Review Of Phase 1 A


  • SP-15 - South of Path 15 -- essentially designates the southern california area south of "path 15" transmission lines that link the two areas.



                                                      )  EVIDENTIARY
                                                      )  HEARING
               Order Instituting Investigation on     )
               the Commission’s Own Motion into the   )
               Rates, Operations, Practices,          )  Investigation
               Services and Facilities of Southern    )  12-10-013
               California Edison Company and San      )
               Diego Gas and Electric Company         )  Application
               Associated with the San Onofre         )  13-03-005
               Nuclear Generating Station Units 2     )
               and 3.                                 )  Application
                                                      )  13-03-013
                                                      )  Application
               And Related Matters.                   )  13-03-014
                                                      )  Application
                                                      )  13-01-016

                                REPORTER'S TRANSCRIPT
                              San Francisco, California
                                   August 5, 2013
                                  Pages 1277 - 1431
                                      Volume - 7

               Reported by:  Michael J. Shintaku, CSR No.8251
                             Gayle Pichierri, CSR No. 11406

                               SAN FRANCISCO, CALIFORNIA


COLIN CUSHNIE Direct Examination By Mr. Weissmann 1283

Cross-Examination By Mr. Shapson 1284

Cross-Examination By Mr. Freedman 1305

7 Cross-Examination By Mr. Geesman 1342

Cross-Examination By Ms. George 1356

8 Cross-Examination (Continued) By Mr. Shapson 1411

9 Examination By ALJ Dudney 1413

Redirect Examination By Mr. Weissmann 1427 Recross-Examination By Mr. Shapson 1428

Iden. Evid.
  1. , 8C, 9, 10, and 1305 16 11C

AUGUST 5, 2013 - 9:33 A.M.


Commission will come to order. Good morning. Today is August 5th, 2013. This is the time and place for the Phase 1A evidentiary hearings in the Investigation 12-10-013 and consolidated applications. This investigation focuses on rates of Southern California Edison and San Diego Gas and Electric in relationship to the outage and retirement of the San Onofre Nuclear Generating Station, we will refer to as SONGS.

I am Administrative Law Judge Kevin Dudney. ALJ Melanie Darling is not here today because she is engaged in hearings in another proceeding. However, she asked me to assure the parties that she will stay informed about these hearings via the transcripts and webcast. Remember this hearing is being webcast live and the archive will be posted publicly.

This investigation has been scoped into several phases, each of which we'll deal with a specific category of costs and legal authority for potentially stopping rate recovery of those costs and provide refunds to ratepayers.

The scope of Phase 1A which will limit our fact finding in this hearing is about establishing a method for calculating the costs and replacing power due to the SONGS outage. I use the term "replacement power" broadly and encompass both foregone energy sales and some types of other market costs. Recognize that one of the issues disputed in testimony is which types of other market costs should be included. And for now I will stay on that issue to develop a more complete record on the subject.

The scope of Phase 1A does not extend to discussion of long-term replacement options for the generation argument about who should bear the costs of replacement power, which I anticipate will be decided in Phase 3, or any 2012 operations or capital costs of the SONGS facility.

Further, this scope does not include actions or costs before the beginning of the outages. It does not include discussion of which procurement options should have been pursued. Instead the focus is on quantifying the costs that were incurred.

On July 22nd, I issued a set of ground rules for these hearings. I expect everyone here to abide by those rules so that we may have an efficient and productive hearing.

I'd like to remind everyone of the few of the key points. We are spending ratepayer dollars to conduct this hearing. Ratepayer dollars pay for the facilities, Commission and utility staff, and intervenor staff to the extent intervenor compensation is sought and granted.

We should all take seriously our responsibility to spend public's money wisely. Therefore, we all need to stay focused on the scope and make our questions and answers to the point.

Questions shall not exclude excessive introductory remarks or any attempts to lay foundation using information that is not in the record. After a question is asked, the witness should be given time to answer it.

To the extent that these rules are not followed, I will listen to and sustain objections or may act on my own motion to keep the record limited to relevant evidence.

As a reminder, briefs on Phase 1A are currently scheduled for August 29th followed by reply briefs on September 12th.

Those briefs are your opportunity to make legal and policy items. These hearings are only to establish material facts.

Now, we have pre-marked several exhibits for cross-examination already this morning. I think we'll go ahead and get the remainder during the first break.

