe how and provide the line loss costs associated with each scenario studied.

26. Please explain SDG&E's understanding of how line losses are taken into account in determining dispatch of resources in the economic analysis in Appendix I-1.

27. Tables 4.1 and 4.2 on pp. 37-38 of Appendix I-1 shows SDG&E internal generation in 2010 and 2015 of under 2200 Mw with Otay Mesa out of service. Table IV-17 shows "Total San Diego Capacity after G-1" of 2279 Mw in 2010 and 2015. Please:

a. Explain SDG&E's understanding of the discrepancy
b. Indicate whether SDG&E, as a member of the CSRTP-2006 Team, ever pointed out the discrepancy to the CAISO.
c. Indicate when and how SDG&E first became aware of the discrepancy.

28. Table 4.2 on p. 38 of Appendix I-1 shows SDG&E load plus losses with all lines in service (and no Sunrise) of 5467 Mw. Table IV-17 shows 2015 "(Peak Load (90/10)" (including losses) of 5192 Mw. Please explain how much of the 275 Mw discrepancy is due to:

a. 150 Mw of on-peak rooftop solar included in Table IV-17 but not in Table 4.1 of Appendix I-1.
b. 15 Mw of distributed generation included in Table IV-17 but possibly not included in Table 4.1 of Appendix I-1.
c. Other factors (please identify and quantify any such other factors).

28. Please provide, for each of the 9 non-diverged cases shown in Tables 4.1 and 4.2 on pp. 37-38 of Appendix I-1:

a. A list of all overloaded facilities
b. A description of how the need for or lack of need for cross-tripping of Imperial Valley-La Rosita was determined, since such cross-tripping is not mandatory for every SWPL trip under the relevant SPS.
c. Powerflow diagrams for each case covering, at a minimum, San Diego, Imperial, and Orange Counties, plus the relevant portions of CFE.

29. On p. 38 of Appendix I-1, in Table 4.2, comparing the first and next-to-last cases reported, please confirm that:

a. Loads are the same
b. SDG&E internal generation differs by 560 Mw, consisting solely of the Otay Mesa generator being off-line in the first case and running in the next-to-last case.
c. System losses increase by 5 Mw when Otay Mesa is running.
d. SDG&E imports decrease by 555 Mw when Otay Mesa is running, based on 560 Mw of Otay Mesa generation, offset by 5 Mw of increased losses.

30. Please explain how adding 560 Mw of internal SDG&E generation at Otay Mesa to displace imports can increase SDG&E system losses.

31. Appendix I-1, p. 39, indicates that "in the Presence of the Tehachapi Project" then "The Sun Path project mitigates the Imperial Valley - La Rosita 230 kV line contingency overloading." No such sentence occurs in the description of impacts in the absence of the Tehachapi Project.

a. Absent Tehachapi, what is the maximum loading on the Imperial Valley - La Rosita 230 kV line for the 67 contingencies reported (on p. 38 of Appendix I-1) to have been studied?
b. With Tehachapi present, what is the maximum loading on the Imperial Valley - La Rosita 230 kV line for the 67 contingencies reported (on p. 38 of Appendix I-1) to have been studied?

32. Appendix I-1 states on p. 40 that with the Sunrise project, cross-tripping of the IV-La Rosita line after a SWPL outage "is no longer needed." On p. 43 it reports that the same cross trip "may no longer be needed." Please reconcile this apparent discrepancy, explaining which statement is, in SDG&E's opinion, the accurate one, and why.

33. Appendix I-1, p. 27, gives the criteria used for including future CAISO-area transmission projects in the study. Please identify SDG&E's understanding of what criteria were used to determine which future non-CAISO-area transmission projects should be included.

34. Appendix I-1, p. 29, last line, requires a verification "that the proposed project is the least cost solution to solve the identified reliability problem." Please explain whether, in SDG&E's opinion, "least cost" means:

a. Lowest dollar cost, without regard to the size of any associated benefits?
b. Lowest net cost, with both costs and benefits accounted for?
c. Highest benefit/cost ratio, with both costs and benefits accounted for?
d. Something else (if so, explain what).

