UCAN's FIRST SET OF DATA REQUESTS
05-12-014

Please supply, in Excel format, annual SDG&E load data (8760 hourly loads):

For the most recent 12 month period available
Consistent with the peak load forecast for 2010 used in the Sunrise application

Please supply copies of all correspondence, written or electronic, between SDG&E (or any SDG&E contractor) and any employee or contractor of Anza-Borrego Desert State Park (ABDSP) regarding

the Sunrise Powerlink project
availability of transmission routes at any voltage above 50KV through ABDSP
any areas of ABDSP which are or might be unacceptable for use as transmission corridors for transmission lines of 100 KV or above

Please supply copies of any internal correspondence within SDG&E or between SDG&E and any SDG&E contractor regarding:
availability of transmission routes at any voltage above 50KV through ABDSP
any areas of ABDSP which are or might be unacceptable for use as transmission corridors for transmission lines of 100 KV or above
Communications with employees or contractors of ABDSP in 2004-05.

Please supply any studies containing powerflow diagrams performed by or for SDG&E in the last 24 months which represent the SDG&E system with the Miguel-Mission #2, Miguel 500/230 KV transformer #2, and Otay Mesa-Sycamore Canyon 230 KV transmission lines in service, and indicate:

The nature of the study (e.g., system interconnection study for a San Diego County generation project)
The date of the study
The distribution of the study (e.g., internal only, sent to FERC, sent to CPUC, etc.)
The year of SDG&E operation which was simulated in the study
The SDG&E system peak load used in the study
Whether the study included Sunrise Powerlink in operation

For any studies which would be responsive to #4, but which SDG&E refuses to produce on grounds of confidentiality, please identify:

The nature of the study (e.g., system interconnection study for a San Diego County generation project)
The date of the study
The year of SDG&E operation which was simulated in the study
The SDG&E system peak load used in the study
Whether the study included Sunrise Powerlink in operation
The reason for SDG&E's claim of study confidentiality (e.g., permission to release not yet obtained from the counterparty in the case of a system interconnection study)

Please provide all powerflow studies performed by SDG&E as part of the process of determining the preferred location for what is now known as the Sunrise Powerlink. This response should include all the analyses referred to in various SDG&E submissions to the ISO's STEP group in which SDG&E analyzed alternative transmission options to Sunrise which would have served SDG&E via SCE, via CFE, or via the Miguel substation.

Please identify all new generation proposals within the current SDG&E service area of which SDG&E is currently aware that SDG&E believes could be in commercial operation by 2012. At a minimum, the response to this request should reference the Palomar, Otay Mesa, Lake Hodges, South Bay repower, and Encina repower proposals. For each proposal, please indicate, to the extent SDG&E knows:

Project proponent
Planned commercial operation date
Planned permit approval date
Size (Mw)
Technology
SDG&E's estimate of the likelihood that the project will ever enter commercial operation.

SDG&E has identified potential routes through ABDSP along routes S-2 and California Highway 78. Please confirm that there are parts of both of these routes where ABDSP has designated wilderness along both sides of the roadway, so that the Sunrise Powerlink would have to be built within a designated wilderness area.

If you do not so admit in response to question #8, please provide a map of ABDSP, at a scale of 1 mile to the inch or more detailed, showing all designated wilderness areas in the park, and labelling the width of the non-wilderness corridor in areas where there is wilderness on both sides of either S-2 or Hwy. 78.

Does SDG&E believe the cost of Sunrise is relevant to the need for Sunrise to be built? If not, why not?

Does SDG&E believe the location of Sunrise would affect its cost?

Does SDG&E believe that proximity to wilderness areas, or re-routing to avoid wilderness areas, will affect the cost to build the Sunrise Powerlink? If not, why not?

Please provide SDG&E's most recent forecast of peak demand reduction due to AMI for each of the years 2009-2015. Please indicate the source of this forecast and provide a copy of the source documents (e.g., workpapers in SDG&E's AMI business case filing with the CPUC).

Please indicate whether the load forecasts included in the Sunrise Powerlink application and testimony include peak demand reductions due to AMI, and if so indicate the Mw reduction for each such forecast.