We will wait to mark them on the record as exhibits are used. So please request to mark your exhibits the first time you use them in your cross-examination or when introducing the sponsoring witness. Then we'll take motions to admit exhibits into evidence at the close of hearing.

Is there any other introductory business before we start with the first witness?

Okay. Hearing none, Mr. Weissmann.


Thank you, your Honor.

Good morning. As our first witness, we would call Mr. Colin Cushnie.


Mr. Cushnie, please come forward. Mr. Cushnie, please stand and raise your right hand.

COLIN CUSHNIE, called as a witness by Southern California Edison, having been sworn, testified as follows:


Please state your name and business address for the record.


My name is Colin Cushnie. Last name is spelled C-u-s-h-n-i-e. My business address is 2244, Walnut Grove Avenue, Rosemead, California, 91770.


Mr. Weissmann.

MR. WEISSMANN: Thank you, your Honor.


Q Good morning, Mr. Cushnie. And welcome.

A Good morning.

Q I'd like you to place before yourself a number of exhibits starting with what's been marked for identification as SCE-2. Do you have that document?

A Yes, I do.

Q And I'll direct your attention to -- I'll direct your attention to the portion of that exhibit beginning on page 18, Response to Question 16, and running through page 26, the Response to Question 20. Do you have those portions in mind?

A I do.

Q Next I'd ask you to look at what's been marked for identification as SCE-8.

A I have that.

Q And specifically I would ask you to look at pages 12 through 23. Do you have that?

A I do.

Q Next I'd ask you to look at Exhibit SCE what's been marked for identification as SCE-37.

Do you have that?

A Yes, I do.

Q And, finally, what's been markedfor identification as SCE-38. Do you have that?

A Yes, I do.

Q Now, these exhibits that we have just identified -- were they prepared by you or under your supervision?

A Yes, they were.

Q And do you adopt them as your testimony?

A I do.


Your Honor, the witness as available for cross-examination.


Thank you, Mr. Weissmann. Mr. Shapson.


Thank you, your Honor.


Q Good morning.

A Good morning.

Q I'm going to ask you to give a road map here about the forced outage rate and then about the congestion revenue rates. So let's start with the forced outage rate. As I understand your testimony, in various places throughout what's been marked as your various exhibits, you believe that the forced outage rate should be based on a ten-year average; is that correct?

A That's correct.

Q Okay. Actually, I should ask you first of all, we're here to talk about power replacement costs.

What is your understanding of why we care about power replacement costs?

A The Commission in its October 2012 OII has instructed as in San Diego Gas and Electric to record in their Outage Memorandum Accounts various categories of costs related to the operation of San Onofre. Among those costs were costs that the Commission loosely referred to as "power replacement costs."

And there were three categories of costs we were asked to capture in our OMA. The first category was replacement generation, which in my testimony I refer to as replacement energy. The second category costs were foregone energy sales. Those would be sales that we could have made had the power plant been operating since it was not operating we could not make.

And the third category of costs were all those costs, market-related costs that the utility incurred to maintain reliable electric service for its customers. And I referred to that as either other or miscellaneous costs in my testimony. And it includes capacity-related costs.

Q Are you aware of the Commission ever disallowing power replacement costs this century?

A I'm generally aware of some very nominal disallowances for -- in the case of Southern California Edison, for power plant outages that the Commission found Edison was unreasonable in its operation and therefore assessed a disallowance based on some form of power replacement cost calculation.

Q Are you aware of any differences between the calculations that we use in those cases and the calculation that you presented in your memorandum account? A Again, I'm just generally aware that the disallowances that the Commission did adopt were based primarily on energy- (1287) related assessments. In other words, they looked at the lost energy production and multiplied it by and assumed energy price to come up with a disallowance whereas in this case, in Phase 1A, we're not talking about disallowances. We're talking about categorizing and estimating costs pursuant to the instructions in the OII.

And there we're capturing broader categories of costs than we did for previous disallowances. So in addition to energy, we're looking at foregone energy sales.

We're looking at capacity-related costs. And we're looking at other market-related costs that are associated with the outages of San Onofre.

Q Okay. Thank you for that background information.

The ten-year average -- what do you base the need for a ten-year average on?