34. Appendix I-1 describes the Mexico Light Transmission alternative on p. 44. Please confirm that this alternative:

a. Would require no new transmission line construction.
b. Would have minimal costs
c. Would need to operate only when all three of the following occurred simultaneously (or, in the alternative, explain why this alternative would need to be triggered if one of the following did not occur):
(i) SDG&E imports over 2200 Mw (since with imports below 2200 Mw the desired 300 Mw increase in imports could be obtained via south-of-SONGS and Mexico Light would be unnecessary).
(ii) SDG&E load over 4400 Mw (since with load below 4400 Mw, load could be served with G-1 in-area generation plus imports of 2200 Mw).
(iii) SWPL out of service (since with SWPL in service imports could be 2850 Mw)

35. In the Gridview economic modeling with no "Sun Path" project, how many hours per year were SDG&E loads over 4400 Mw while imports to the SDG&E local area were simultaneously over 2200 Mw:

a. In 2010?
b. In 2015?

35. Appendix I-1 says on p. 45 that the "CAISO performed an assessment of the proposed Mexico Light transmission alternative." Please provide SDG&E's understanding of:

a. The date(s) on which the assessment was performed.
b. The name(s) of the person(s) performing the assessment.
c. All documents in SDG&E's possession pertaining to the assessment.
d. The power flow analysis showing an "18% overloading concern" (App. I-1, p. 45).
e. The year in which the "18% overloading concern" occurred.
f. The length of the La Rosita Plant - La Rosita substation 230 KV lines for which Appendix I-1 expresses an "18% overloading concern."
g. The estimated capital cost to upgrade the La Rosita plant - La Rosita substation lines to be able to handle 430 x 1.18 = 508 MVA each on an emergency basis (or, if cheaper, to build a 3rd La Rosita plant - La Rosita substation line). Please estimate within the following cost intervals:
i. $0-1 million
ii. $1-10 million
iii. $10-20 million
h. The maximum loadings on the La Rosita-HRA, La Rosita-Rumorosa, and Rumorosa-HRA 230 KV lines using the Mexico Light alternative.
i. Power flow diagrams for all scenarios in which any CFE transmission lines exceed their rated emergency capacities under the Mexico Light alternative.

36. Appendix I-1 says on p. 45 that the Mexico Light alternative with an additional 300 Mw from Intergen could overload the existing 860 MVA of emergency transfer capability from La Rosita Plant to La Rosita substation by 18%. This corresponds to an overload of 155 MVA. Please indicate SDG&E's understanding of:

a. If the Mexico Light alternative were scaled back to 140 Mw instead of 300 Mw, would that eliminate the "18% overloading concern" for the La Rosita Plant - La Rosita substation lines? If not, why not.
b. If the Mexico Light alternative were scaled back to 140 Mw would it create any reliability issues for other transmission lines on the CFE system in 2010 or 2015? (If the answer is anything other than "no," please explain in detail what those concerns would be and provide power flow diagrams demonstrating those concerns).
c. If the Mexico Light alternative were scaled back to 140 Mw, would it effectively increase the NSIL from 2500 Mw to 2640 Mw?

37. If the Mexico Light alternative provided enough reliability to defer the Sunrise project for one year, please indicate what the cost of Sunrise would be if deferred for one year:

a. In lifecycle NPV terms (as compared to the $2,059 million in 2010 NPV shown in App. I-1, p. 64 for a Sunrise project online in 2010).
b. In investment cost terms, expressed in "2006 real dollars" (as compared to the "$1,113.7M (in 2006 real dollars)" shown on p. 64 of App. I-1 for a Sunrise project online in 2010).
c. In year-by-year revenue requirements (as compared to the year-by-year revenue requirements shown in Tables IV-9 and IV-10 for a Sunrise project online in 2010).

38. Appendix I-1 says at p. 45 that "The CAISO performed an assessment of " UCAN's SONG's Light Transmission Alternative. Please indicate SDG&E's understanding of:

a. The date(s) on which the assessment was performed.
b. The name(s) of the person(s) performing the assessment.
c. All documents in SDG&E's possession pertaining to the assessment.