Please provide:

The annual forced outage rate for the Southwest Powerlink for each of the last 10 years.
The annual number of hours that SWPL was out-of-service due to forced outage(s).
An explanation of any years in which the response to part (b) of this question is different from 8760 hours per year (or 8784 hours per year in leap years) times the response to part (a) of this question.
Operating logs describing each SWPL forced outage during the last 5 years.

For each of the last 10 years, please provide:

The number of hours per year that SDG&E loads were within 15% of the annual peak hourly load
The number of hours per year that SDG&E loads were within 15% of the annual peak hourly load, and SWPL was out of service due to a forced outage
The number of hours per year that simultaneous imports into the SDG&E service area over all in-service transmission facilities exceeded 2500 Mw
The maximum import into the SDG&E service area over all in-service transmission facilities during hours when SWPL was out of service (for any reason).
SDG&E's maximum annual hourly load
SG&E's 176th largest hourly load (i.e., the load which was only exceeded in 175, or 2 percent, of the hours of the year).

Please provide any interconnection studies SDG&E has performed for a repowered or reconfigured South Bay Power Plant for operations in 2009 or beyond.

Please provide copies of any documents in SDG&E's possession which are less than one year old and refer to proposed repowering or reconfiguring of the South Bay Power Plant to allow generation of electricity at the South Bay site beyond the expiration of the current South Bay Powerplant lease in approximately 2009.

Please provide any documents in SDG&E's possession which are less than one year old and refer to the status of any proposed 500 KV transmission line interconnecting the SCE and SDG&E service areas.

Please provide all workpapers for the Sunrise application and testimony.

Please provide an unredacted version of the Sunrise testimony.

Please confirm that economic modeling of the Sunrise proposal has been performed for SDG&E by ABB using the Gridview model, and provide a copy of the contract between SDG&E and ABB under which the Gridview model was used to evaluate the Sunrise proposal;

Please provide copies of all correspondence between SDG&E and ABB relating to the Sunrise proposal and/or the use of Gridview to model SDG&E's transmission system.

Please provide copies of any work products provided by ABB to SDG&E as part of its analysis of the Sunrise project;

Please provide copies of any data inputs or other modeling instructions provided by SDG&E to ABB, or vice versa, in conjunction with ABB's work for SDG&E regarding the Sunrise proposal.

Please provide a complete description of how SWPL outages trigger cross-tripping of Path 45 facilities, including but not limited to:

a description of which SWPL contingencies trigger cross-tripping
a description of which Path 45 facilities are subject to cross-tripping (SDG&E says Imperial Valley-La Rosita on p. III-5)
a description of the timeframe within which cross-tripping must be accomplished
a description of the necessary conditions which must exist before restoring service over cross-tripped facilities is permitted
a description of the minimum time required for restoration of service over cross-tripped facilities once the required conditions have been met.

Please provide a map of the Path 45 facilities showing their actual locations and those of nearby (within 20 miles) grid facilities (other transmission lines and powerplants; only transmission lines at 230 KV and above need be shown)

Please describe SDG&E's understanding of the feasibility of creating new interconnections between the CFE grid and the Sempra and Intergen generators which are currently connected to the Imperial Valley substation, indicating at a minimum:

the cost of interconnecting each of the generators to CFE.
whether it would be feasible to have one or both of the generators simultaneously connected to both CFE and Imperial Valley.
for each of the generators, whether it would be feasible to have that generator connected to only Imperial Valley normally, with a normally open connection to CFE which could be energized after an interruption of the Imperial Valley interconnection without interrupting generation at the powerplant.
what the cost would be of the breakers and other equipment required to allow a normally open interconnection to CFE which could be used immediately after an interruption of the existing interconnection to Imperial Valley.
for each of the generators, whether it would be feasible to have that generator connected to only CFE normally, with a normally open connection to Imperial Valley which could be energized after an interruption of the CFE interconnection without interrupting generation at the powerplant.
what the cost would be of the breakers and other equipment required to allow a normally open interconnection to Imperial Valley which could be used immediately after an interruption of the new interconnection to CFE.
What fraction of the output of each generator normally flows over the CFE grid to the U.S. today, re-entering Mexico from Imperial Valley substation via Path 45, and then departing the CFE grid via Path 45 at Tijuana?