A The nuclear power plant has been in operation for an extended period of time. And like any large piece of equipment, you'll have periods of time with power plant. It has a very high availability factor. It runs very well. And you will have other periods of time where incidents occur to prevent the power plant from operating for a period of (1288) time.

So we felt that ten years was a reasonable period of time that would capture both the periods of time where the power plant was run very well and other periods of time where the power plant had extended outages.

Q Did you make the decision to use a ten-year average?

A It was my decision to adopt a ten-year average. My support team had actually recommended that we look at the entirety of the power plant operations. And I felt that was too long. I felt that ten years was long enough.

Q When they made that recommendation to look at the entirety of the plant, did they present you with forced outage rate for that period of time?

A No, they didn't.

Q Did you learn the forced outage rate for any periods other than the ten-year period?

A In developing the testimony, we were aware that a shorter duration period would result in a lower forced outage rate. But that was just became obvious in looking at the data. It wasn't -- our selection of (1289) the ten years was not intended to achieve that outcome.

Q Did you look at a 15-year average?

A Not specifically.

Q Do you know what the 15-year average would be?

A I do not.

Q Do you know what a 20-year average would be?

A I do not.

Q Do you know what the 20-year industry average is?

A No, I do not.

Q In your testimony, you quote the ten-year industry average, correct?

A That's correct.

Q So just so I'm clear, so you picked the ten-year average without knowing what the number would be? ]

A That's correct.

Q Now, I understand that there were two outages between -- in '05 -- I'm sorry. There was one outage for about three weeks in '05, and another outage for about a month and a half in '06.

Are you aware of those outages?

A I am aware that there were two outages that a DRA witness recommended be (1290) excluded from a ten-year forced outage rate calculation because they were of a longer duration than the other outages.

Q Okay. You don't believe that those should be excluded as outliers because of what?

A Because they happened and they represent the actual availability of the power plant over the ten-year period.

Removing those two outages would result in an artificially low availability rate compared to what the plants were actually able to operate at over that ten-year period.

Q Okay. And so as I understand it, you believe the ten-year average is more useful than the five-year average because it has a larger sample size.

A That's correct.

Q Okay. Thank you. I want to ask you a few questions about Congestion Revenue Rights.

First of all, let's -- well, let's start really simple. What's congestion?

A Congestion occurs on the transmission paths when there is more energy trying to be transmitted across the path to a delivery point. (1291)

Q What's revenue?

A Revenue is associated with Congestion Revenue Rights. Congestion Revenue Rights are a financial instrument that Cal ISO makes available to market participants either through allocation or auction. And the older of that Congestion Revenue Right is entitled to either the revenues that are associated with that CRR instrument or they're obligated to pay the costs that are associated with that CRR instrument. You receive revenues when there is a congestion cost on the line, and you have to pay when there is a CRR benefit, if you will, or a congestion benefit, if you will, on the line.

Q Okay. You sort of jumped ahead. I was actually going to ask you about Congestion Revenue Rights. I was just asking you about revenue right then.

So I take it that your prior answer is essentially your definition of Congestion Revenue Rights.

A Yes. Congestion Revenue Right is a financial instrument that obligates the holder to either pay or receive the costs of the congestion on a particular path, depending on the direction of the congestion. (1292)

Q And, well, can we make an agreement that CRRs or Congestion Revenue Rights are 3 the same thing --

A Yes, they are.

Q -- for purposes of these --

A CRRs are an acronym for Congestion Revenue Rights.

Q Thank you. So the CRRs are -- well, how are they acquired?

A Most of Edison's CRRs are acquired through an allocation process. The California Independent System Operator allocates CRRs on a year ahead basis and a month ahead basis. And low-serving entities are entitled to put in nominations for CRRs at various generation nodes.

Edison can also will acquire CRRs through auction. The Cal Iso auctions off remaining CRRs after the allocation process to all market participants. And Edison does seek to acquire CRRs through the auction process and sometimes sells CRRs through the auction process.

Q The monthly CRRs are acquired or allocated each month. The ones that are acquired each month are about 25 percent of the total CRRs; is that correct?

A I don't recall the specific number (1293) off the top of my head, but it is a fraction somewhere in the 25 to 30 percent range.

Q Okay. Thank you. That would be a fair estimate, then.

A Yes.

Q I think you used the phrase "congestion node." Is that the same as the "pricing node"?