39. Appendix I-1 asserts on p. 46 that the SONGS Light Alternative "does not increase the South of SONGS path rating (2500 Mw under an N-1 of the IV-Miguel 500 kV line contingency) unless SCE upgrades the Barre-Ellis 230 kV line for the loss of SCE's Del Amo-Ellis 230 kV line. Please indicate SDG&E's understanding of:

a. When was upgrading the Barre-Ellis line identified as the limiting factor on south-of-SONGS deliveries after a SWPL outage?
b. Were any studies performed in 2006 of the south-of-SONGS transfer capability after a SWPL outage if there is a subsequent Del Amo-Ellis outage?
c. In the studies leading to the conclusion that Barre-Ellis is the "current limiting factor for the South of SONGS path,

(i) What emergency line rating was assumed for Barre-Ellis?
(ii) What generation level was assumed for the Huntington Beach 1-4 generators?
(iii) What generation level was assumed for the SONGS 2-3 generators?

40. Appendix I-1 reports on p. 46 that, according to SCE, the Barre-Ellis line is "already constructed with the maximum conductor size for 230 kV tower construction (1195 MVA normal rating and 1613 MVA emergency rating." Please explain SDG&E's understanding of why the power flow base case which the CAISO shared with UCAN (as reported on p. 5 of App. I-1) shows the Barre-Ellis line with a normal capacity of 988 MVA and an emergency capability of no more than 1279 MVA.

41. Please provide a 2010 power flow study, including a power flow diagram covering at least San Diego and Orange Counties, showing flows and any overloads of emergency line ratings with the SONGS Light transmission alternative in place, 2850 Mw of imports into the SDG&E service area via the South of SONGS path, SWPL out of service, Del Amo-Ellis out of service, Otay Mesa out of service, Huntington Beach generators at near-full output (as already shown in the base case supplied to UCAN by the CAISO), Barre-Ellis with an emergency rating of 1613 MVA and all other assumptions the same as the CAISO 2010HS Pre-Project case.

42. Please describe SDG&E's understanding of whether the CAISO requires WECC review and/or approval to change the ratings for intra-CAISO paths such as Path 15 or the South-of-Lugo path?

43. Please describe SDG&E's understanding of whether the CAISO requires WECC review and/or approval to change the ratings for intra-CAISO paths which are also inter-PTO paths, such as Path 26. If yes, please describe the process for WECC review or approval of an inter-PTO intra-CAISO path rating.

44. Appendix I-1 indicates that the maximum possible conductor size for a 230 KV tower would allow no more than an 1195 MVA normal rating and a 1613 MVA emergency rating. The 2010 base case provided to UCAN (as described on p. 5 of App. I-1) shows the Antelope-Pardee 230 KV line (in the SCE service area) with a normal rating of 1574 MVA and an emergency rating of 2123 MVA.

a. Please explain whether the base case is in error?
b. Please explain whether the statement in App. I-1 is in error.
c. Please provide any further explanation needed to resolve the discrepancy.

45. The 2010 base case provided to UCAN (as described on p. 5 of App. I-1) shows the normal rating for the proposed Central-Sycamore Canyon 230 KV lines as 912 MVa and their emergency rating as 1176 MVA.

a. Does this mean the maximum allowable flow over the Central-Sycamore lines would be 1824 MVA normally and 2352 MVA in emergencies?
b. How much less expensive would the San Felipe- Imperial Valley 500 KV segment be if it were sized to transmit 1824 MVA normally/2352 MVa emergency rather than the proposed ratings of 3124 MVA normal/3435 MVA emergency shown in the 2010 base case provided to UCAN?
c. If a smaller conductor size would provide the same reliability benefits at lower cost, why did Appendix I-1 not propose such a smaller size, pursuant to criterion 5 on pp. 29-30 of App. I-1?

46. Please explain SDG&E's understanding of why looping a north of SONGS line into Talega would require ownership of the line to be transferred from SCE to SDG&E?

47. Please confirm that CAISO did not conduct a separate analysis of the SONGS Heavy Alternative. Note that the text simply repeats the conclusions already given for SONGS Light. If there was a separate analysis of SONGS Heavy of which SDG&E is aware, please provide it.