Please provide your most recent ISO-approved electric transmission grid expansion plan.

With regard to communications between SDG&E and IID regarding interconnections between IID and the Sunrise project or any other non-SWPL 500 KV transmission project,

Please provide all such communications since the beginning of 2005.
Does SDG&E intend to route, design, and build Sunrise so as to facilitate an interconnection with a future 500 KV IID transmission line, at or near the existing San Felipe substation?
Does SDG&E intend to route, design, and build Sunrise so as to facilitate an interconnection with a future 230 KV IID transmission line, at or near the existing San Felipe substation using a 230/500 KV transformer?
Does SDG&E intend to own any substations along the route of the Sunrise project which provide interconnections to Sunrise?
Does SDG&E's modeling of the economics of the Sunrise project include any other new 500 KV facilities within the IID service area or connecting to it, such as a possible 500 KV transmission line from LADWP to the Coachella Valley?
Does SDG&E's modeling of the economics of the Sunrise project include the effects of any interconnections between IID and the Sunrise line, whether at a future San Felipe site or anywhere else?

With regard to communications between SDG&E and Duke Energy North America (DENA), or any DENA affiliate, regarding operation of a powerplant at the South Bay site beyond the year 2010,

Please provide copies of all such communications since the beginning of 2005.
Please indicate how such communications were taken into account in analyzing the amount of generation at the South Bay site which would be included in the analyses included in SDG&E's Sunrise testimony.
Please indicate SDG&E's most current expectations with regard to the probability that there will be generation at the South Bay site after 2010.

Please provide a copy of SDG&E's most recent procurement plan to acquire renewable resources.

With regard to communications in the last 12 months between SDG&E and proponents of the LEAPS project,

Please provide copies of all such communications since the beginning of 2005.
Please provide a copy of the System Interconnection Study (SIS) for this project as soon as it is completed.
Please provide a copy of SDG&E's 1/13/06 FERC protest of the LEAPS project

SDG&E testifies that "Sunrise Powerlink will also allow for the future retirement of older, less-efficient gas-fired generating units located in the San Diego area." (p. I-13).

Please identify each unit which SDG&E expects to be allowed to retire as a result of Sunrise. For each unit identified, please indicate its age (measured in years) and its efficiency (measured by its heat rate in MMBtu/kwh) and indicate where it ranks compared to the other "gas-fired generating units in the San Diego area."

SDG&E testifies regarding the Stirling Energy contract that "Commercial operation of this facility must begin no later than 2010. ... the contract delivery point for all three phases of the project is dependent on the timing of SDG&E's construction of the Sunrise Powerlink." (p. I-14). Please indicate:

Does "2010" mean the beginning of 2010, the end, or some point in the middle?
How many Mw must be in commercial operation ...no later than 2010" for Stirling to meet its obligations to SDG&E?
What are SDG&E's options, obligations, and intentions with regard to the Stirling project if the required number of Mw are not in operation by 2010?
What is the contract delivery point for generation from Stirling prior to the planned Sunrise operation date of mid-2010?
How many Mw of Stirling generation does SDG&E expect to be in service prior to mid-2010?
Does SDG&E expect to be able to take delivery of Sterling generation prior to mid-2010?
What is the Stirling delivery point after mid-2010 if Sunrise is not yet in operation?
What is the Stirling delivery point after operation of Sunrise?
Is SDG&E's right to take deliveries from Stirling Energy contingent upon the completion of the Sunrise project by any specific date or via any specific route? If so, please explain.
Is SDG&E in any way obligated to ever take deliveries from Stirling Energy at any point on the Sunrise line, assuming it is built, other than the Imperial Valley substation? If so, explain the obligation and the circumstances which would trigger it.
Please identify the Stirling delivery point after mid-2010 if Sunrise is not approved or built?
Please indicate whether there is any contingency built into the SDG&E energy contract with Stirling for the event that Sunrise is not approved or built for any reason?