A I don't recall using the term "congestion node."

Q I apologize. Let me start again, then.

Did you use the phrase "congestion node"?

A I do not recall.

Q Okay. And the CRRs that Edison acquired on an annual basis for 2012 were acquired before the outage occurred at SONGS; correct?

A That's correct.

Q And CRRs that would be acquired for 2013 would be acquired on an annual basis when?

A It occurs over several rounds of allocation and auction. Typically, the process starts in September of the year preceding the CRR annual year and concludes I want to say at the end of October, early (1294) November. I don't have the dates in front of me.

Q Do you know if Edison acquired any CRRs for 2013?

A I do not.

MR. WEISSMANN: Objection, your Honor. Scope.


Let's focus --


I'm sorry. May I respond?



It's my understanding that we are here to evaluate the methodology of calculating power placement costs for the entirety of the case, not just for 2012.


For now, let's focus on the method for 2012. And if we -- depending on how things go later on in the case, if we need to open the question of whether the method for 2013 would be different, we will do that later. But for now, let's just focus on 2012 to be consistent with all of the previous rulings and scope.

Do you have a question, Mr. Shapson?


Well, it wasn't my understanding of what we were doing here today. I appreciate, your Honor, that we're sort of, in a colloquial sense, dealing with (1295) damages before liability, but we're working on, as I understood it, the methodology -- not necessarily the number, but the methodology for figuring out what those damages would be should eventually the Commission find liability.


Right. I agree with that. But for this hearing let's focus on 2012, and we'll come up with the formula for determining that number for 2012. And if at a later date we think it's necessary to expand that time horizon beyond 2012, we will do so.


Thank you, your Honor.




May I have a minute, then, your Honor?


Sure. Let's take a moment, then, off the record.

(Off the record.)


On the record. Go ahead.


If it please the Court, I would like to reserve a little time at the end because I may need to tweak some of my cross, given the Court's guidance.




Thank you.


And just to make sure I (1296) understand, that's at the end of Mr. Cushnie's testimony.


At the end of Mr. Cushnie's testimony, yes. Thank you, your Honor.

ALJ DUDNEY: All right.


Q Mr. Cushnie, where are Congestion Revenue Rights -- I'm sorry, strike that.

Mr. Cushnie, are Congestion Revenue Rights recorded in the Energy Resource Recovery Account?

A Yes, they are.

Q Where are they recorded in the ERRA or Energy Resource Recovery Account?

A Are you asking what specific sub account are they recorded in?

Q I'm sorry. Thank you for the clarification.

Where are they reported to the Commission? I'll give you some options, if that will help.

Are they -- potentially reported to the Commission in the QCR, Quarterly Compliance Report. Potentially they are reported to the Commission in the annual reasonableness review application. They may be reported to the Commission somewhere else. (1297)

I'm asking if you know what vehicle is used to report them to the Commission.

A Okay. So with that understanding, there are actually two vehicles under which our CRR transactions are reported to the Commission. The first is through the Quarterly Compliance Report, also referred to as the QCR. That is, as the name applies, a quarterly submittal to the Commission for the Commission to review all of the transactions that we did in the previous quarter to verify that they were compliant with our AB 57 bundle procurement plan.

The costs of the CRRs are recorded into the ERRA account, and those costs are submitted to the Commission for costs recovery as part of our ERRA proceedings.

Q Okay. And while we're at it, do you know the sub account?

A I do not.

Q Do you have an understanding of the effect that the SONGS outage had on Edison's CRR portfolio?

A I have a general understanding.

Q What is that understanding, please?

A The SONGS outage created a lot of additional congestion in the LA Basin. That additional congestion resulted in higher CRR (1298) revenues to the extent that Edison was holding CRRs on the congested paths.

Q Do you know what a power flow analysis is?

A Generally familiar with power flow analysis.

Q Could you tell the Court what that is?

A It's an analysis performed using fundamental models to assess the flow of power -- electricity, if you will -- across the grid, and it is used to assess where constraints may occur on the grid. Those constraints lead to congestion.

Q And I may have missed something, but I believe that San Diego's witness testifies about the value of doing a power flow analysis, but you do not. Is that correct? Or did I miss some part of your testimony?

A There is a portion of my testimony where I indicate that a power flow analysis could be performed or -- let me back up.