48. Appendix I-1 reports on p. 47 that the Imperial Valley - Miguel (2nd SWPL) alternative has "poor reliability performance, particularly under an N-2 condition for the double Imperial Valley - Miguel 500 KV line outage." Please indicate:

a. How and why would the reliability performance of the 2nd SWPL alternative under an N-2 condition for Imperial Valley-Miguel differ from the reliability performance of the proposed Sunrise project under an N-2 condition for outages of Imperial Valley-Miguel and San Felipe-Central?
b. Would an N-2 outage of Imperial Valley - Miguel for the "2nd SWPL" alternative be a NERC category D outage event? If not, what category would it be?
c. Would an N-2 outage of Imperial Valley-Miguel and San Felipe-Central for the proposed Sunrise project be a NERC category D event? If not, what category would it be?

49. In the 2015 case, for the proposed project, with imports of 3336 Mw under N-1/G-1 conditions as shown in Table 4.2, third column from the right, it is SDG&E's belief that the system be able to withstand a subsequent trip of the Imperial Valley-San Felipe line without overloading the Bannister-San Felipe line.

50. In the 2015 case, for the proposed project, with imports of 3336 Mw under N-1/G-1 conditions as shown in Table 4.2, third column from the right, if a subsequent trip of Imperial Valley-San Felipe also caused Bannister-San Felipe to trip, would the resulting flows trigger a cross-trip of the Imperial Valley-La Rosita line? If not, what would the Mw flows be on the IV-La Rosita line?

51. In the 2015 case, for the proposed project, with imports of 3336 Mw under N-1/G-1 conditions as shown in Table 4.2, third column from the right, if a subsequent trip of Imperial Valley-San Felipe also caused Bannister-San Felipe and Imperial Valley-La Rosita to trip, what is SDG&E's understanding of the resulting Mw flows on the south-of-SONGS path, and would those flows violate any transmission criteria?

52. On p. 48 of Appendix I-1, a transmission alternative consisting of the "LEAPS Transmission Line Only" with phase angle regulation is identified (next-to-last box). Does SDG&E maintain agree that this alternative:

a. Solve San Diego reliability problems?
b. Cost less than $1.14 billion to construct ($2006 dollars)?
c. Still allow Imperial Valley renewable generation to be delivered to the CAISO?

53. Please provide any economic analysis conducted by SDG&E of the "LEAPS Transmission Line Only" option with phase angle regulators, as compared to the proposed Sunrise project. If SDG&E has such an analysis conducted by CAISO, please provide that analysis as well.

54. Regional natural gas prices are discussed on p. 50 of Appendix I-1 but apparently never provided. Elsewhere in its testimony, SDG&E suggests that it does not agree with the natural gas prices used in Appendix I-1 (pp. IV-49, IV-50). The natural gas prices referred to in Appendix I-1 are not the same prices originally posted by the CAISO on its website and subsequently critiqued by UCAN.

a. Please provide the natural gas prices used in developing Appendix I-1.
b. When were the natural gas prices used in Appendix I-1 adopted.
c. Please explain the role that UCAN's critique of the previously used gas prices played in leading the CAISO to change the natural gas prices used in Appendix I-1.
d. When did SDG&E become aware of the differences between the natural gas prices underlying Chapter IV and those underlying Appendix I-1.
e. Did SDG&E ever involved the CAISO that it did not agree with the natural gas prices being used for the analyses underlying Appendix I-1?
f. Please provide all documents in SDG&E's possession regarding the natural gas prices used in the analyses described in Appendix I-1, those used in the analyses discussed in Chapter IV, and the differences between the two sets of natural gas price forecasts.

55. For each of the years 20101 and 2015, for each thermal generator modeled in Gridview, please provide an electronic copy of the Gridview input data regarding thermal generators described at the top of p. 51 of Appendix I-1, namely:

a. Heat rate
b. type of gas used
c. cost of gas used
d. minimum up time
e. minimum down time
f. startup costs
g. shutdown costs
h. ramp rate
i. cost of O&M
j. other data

56. Please describe how Gridview accounts for forced outages and how it accounts for scheduled outages.

57. For each of the years 2010 and 2015, for each thermal generator, please provide:

a. The forced outage rate modeled in Gridview.
b. The scheduled outages modeled in Gridview.

58. Please describe how Gridview accounts for unit commitment.

59. Please describe how Gridview accounts for minimum generation levels for committed units.

60. For each of the years 2010 and 2015, please provide the minimum generation level for committed units in:

a. The SDG&E service area
b. The rest of the CAISO control area
c. The IID control area
d. Arizona
e. New Mexico
f. Nevada
g. Mexico
h. Other areas of the WECC not listed in a-g

61. Appendix I-1 states that Gridview models load by control area using "monthly maximum demand and load profiles." Does Gridview model the CAISO as a single control area, as separate control areas for SCE, PG&E, and SDG&E, or in some other fashion?