Please provide an amended version of the graph on p. I-16 which:

Extends to 2016, consistent with the RMR data on p. V-7
Shows annual costs with the Miguel-Mission upgrade but no other "major transmission and generation initiatives."
Shows annual costs with the Miguel-Mission upgrade and the Palomar plant, but no other "major transmission and generation initiatives."
Shows annual costs with the Miguel-Mission upgrade and the Palomar and Otay Mesa plants, but no other "major transmission and generation initiatives."
Reconciles the $50 million figure shown for the year 2010 "with major transmission and generation alternatives" with the $77 million figure given for the same year on p. V-7 for the case with Sunrise constructed.
Please provide all the analysis and workpapers used to generate the table in chapter I, page 16, of the SDG&E filing

SDG&E testifies that "RMR ... may not continue ... [but] the cost of meeting such demand must continue in one form or another." (p. I-16, fn. 28). Please explain:

how SDG&E customers would incur RMR-like costs after implementation of the ISO's MRTU project.
why MRTU will not reduce the magnitude of those costs.
The "form" in which RMR-like costs will occur after MRTU is implemented.

SDG&E testifies that Sunrise will "augment existing transfer capability between the desert Southwest and California load centers ... reduce congestion costs and losses ... [and] among the generating companies that supply power to California, put downward pressure on energy costs." (p. I-17). Please provide:

A description of all modeling performed by or for SDG&E for this proceeding which assumed that Arizona or Nevada generators are currently selling to California at prices above their costs, so that they are capable of reducing their selling price.
All modeling results produced as part of SDG&E's Sunrise analyses in which expected selling prices for generation from Arizona or Nevada with Sunrise in service were lower than selling prices without Sunrise.
All modeling results produced as part of SDG&E's Sunrise analyses in which congestion costs for generation delivered to California from Arizona or Nevada with Sunrise in service were lower than congestion costs for generation delivered to Californa without Sunrise in service.
The expected transfer capacity between Arizona/Nevada and California, with and without Sunrise, and an explanation for any change, in light of the fact that Sunrise will not connect to either Nevada or Arizona.

SDG&E testifies that Sunrise will be 75-105 miles long. (p. II-3).

What route would a 75-mile long Sunrise line follow?
What route would a 105-mile long Sunrise follow?
How many miles of 230 KV lines would be required for a 75-mile long Sunrise?
How many miles of 230 KV lines would be required for a 105-mile long Sunrise?
Please confirm that the 75 and 105 mile references are for the 500 KV portion of the Sunrise project only.

SDG&E testifies that Sunrise will be built to carry more than 2000 Mw "in anticipation of future needs." (p. II-4). In regards to this testimony, please state:

What thermal rating is needed for Sunrise to be able to provide reliable service after a SWPL outage under 2010 load and resource conditions?
What thermal rating is needed for Sunrise to be able to provide reliable service after a SWPL outage under 2016 load and resource conditions?
What "future needs" does SDG&E have in mind that will require thermal capabilities in excess of 2000 Mw for Sunrise?
What is the "thermal powerflow capability" of the existing SWPL, DPV1, and Devers-Valley-Serrano 500 KV lines?

SDG&E testifies that the new 230 KV lines will be 35-51 miles. (p. II-5)

For the 35 mile case, how many miles will be between Penasquitos and Sycamore Canyon?
For the 35 mile case, where will the Central substation be located?
For the 51 mile case, how many miles will be between Penasquitos and Sycamore Canyon?
For the 51 mile case, where will the Central substation be located?
Please confirm that the 35 and 51 mile figures refer to miles of transmission corridor, and not transmission line miles.

SDG&E testifies that Sunrise will allow 4000+ Mw of imports to SDG&E under N-0 conditions (p. II-5), and 3500 Mw "without violating the CAISO's G-1/N-1 reliability requirement." (p. III-4). Please state:

Does SDG&E intend to ever schedule 4000 Mw or more of imports during N-0 conditions if Sunrise is built?
Has SDG&E's modeling of Sunrise benefits in this case assumed that, with Sunrise built, SDG&E could and would import up to 4000 Mw under N-0 conditions?