That analysis could be performed to assess the impact of SONGS being out and what that impact would be on congestion and the cost of congestion; and that it would be highly speculative because there would have (1299) to be a lot of assumptions put into and we don't recommend doing it.

Q Okay. Would it add to your understanding of the effect of the SONGS outage on Edison's CRR portfolio?

A Edison performs numerous power flow studies in part to understand the impact of San Onofre not being available to operate and what that does to the power flow in the LA Basin and its impact on market prices.

We do those analyses with many different assumptions. You want to think about we do a lot of iterations of those analyses, a lot of sensitivities of those analyses. There is not a definitive set of analyses that we could point to that we think would make sense in a hearing room because the assumptions would be very much subject to debate.

Q Thank you. Would the power flow analysis add to Edison's understanding of the impact of the SONGS outage on the CRR portfolio?

A The power flow analyses that we've done have added to our understanding the impact that the SONGS outages had on our CRR portfolio, but we haven't calculated what the specific impacts would be. We're just (1300) generally aware of what those impacts are. ]

Q What is your understanding, generally?

A That the CRRs that we hold in the LA Basin realized more revenue as a result of the SONGS outages.

Q Do you know how much more revenue?

A I don't have that number. And, again, it would be a large range because it would be very assumption dependent.

Q When you say it's speculative assumption dependent, are you aware of any particular margin of error that that analysis would have?

A I'm not aware of specific margin of error. These analyses are very complicated. Some of the variables that you would have to account for would be the bid behavior of the market participants, which Edison does not have access to. So we have to make assumptions as to how entities are bidding their assets. We have to look at how imports are being delivered to the California grid. We have to look at how full network model is changing from time to time.

So when we run our models, we're using the latest full network model that's available to us, but it doesn't necessarily (1301) capture all the constraints that Cal ISO has in their high-end market operation. So there's a tremendous amount of moving parts in an analysis like this to make it very difficult to ascertain with any sort of competence what a specific impact is of something like San Onofre being out. We can do a lot of analysis that says generally the CRRs that Edison holds are worth more as a result of the SONGS outage. But it's very difficult to quantify how much more.

Q Have you heard the phrase production costs model?

A Yes.

Q And do you understand that to be different than power flow analysis?

A Production cost model is different than -- people sometimes use the word production cost model interchangeably. But I think of production cost model as basically a supply and demand of assessment where a power flow model is looking at actual power flows across the grid and identifying constraints. But it also produces -- can also produce the cost of congestion and market prices, if you run it that way.

Q Has Edison performed any production cost model analysis to help it understand the (1302) effect of the SONGS outage on its CRR portfolio?

A No.

Q Would doing so help it understand or better understand the effect of the outage at SONGS on its CRR portfolio?

A Not on its CRR portfolio.

Q Are you aware of CAISO publication I believe it's call "Local Capacity Technical Analysis"?

A I believe that's the local area studies that CAISO performs.

Q And SONGS is in the LA Basin area in that analysis; is that correct?

A I think it's defined as being in the LA Basin, but it's physically located between the Edison and San Diego systems.

Q And do you know what a Local Reliability Area is in the parlance of ISO and analysis that I just brought up?

A The CAISO has defined two local area zones for Southern California Edison. One is the LA Basin, and the second is the Big Creek Ventura area. And then in San Diego service territory, the local area is the San Diego Low Pocket.

Q And do you know why CAISO performs these Local Reliability Area studies?


A To ensure that the grid is sufficiently robust in the local areas because there is a dependence on imported generation to carry the load. They want to make sure there's enough local area generation to avoid system disturbances in the event of large contingencies on the grid.

Q And is that because the LA Basin as we've just using it the way we just talked about is considered locally constrained -- a locally constrained area?

A That's correct.


Thank you very much, your Honor. I just would like to reserve some time as we discussed before.




Thank you.


Mr. Freedman.


Thank you, your Honor. Can we go off the record to distribute some exhibits?


Yes. Off the record. (Off the record)


Back on the record. While were off the record, we pre-marked few exhibits. Mr. Freedman will now walk us through those.



Thank you, your Honor.

During the break, we marked a series of exhibits. I will walk through what each of these exhibits is. We have preliminarily marked as TURN-7 several pages from a California ISO 2012 Annual Report on Market Issues and Performance.