62. Please provide the load profile(s) used by Gridview for the CAISO and/or for SDG&E.

63. Tables 6.1 and 6.2 show generation in Arizona increasing 4900 Mw from 2010 to 2015, while peak loads grow only 2263 Mw.

a. What is the basis for expecting net new generation more than twice as large as load growth in Arizona?
b. Taking into account retirements, how many Mw of new generation are assumed in order to produce a net increase in generation of 4900 Mw?
c. How many Mw of the generation assumed to come on line in 2011-2015 have already begun construction?
d. How many Mw of the generation assumed to come on line in 2011-2015 already have air quality and construction permits?
e. How many Mw of the generation assumed to come on line in 2011-2015 already have applied for air quality and construction permits?

64. Tables 6.1 and 6.2 show generation in Mexico increasing 766 Mw from 2010 to 2015 while peak loads grow only 321 Mw.

a. What is the basis for expecting net new generation more than twice as large as peak load growth in Mexico?
b. Taking into account retirements, how many Mw of new generation are assumed in order to produce a net increase in generation of 766 Mw?
c. How many Mw of the generation assumed to come on line in 2011-2015 have already begun construction?
d. How many Mw of the generation assumed to come on line in 2011-2015 already have air quality and construction permits?
e. How many Mw of the generation assumed to come on line in 2011-2015 already have applied for air quality and construction permits?

65. Tables 6.1 and 6.2 show Bonanza ("BONZ") generation decreasing from 4668 Mw in 2010 to 468 Mw in 2015. Please confirm that the 2010 figure is ten times too high, and indicate whether the actual computer input file is correct.

66. Tables 6.1 and 6.2 show generation in Nevada increasing 1676 Mw from 2010 to 2015 while peak loads grow only 728 Mw.

a. What is the basis for expecting net new generation more than twice as large as peak load growth in Nevada?
b. Taking into account retirements, how many Mw of new generation are assumed in order to produce a net increase in generation of 1676 Mw?
c. How many Mw of the generation assumed to come on line in 2011-2015 have already begun construction?
d. How many Mw of the generation assumed to come on line in 2011-2015 already have air quality and construction permits?
e. How many Mw of the generation assumed to come on line in 2011-2015 already have applied for air quality and construction permits?

67. Tables 6.1 and 6.2 list IID as part of the CAISO region.

a. Please admit that IID is not a CAISO PTO.
b. Please indicate whether or not the reported "CAISO Benefit" in Tables 6.4, 6.5, 6.6, 6.7, 6.8, 6.9, 6.10, 6.11, 6.12, and 6.13; the benefits to the "CAISO Ratepayer" shown in tables 6.15, 6.16, and 6.17; and the "Benefits" shown in Table 6.18 of Appendix I-1 include IID as part of the CAISO region. If they do, please provide corrected tables excluding IID.

68. Tables 6.1 and 6.2 show generation in "WAPA L.C" increasing 460 Mw from 2010 to 2015 while peak loads grow only 25 Mw. To the extent that SDG&E can, please

a. What is the basis for expecting net new generation more than 18 times as large as peak load growth for the "WAPA L.C." area?
b. Taking into account retirements, how many Mw of new generation are assumed in order to produce a net increase in generation of 460 Mw?
c. How many Mw of the generation assumed to come on line in 2011-2015 have already begun construction?
d. How many Mw of the generation assumed to come on line in 2011-2015 already have air quality and construction permits?
e. How many Mw of the generation assumed to come on line in 2011-2015 already have applied for air quality and construction permits?
f. How many Mw of the generation assumed to come on line in 2011-2015 is assumed to be generation located in California which would require a CEC permit?

69. Appendix I-1, p. 53, lists three scenarios whose economic impacts were examined. They include Sunpath without LEAPS or Tehachapi, Sunpath with LEAPS and Tehachapi, and Sunpath with Tehachapi but no LEAPS. Please explain SDG&E's understanding of why the scenario of Sunpath with LEAPS but no Tehachapi was not studied?