If SDG&E was importing 4000 Mw under N-0 conditions, and then N-1/G-1 contingencies occurred such that imports had to be reduced to 3500 Mw, please state:

How much time would SDG&E have under the relevant operating rules to reduce its imports to 3500 Mw?
What internal SDG&E generation would be ramped up to replace the lost 500 Mw?
Does this mean that whenever imports are above 3500 Mw, post-Sunrise, the SDG&E area will have to have spinning reserves or quick start units available to cover the differences between 3500 Mw and the actual level of imports?
Did any of SDG&E modeling of the Sunrise project account for the cost (or opportunity cost) of any increased reserve requirements associated with increasing the difference between N-0 and N-1/G-1 import limits?

SDG&E testifies that it did not adjust the Sunrise "scope" to mitigate overloads resulting from "double outages" or "common corridor contingencies" (p. II-7). Please state:

Would an outage of the proposed two 230 KV lines from Central to Sycamore Canyon be considered a double outage or a single outage?
Are those two lines proposed to be on a common tower?
Would an outage of those two lines be considered a "common corridor contingency"?
What is the expected frequency of an outage of both Central-Sycamore Canyon lines?

SDG&E testifies that Sunrise is expected to cost $1.015-1.437 billion to construct, and $10 million per year (in 2010 dollars) to operate during its 40 year life. (p. II-10). In regards to this assertion, please state:

Does the $10 million per year figure include all capital additions over the 40 year period?
What additional capital costs, if any, does SDG&E expect over the life of the line after initial construction is complete?
What is the basis for the $10 million figure?
What inflation rate was applied to the $10 million figure for the years 2011-2049?
What have the annual O&M costs been for the SWPL project, expressed in 2010 dollars, for each year of its life to date?
What have the annual revenue requirements been for the SWPL project, for each year of its life to date, associated with post-commercial operation capital additions?

SDG&E testifies to the annual revenue requirements for Sunrise for each year from 2008-2049 (Table II-1). In regards to these revenue requirements:

Please provide all the workpapers for this table.
What rate of return on rate base underlies the table?
What rate of return on equity underlies the table?
Why are capital costs in 2047 lower than in either 2046 or 2048?
Why is the total revenue requirement greater than the sum of the O&M revenue requirement and the capital recovery revenue requirement in almost all years?
Have tax effects from differing CPUC and IRS depreciation schedules been taken into account?
What discount rate and/or inflation rate assumptions were used to convert the annually-varying figures in Table II-1 into the figures of $153 million per year or $210 million per year on p. II-10?
What year dollars are the levelized figures on p. II-10 expressed in?
Do the levelized figures on p. II-10 account for the 2008-09 costs in Table II-1?

SDG&E testifies that the CAISO's G-1/N-1 criteria is more stringent than the NERC/WECC reliability criteria (p. III-2, fn. 3), and provides tables of Mw surpluses/deficits in 2006-2015 under various scenarios, calculated based on the CAISO G-1/N-1 criteria (Tables III-1, III-2). Please provide versions of tables III-1 and III-2 showing the numbers which would apply using NERC/WECC criteria.

SDG&E testifies that its Sunrise reliability analysis "is addressing options to satisfy local service area loads..." (p. III-3). Is it SDG&E's contention that its entire service area, including the Orange County portion of its service area, is a "local" area with "local load serving concerns"?

SDG&E testifies that "the CAISO's N-1/G-1 requires that reliability criteria requires that there be no loss of load, thermal overloads, or unacceptable voltages in the event that (a) the largest generator in the local area and the most critical transmission element are already out of service, and (b) there is a subsequent outage of another transmission element." (p. III-2). Is it correct that this description actually involves loss of two transmission elements in succession as well as the largest generator during peak month under 10/90 load condition, and is thus accurately termed "G-1/N-1-1" in Table III-2 on p. III-4?

SDG&E testifies that with Sunrise in service it will be able to import 3500 Mw with an outage of the Imperial Valley-Miguel segment of SWPL followed by an outage of the North Gila-Imperial Valley segment of SWPL (p. III-5). In regard to this assertion:

Is it SDG&E's position that these two SWPL segment outages constitute "the most critical transmission element" and "another transmission element" in accordance with the CAISO's N-1/G-1 criteria as described on p. III-2?
Wouldn't an "outage of the Imperial Valley-Miguel 500 KV line, system readjusted, followed by the outage of" the Sunrise Powerlink also constitute an outage within the meaning of the CAISO's G-1/N-1 reliability criteria?