We have preliminarily marked as Exhibit TURN-8C a Data Response by Edison to TURN Data Request Set 9, Question 1. This is a confidential data response that contains Edison-specific confidential material.

We have preliminarily marked as Exhibit TURN-9 a series of data responses by Southern California Edison to TURN Data Request Set 2, Questions 13A, 13B, and Data Request Set 2, Question 19A.

We have marked as Exhibit TURN-10 a series of Edison data responses to TURN Set 3, Question 6A, 6C, 3, and TURN Data Request Set 2, Question 17D.

And then, finally, we have marked as TURN Exhibit 11C Edison Data Response to TURN Set 3, Question 5, including tables that have Edison-specific confidential materials.


Thank you, Mr. Freedman.

TURN Exhibits 7, 8C, 9, 10, and 11C are marked for identification.


(Exhibits Nos. 7, 8C, 9, 10, and 11C were marked for identification.)


Mr. Freedman, do you need a moment?

MR. FREEDMAN: I think I am ready, your



Okay. Go ahead.


Q Good morning, Mr. Cushnie.

A Good morning, Mr. Freedman.

Q I'd like to start with what has been marked as Exhibit SCE-02, which is the January 9th testimony, specifically on page 21.

A I have that.

Q On page 21, starting on line 14 going through line 16, you refer to the price deflation elasticity impact SONGS would have had on market prices had SONGS been available to generate.

Is that another way of saying that the SONGS outages caused market energy prices to rise above levels they would have otherwise been set at?

A Yes, except that I would say rather than having market prices set at, it's what market prices would have cleared at. They're (1306) not administratively set.

Q And, in fact, are you aware that Southern California Edison did provide a specific estimate of the impact of the SONGS outages on SP-15 market prices in response to a TURN data request that was included in Mr. Woodruff's testimony?

A Is it one of the exhibits that we marked here this morning?

Q It is not. It is part of Mr. Woodruff's March 29th testimony to which you were provided rebuttal?

A Was that the July 10 testimony of Mr. Woodruff?

Q It is the March 29th testimony of Mr. Woodruff.

A Can you point me to a page reference?

Q It would have been Attachment 2.


Let's go off the record for a moment while everybody gets their papers. (Off the record)


Back on the record. Mr. Freedman, please remind us what exhibit we're looking at and then go ahead.

MR. FREEDMAN: We're looking the

exhibit that was pre-marked as Exhibit (1307) TURN-2C, Mr. Woodruff's prepared direct testimony on March 29th. And Attachment 2 has a table that is based on an Edison data response to TURN.

Q Mr. Cushnie, have you been able to take a look at that?

A Yes, I have.

And am I correct in understanding that this represents Edison's estimate of the impact of the SONGS outages on replacement power costs?

A This looks like results of a price elasticity study that we performed to inform our price elasticity assumptions in our foregone energy sales calculations.

Q And you didn't provide any rebuttal testimony, did you, on the calculations that are contained in this attachment?

A No, I did not.

Q All right. Well, keeping that in mind, I would like you to turn to what has been marked as TURN-7.

This exhibit contains an excerpt from the California ISO's Division of Market Monitoring report on the ISO market for 2012.

Have you had a chance to take a look at this excerpt that was provided?

A I reviewed it briefly prior to the (1308) hearings.

Q Okay. Well, I would like you to turn to what has been -- what is marked as page 58 of the report. It's not 58 of the attachments, since we have mercifully excerpted the relevant pages.

There is a section titled "Total Wholesale Market Costs," and in particular there is a reference at the very end of the first paragraph to an increase of over 28 percent in gas normalized prices during 2012. Do you see that sentence?

A Yes, I do.

Q Does the report in the next paragraph identify one of the factors contributing to this increase in gas normalized costs or prices as the outage of the San Onofre nuclear plant?

A Yes, it does.

Q And do you generally agree with the ISO's conclusions in this respect?

A I would agree that the standard San Onofre outage is one of the contributing factors to the higher gas normalized prices that they report, but there were other factors that led to higher prices as well.

Q And does this generally mean that (1309) Edison's purchases of energy in the ISO markets during 2012 occurred at higher prices that were in part due to the SONGS outages?

A Yes. The market prices that we paid in 2012 for energy delivered in 2012 were impacted by the SONGS outages and were presumably higher because of the SONGS outages.