70. Please admit that if the data was available for the three scenarios studied, then the data was also available to study a scenario with Sunpath and LEAPS but no Tehachapi.

71. On p. 54 of Appendix I-1, are the "Total WECC Production Cost Reduction" numbers for all of the WECC or the non-CAISO part of the WECC?

72. In the economic analysis for 2010 summarized in Table 6.5 of Appendix I-1, in what months of 2010 is the "Sun Path" project assumed to be operational?

73. In the economic analysis inputs shown in Table 6.1 of Appendix I-1, for generation resources which come on line in 2010, in what months of the year 2010 are those generators assumed to be available, in SDG&E's opinion? If the answer varies by generator, please provide a table listing each generator assumed to come on line in 2010 and the month in which it is first assumed on line.

74. In the economic analysis inputs shown in Table 6.2 of Appendix I-1, for generation resources which come on line in 2015, in SDG&E's opinion, what months of the year 2015 are those generators assumed to be available? If the answer varies by generator, please provide a table listing each generator assumed to come on line in 2015 and the month in which it is first assumed on line.

75. From a societal point of view, ignoring transfer payments, what is SDG&E's understanding of how (if at all) the overall economic impacts of "Sun Path" as analyzed in Appendix I-1 are different than the difference between the "total WECC production cost reduction" and the cost to build and operate the "Sun Path" project, as shown on p. 65?

76. Please provide the 2010-2050 NPV, in 2010 dollars, of the "Total WECC Production Cost Reduction" for which 2010 and 2015 values are shown in Tables 6.8 and 6.9 of Appendix I-1, using the same interpolation and extrapolation method for the years 2011-2014 and 2016-2050 as shown on Figure 6.2 of Appendix I-1.

77. For each of the years 2010 and 2015, please provide:

a. The coal prices used in the Gridview analysis.
b. Coal generation (in gwh) with and without "Sun Path."
c. The total WECC-wide cost of generation from coal-fired powerplants with and without "Sun Path," in millions of 2006 dollars.

78. Appendix I-1, p. 55, asserts that "the rest of the WECC gains more than $700M[illion] in production cost savings (benefits) from the added renewable resources in the Salton Sea area in 2015 ...." What is SDG&E's understanding of:

a. Where the $700 million figure comes from.
b. The analytical methodology used to calculate the $700 million figure.
c. Please provide any or all workpapers underlying the $700 million figure.
d. Is it SDG&E's belief that Appendix I-1 claiming that WECC-wide or non-CAISO WECC-wide production costs would be $700 million higher if geothermal development did not occur in the Imperial Valley but the WECC grid was otherwise unchanged?
e. Please identify all Gridview runs performed in the course of developing Appendix I-1 in which the level of geothermal development in the Imperial Valley in 2015 was different from that in the base cases with and without "Sun Path," and the Mw size of that difference.
f. What is SDG&E's understanding of the average production cost (in 2006 dollars per Mwh) for Imperial Valley geothermal generation:

i. In 2010, for each of the six scenarios (3 alternatives, each with and without "Sun Path") underlying Table 6.11 of Appendix I-1?
ii. In 2015, for each of the six scenarios (3 alternatives, each with and without "Sun Path") underlying Table 6.10 of Appendix I-1?

g. What is SDG&E's best estimate of the total cost, (variable cost plus fixed cost) for geothermal generation purchased from the Imperial Valley in 2010, expressed in:

i. 2006 dollars
ii. Nominal 2010 dollars

h. What is SDG&E's best estimate of the total cost, (variable cost plus fixed cost) for geothermal generation purchased from the Imperial Valley in 2015, expressed in:

i. 2006 dollars
ii. Nominal 2015 dollars

i. What is SDG&E's understanding of the quantity of Imperial Valley geothermal generation is produced in 2015 in the Gridview analysis for each of the following 6 cases:

i. The two cases (with and without "Sun Path") underlying the first column of Table 6.10 of Appendix I-1.
ii. The two cases (with and without "Sun Path") underlying the second column of Table 6.10 of Appendix I-1.
iii. The two cases (with and without "Sun Path") underlying the third column of Table 6.10 of Appendix I-1.