Assume the following: a combined import of 3500 Mw, the outage of the Imperial Valley-Miguel 500 KV line, system readjusted, followed by the outage of the Imperial Valley-Central (Sunrise) line.
Would that situation result in flows that are at or below 100% of the emergency rating of all remaining in-service transmission elements.
Would that situation result in all voltages within permissible limits?
In that situation, how much of the 3500 Mw import would flow be on each of the remaining lines into the SDG&E area, across paths 44 and 45?

In calculating that SDG&E could import 3500 Mw without violating the CAISO's G-1/N-1 criteria, why did SDG&E assume the phrase "another transmission element" of that criteria should refer to the North Gila-Imperial Valley, and not any other line?

SDG&E testifies that with the current transmission network, the maximum import capability under the N-1/G-1 criteria is 2500 Mw, based on an outage of the Imperial Valley-Miguel component of SWPL, cross-tripping of the Imperial Valley-Rosita line, and then a subsequent outage of a SONGS-Talega line. SDG&E further testifies that the constraint which prevents above 2500 Mw under this situation is "thermal limitations on SCE's Barre-Ellis line (p. III-5). In regard to this testimony, please state:

What studies serve as the basis for SDG&E's testimony?
On what dates were those studies done?
What conductors are on the Barre-Ellis line and what is their thermal limit?
How long is the Barre-Ellis line?
What would it cost to reconductor the Barre-Ellis line with conductors with a higher thermal limitation?
If Barre-Ellis were reconductored, what would be the next constraint in N-1/G-1 imports into San Diego?
If Barre-Ellis were reconductored, what would the new G-1/N-1 import limit into SDG&E be, instead of 2500 MMw?
Has SDG&E ever proposed upgrading Barre-Ellis in the 8 years since the ISO began operating? If not why not?
Has SCE or the ISO ever proposed upgrading Barre-Ellis in the 8 years since the ISO began operating?
Please provide any studies in SDG&E's possession of upgrades to the SCE or SDG&E transmission systems at the 230 KV level or below which would increase the existing 2500 Mw G-1/N-1 import limit into SDG&E.
Is it correct that if one of the SCE-SONGS lines was looped into Talega substation, that would create a sixth SONGS-SDG&E transmission line and a third SONGS-Talega line?
What would looping an existing SCE-SONGS line into Talega substation require in terms of line-miles of new 230 KV line and in terms of dollars?
What would the creation of a third SONGS-Talega line do to the existing 2500 Mw G-1/N-1 import limit for SDG&E?
Is it correct that the four existing SCE-SONGS 230 KV lines all physically cross (without touching, of course) SDG&E's Talega-Escondido 230 KV line?
Is it correct that by cross-connecting an existing SCE-SONGS line with the existing Talega-Escondido line, a 6th SONGS-SDG&E line could be created, from SONGS to Escondido, while one of the existing SCE-SONGS line would be reconfigured as an SCE-Talega line?
What would such a line reconnection cost?
What would the creation of a new SONGS-Escondido line and the retermination of an existing SCE-SONGS line at Talega do to the existing 2500 Mw G-1/N-1 import limit for SDG&E?

SDG&E testifies that "the CAISO has expressed uncertainty whether these [demand response] programs would be triggered during the period of time covered by the G-1/N-1 contingencies that forms [sic] the basis for application of its reliability criteria." (p. III-iv).

Please identify the "period of time" that is allowed for system readjustment after an N-1/G-1 contingency to be ready for the next contingency? Please provide the basis for your answer.

If a demand response program produces results within the allowable time period, can it be counted as a means of system readjustment?

Please provide any instances of which SDG&E is aware in which the ISO has ever said that quick-response demand response programs should not be counted as a means of system readjustment after an N-1/G-1 contingency.

Please state whether it is SDG&E's position that ISO "uncertainty" means that demand response programs should be ignored?