j. What SDG&E's understanding of the quantity of Imperial Valley solar generation is produced in 2015 in the Gridview analysis for each of the following 6 cases:

i. The two cases (with and without "Sun Path") underlying the first column of Table 6.10 of Appendix I-1.
ii. The two cases (with and without "Sun Path") underlying the second column of Table 6.10 of Appendix I-1.
iii. The two cases (with and without "Sun Path") underlying the third column of Table 6.10 of Appendix I-1.

k. What SDG&E's understanding of the quantity of Imperial Valley geothermal generation is produced in 2010 in the Gridview analysis for each of the following 6 cases:

i. The two cases (with and without "Sun Path") underlying the first column of Table 6.11 of Appendix I-1.
ii. The two cases (with and without "Sun Path") underlying the second column of Table 6.11 of Appendix I-1.
iii. The two cases (with and without "Sun Path") underlying the third column of Table 6.11 of Appendix I-1.

l. What SDG&E's understanding of the quantity of Imperial Valley solar generation is produced in 2010 in the Gridview analysis for each of the following 6 cases:

i. The two cases (with and without "Sun Path") underlying the first column of Table 6.11 of Appendix I-1.
ii. The two cases (with and without "Sun Path") underlying the second column of Table 6.11 of Appendix I-1.
iii. The two cases (with and without "Sun Path") underlying the third column of Table 6.11 of Appendix I-1.

79. Appendix I-1 says that, or 2010, the base cases include "745 Mw of new renewables whether Sun Path is built or not." Please identify, to the extent SDG&E knows:

a. The specific generators comprising the 745 Mw.
b. Which of those generators are under construction?
c. Which of those generators have CEC permits?
d. Which of those generators have applied for CEC permits?
e. Which of those generators have announced their intention to apply for CEC permits?
f. Whether the "SaltnGeo" 185 Mw geothermal generator listed in Table IV-14 is currently:
i. Operating?
ii. Under construction?
iii. Licensed?
g. How many Mw of the projects listed in the 2010 column of Table IV-14 represent new renewables in the Imperial Valley?

80. Please provide any documents in SDG&E's possession, including but not limited to SDG&E documents, CAISO documents, and e-mails within SDG&E or between SDG&E and the CAISO, identifying discrepancies between the level of new Imperial Valley renewable generation assumed in 2010 and 2015 in the studies underlying Appendix I-1, and the level of new Imperial Valley renewable generation included in Table IV-14.

81. How many Mw of new Imperial Valley renewable generation does SDG&E assume are on line between 2010 and 2015 in the studies underlying Appendix I-1, from:

a. Wind generators
b. Solar generators?
c. Geothermal generators?

82. How many Mw of new Imperial Valley renewable generation does SDG&E assume are on line between 2010 and 2015 in Table IV-14, from:

a. Wind generators?
b. Solar generators?
c. Geothermal generators?

83. According to Appendix I-1, the "Sun Path" project will mitigate market power in 2015 that would otherwise by exercised by non-IOU generation in the SCE and PG&E areas (p. 60). Please explain in detail why SDG&E does or does not agree that:

a. Under the methodology used in Appendix I-1, any benefits calculated for the year 2015 also result in benefits for the years 2011-2014 and 2016-2050, inclusive.
b. Absent the Sunrise project, non-PG&E generators in the PG&E service area will be able to exercise market power in each of the years 2011-2050.
c. Absent the Sunrise project, non-SCE generators in the SCE service area will be able to exercise market power in each of the years 2011-2050.

84. Please describe whether SDG&E agrees that the CAISO's various market intervention mechanisms will be unsuccessful in preventing all exercise of market power in 2011 and after. If not, please explain why not.

85. In Table 6.12, what fraction of the market power mitigation benefits shown in Table 6.12 comes from mitigation of strategic bidding by Sempra-owned generation in the SCER or PG&E service areas?

86. The South Bay combined cycle project is described as a plant with "two gas units and one steam unit" (Appendix I-1, p. 60). What is SDG&E's understanding of why is it treated as a single unit for reliability purposes in Table 4.2 of Appendix I-1?