SDG&E testifies that in July 2004 it forecasted self-served load and self-generation of a variety of types to total 6 Mw by 2006 (pp. III-v, III-vi.)
What is the current amount of self-served load and distributed generation in the SDG&E area?
What is SDG&E's current forecast for self-served load and distributed generation by the summer of 2006?

SDG&E testifies that its share of solar installations statewide would be about 10% if "potential installations are spread uniformly throughout the state." (p. III-vi)

Does SDG&E in fact expect future solar installations to be spread uniformly throughout the state?
Does SDG&E agree with the protest in this proceeding which suggested that SDG&E may get 15% of future solar installations, and if not, why not?

SDG&E testifies that it has typically used the CAISO's figures for the "available capacity within the San Diego area for purposes of establishing RMR contract requirements" as its basis for knowing "the quantity of exisitng in-area resources that can be relied upon for meeting the CAISO's reliability criteria." (p. III-vii).

In this filing, are SDG&E's numbers regarding exisitng capacity taken from CAISO numbers in the CAISO's RMR analyses?

Please state whether SDG&E agrees that if there are discrepancies between SDG&E's Sunrise testimony and CAISO data regarding existing generation, and the CAISO data comes from a CAISO analysis of SDG&E reliability, that the CAISO numbers are appropriate to use? If you disagree, please explain why.

SDG&E testifies that the CAISO "has not been willing to count wind capacity for purposes of satisfying its G-1/N-1 reliability requirement absent historical evidence that some portion of wind capability can be relied upon during peak periods." (p. III-viii). Does this man that the CAISO is willing to count wind capacity to the extent that there is "historical evidence that some portion of wind capability can be relied upon during peak periods"?

Please state whether SDG&E knows how much "historical evidence" the CAISO requires.

By 2010, does SDG&E expect to have enough "historical evidence" to show the CAISO that the Kumeyaay project produces wind capability which "can be relied upon during peak periods"?

Based on evidence currently available to it from meteorological data or from wind generation at existing facilities, what does SDG&E (not the CAISO) expect the on-peak capacity of the Kumeyaay wind farm to be?

When SDG&E made the decision to contract with the Kumeyaay project, what assumptions did it make in evaluating the proposed contract about the on-peak capacity that the project would provide?

How much installed Mw of new wind generation other than Kumeyaay does SDG&E intend to bring into service each year from 2006-16?

Based on evidence currently available to it from meteorological data or from wind generation at existing facilities, what does SDG&E (not the CAISO) expect the on-peak capacity of that non-Kumeyaay wind generation to be?

For any non-Kumeyaay wind project(s) that are already under contract, when SDG&E made the decision to contract with those projects, what assumptions did it make in evaluating the proposed contract(s) about the on-peak capacity which the project(s) would provide?

SDG&E's testimony contains a series of tables, each containing the same forecast of SDG&E area load in 2006-2015 under "90/10" load assumptions (Tables III-3 to III-8, pp. III-ix to III-xi). Please confirm that this is a load forecast for all LSE's within SDG&E's transmission service area, including those whose retail loads are not served by SDG&E.

How much do the annual 90/10 load forecast values in SDG&E's tables differ from the annual 90/10 load forecast values in the CEC's most recent load forecast?

Does SDG&E believe the CPUC should use its 90/10 load forecast rather than the CEC's in evaluating the Sunrise proposal? If the answer to the previous subpart was "yes," please provide SDG&E's reasons for its belief? If the answer is "no", please provide amended tables reflected the CEC's most recent 90/10 forecast for the SDG&E planning area.

Please provide the average LMPs, differentiated by Desert South West and California load center regions (SDG&E, SCE, PG&E service areas), with and without Sunrise Power link scenarios.

Please provide all the workpapers behind the calculation of the congestion cost savings of $96 million and its detailed breakdown for each year of the study. In particular please include the number of hours per year in which each monitored path and interface are congested.

Please provide power flows (MW) on the SWPL for the years 2010 through 2015, with and without Sunrise, for all the hours in the month of August.

Please explain why SDG&E has used more stringent reliability criteria than NERC; which allows load drop for G-1/N-1 contingencies.