87. Appendix I-1 says on p. 61 that the LCR Benefit calculation shown in Table 6.14 is based on a "one-in-five years heat wave." The loads and losses shown in Table 4.1 are based on 1-in-10 conditions. Please explain SDG&E's understanding of why the SDG&E load and losses shown in Table 4.1 for 2010 are 4983 Mw with all lines in service (Table 4.1, first column), while the load plus losses shown in Table 6.14 for the year 2010 is only 12 Mw less.

88. Tables 4.1 and 4.2 show that adding "Sun Path" increases losses as well as increasing the SDG&E import limit. Table 6.14 calculates the "Sun Path RMR savings" due to the increased import limit but does not take into account the RMR cost due to Sun Path-caused increased losses. Please provide a revised Table 6.14 which reflects the increased losses due to Sun path shown in Tables 4.1 and 4.2.

89. Please provide the annual nominal costs which underlie the levelized energy revenue requirements shown on Figure 6.2 of Appendix I-1.

90. Please provide in tabular form the annual nominal benefits shown graphically in Figure 6.2 of Appendix I-1.

91. Appendix I-1 quotes a 12/14/05 CPUC filing by SDG&E which states that "SDG&E must procure and additional 2507 GWh in order to achieve the procurement goal by 2010." Since that filing was prepared, how many GWh of contracted renewable energy for 2010 has SDG&E received Commission approval for:

a. Within its own service area?
b. Within the SCE service area?
c. Within the Imperial Valley?
d. Elsewhere?

92. Since 12/14/05, how many GWh of renewable energy for 2010 has SDG&E contracted for which do not yet have CPUC contract approval:

a. Within its own service area?
b. Within the SCE service area?
c. Within the Imperial Valley?
d. Elsewhere?

93. How many GWh does SDG&E expect to be generated from the solar roof capacity shown on Table IV-17:

a. In 2010, where Table IV-17 shows 10 on-peak Mw.
b. In 2015, where Table IV-17 shows 150 on-peak Mw.

94. Appendix I-1 says (bottom of p. 67) that "The Sun Path Project allows California LSEs and especially SDG&E to tap into the renewable power resources in [the Imperial Valley]. Please identify anything in the CAISO tariff which gives SDG&E special rights over and above any other LSE to use the CAISO grid to transmit energy from renewable resources in the Imperial Valley.

95. Appendix I-1 asserts that the Sunrise project "will greatly reduce and may eliminate the need for RMR contracts...."

a. Does SDG&E agree with this statement?
b. Please explain whether reducing the need for RMR will increase or decrease the likelihood that existing units with RMR contracts in the SDG&E service area will be retired?

96. Please explain whether reducing the need for RMR contracts will worsen or improve the prospects for building new generation in the SDG&E service area?

97. In the Gridview studies underlying Appendix I-1, how much (in $/Mwh) does adding the "Sun Path" project increase or reduce the average market price for generators located in the San Diego service area:

a. In 2010?
b. In 2015?

98. Please explain whether higher market prices in the San Diego service area increase or decrease the incentives to build new generation in that area, other things being equal?

99. Appendix I-1 asserts (p. 69) that "The proposed Sun Path project will bring about environmental benefits of reduced airborne emissions in San Diego area from a variety [of] factors." To the extent that SDG&E knows:

a. Are "Green House Gas emissions" (Appendix I-1, p. 69) a local problem or a global problem?
b. Does SDG&E believe that the Sunrise project will reduce carbon dioxide emissions WECC-wide?
c. For each of the years 2010 and 2015, for each of the two cases (with and without "Sun Path" which underlie the first column of results in Tables 6.4 and 6.5, please provide:

i. The total Btu of coal consumed in the WECC.
ii. The total Btu of natural gas consumed in the WECC.
iii. The total gwh of coal-based generation in the WECC.

100. Appendix I-1 concludes that the "Sun Path Project ... benefit exceeds its cost" (p. 70). Please indicate:

a. What is SDG&E's understanding of the first year in which the annual nominal benefit exceeds the annual nominal (not levelized) cost for the base cases with and without "Sun Path" summarized on the first line of Table 6.18?
b. What is SDG&E's understanding of the first year in which the cumulative NPV of the net benefits of building Sun Path (benefits minus costs, for the base cases summarized on the first line of Table 6.18) from 2010 to that year is greater than zero?

101. Please identify any facts asserted in the CAISO study with which SDG&E disagrees or believes to be incorrect, other than those already identified in responses to the questions above.