Please state whether SDG&E believes that its Gridview model results, and the CAISO LMP 3 study results for 2007, are consistent? If not, explain why not. If yes, explain why significant congestion reduction in the CAISO LMP 3 study is consistent with SDG&E's assumption of large congestion and RMR savings arising from the increase in the congestion-related RMR needs.

Please state whether all RMR units in California are modeled as RMR units in SDG&E's analysis?

Please state whether the out of merit operation of the RMR units modeled? If please provide documents showing how this modeling is done. If not, then please describe the basis for the $114 million RMR savings?

Please provide the hours and MWh of RMR operation under the with and without Sunrise scenarios.

Please describe how the above-market-costs of the RMR units are estimated? Show all the supporting analysis.

Please provide the basis for the $67/Kw-yr estimate.

Please state whether there is any historical RMR data used to calculate the RMR generation/costs in this analysis. If so, please state whether the historical RMR cost data was used to forecast future RMR costs.

Please explain why congestion rent/cost has increased with the addition of the Sunrise Powerlink (Table V - 6)?

Please state whether the costs associated with the IID's internal transmission upgrades necessary to accommodate the higher import into the California load centers? Are these costs included in the cost of the Sunrise Powerlink? If not, why not?

Please provide all work papers, unit by unit, associated with the calculation of RMR savings under the different alternatives in table VI-3.

Please provide a comparison of the technical criteria for the Mexico alternative (Path 45) to the Sunrise Powerlink referenced by SDG&E representatives at a May 24, 2005 workshop on transmission hosted by SDGE for the San Diego Area Governments (SANDAG) Energy Working Group, Resources Subcommittee. Specifically, SDGE had identified the Mexico double 230 kV option as meeting "most technical requirements" as an alternative to the 500 kV Valley-Rainbow transmission line in the CPCN alternatives analysis prepared for that project in November 2003. SDGE representatives claims to have prepared a comparative table showing the technical criteria utilized in 2003 to identify the Mexico double 230 kV option as meeting most technical requirements and later to reject this same option as an alternative to the Sunrise Powerlink.

SDGE identifies G-1 as the complete loss of the 541 MW Palomar Energy Project. G-1 later becomes loss of the entire 561 MW Otay Mesa Power Project. Please provide any analysis that has been performed on the cost to retrofit Palomar to include bypass stacks or dilution air blowers to allow simple-cycle operation of the gas turbines if the steam turbine is out-of-service.

Please provide any and all documents that relate to the relative frequency of unscheduled gas turbine and steam turbine outages at combined-cycle powerplants located in San Diego County.

Please provide supporting documentation for the contention - advanced by SDG&E and supported by the CEC's Imperial Valley Study Group that: "The IVSG will focus first on evaluating alternatives capable of exporting 2,000 MW of renewable generation from the Imperial Valley. After it has determined configurations capable of transporting the full 2,000 MW it will then segment the development into phases."

Please provide any documents in SDG&E's possession that validate an estimate of remaining untapped geothermal resources in the Imperial Valley area of approximately 2,000 MW.

SDGE states it evaluated eighteen transmission alternatives prior to reducing these alternatives to three variations of the Sunrise Powerlink. Provide the identify and role of any non-SDGE staff involved in reducing the original 18 alternatives to the final three options.

In letter sent to CPUC Commissioners dated January 26, 2006, Debra Reed indicated that:

 

In regards to this clause from the letter, please provide any and all written documents, memos or reports pertaining to the analysis of the moderated discussions and the anonymous interviews with leaders. Please include in these documents:
Identification of the 30 leaders, representatives and officials as well as those who participated in the moderated discussions.
Identification of those who conducted the interviews/discussions
The dates of these interviews
Any handouts or information given to participants in the interviews or moderated discussions.

In the same letter, SDG&E indicates they held numerous open houses and additional meetings on the proposed Powerline. Please state:
Whether there was any organized presentations of alternatives to the powerline proposal. If so, please provide documents that describe those alternatives.
Whether individuals attending the meetings were given an opportunity to present arguments against the proposal. If so, please provide documentation showing that the opportunity was given to participants.
Whether individuals attending the meetings did present arguments against the proposal. If so, please provide documentation showing that the participants did present that point of view at the meetings.