Q And would these higher prices have also been paid by San Diego Gas & Electric for its replacement power?

A The higher prices would have been paid by any market participant seeking to buy energy in that market.

Q Would this include market participants in Northern California?

A It's hard for me to say for sure at every hour that a Northern California customer would have paid more as a result of the San Onofre outages, but I will acknowledge that there were undoubtedly certain hours where the market clearing price in Northern California was adversely impacted by the SONGS outages. And by "adverse" I mean it was higher than would have otherwise been had SONGS operated.

Q I would like you to move backwards in the exhibit to the prior page which is (1310) marked page 15. And on page 15 under the subheading which is marked Other Reliability Costs, there is a discussion of the costs associated with the ISO's Capacity Procurement Mechanism.

Are you familiar with the Capacity Procurement Mechanism?

A Yes, I am.

Q And in the final paragraph under Other Reliability Costs there is a statement that in response to the SONGS outages, the ISO used its Capacity Procurement Mechanism to procure a total capacity of 966 megawatts at a total cost of about $26 million in 2012.

Do you have any reason to believe that this number is not an accurate representation of the CPM costs incurred by the ISO related to SONGS in 2012?

A I don't have any reason to dispute the magnitude of the costs. I will indicate that in the previous paragraph Cal ISO report indicates that most of the CPM costs were attributed to the SONGS outages. And in the sentence you referred to, it's not clear to me that there -- that the total of 9966 megawatts is the entirety of their CPM purchases or just the purchases related to what the Cal ISO was attributing to the SONGS (1311) outages. But with that caveat, I don't have any reason to dispute the magnitude of the numbers.

Q Well, let's go to a little bit later in the exhibit, page 217 that's the final page. And there is a table titled "Table 9.9.2 Capacity Procurement Mechanism Costs in 2012." And this table shows numbers that add up to the number that was previously discussed: 25.9 million, which I believe is the same as 26 million that was stated earlier.

Where are these units located that are in the table?

A The Huntington Beach units are located in Southern California Edison service territory, and the Encino Unit 4 is located in the San Diego local area.

Q And if you read the asterisk below the table, the asterisk states that all the units are dispatched due to the outages of the San Onofre generating stations Units 2 and 3.

Does this clarify the source of the ISO's estimate?

A Yes, it does.

Q Does this remove some of the concerns you had about whether the entire (1312) amount, the 25.9 million, was attributable to the SONGS outages?

A The reason I still have a question, Mr. Freedman, is if you look at two paragraphs above the table, it says.

However, while reliability must-run payments remain low, capacity payments related to the Capacity Procurement Mechanism increased. The increase in the Capacity Procurement Mechanism payments in 2012 are directly related to the outage of SONGS Units 2 and 3 which were offline for almost all of 2012.

So when you talk about an increase, I'm not sure if it's an increase relative to zero or an increase relative to other CPM costs that were also incurred in 2011.

So I do concur that Table 9.9.2 has a summation equal to 966 megawatts, or 25.9 million, but the Cal ISO has an asterisk there that indicates all of the units are dispatched due to the outages of the SONGS Units 2 and 3. I'm just not sure if this is the entirety of all of the CPM charges.

Q So there could be additional CPM charges that are related to the SONGS outages?

A No. There are just additional CPM charges.

Q Okay. I would like you to, with (1313) that in mind, turn to will has been marked as TURN -- Exhibit TURN-8 C. Again, this is an Edison data response to TURN set 9, Question 1.

A I have it.

Q And I know you are not the person who is listed as having prepared this data response, but are you prepared to answer a couple of brief questions about it?

A I'll do my best.

Q Is it correct to say, if I were to look at the confidential table which is the second page of the data response, that these lines on the table -- and I think I can read the title of the table without there being a problem, which is the title is "Capacity Related Charges CPM Data." Is it fair to say that these line items show Edison's estimates of CPM costs incurred between February and October of 2012?

A That's correct. Q And do you know why the data ends in October?

A Based on my understanding, Edison did not incur any CPM charges in November and December of 2012.

Q And although there is no sum total provided by Edison, I would note that I did (1314) handwrite in a calculated total. And I would ask whether you would accept, subject to check, that the column titled "Sum Amount," if you add up all those numbers, that it adds up to a number that is handwritten at the bottom?

A I would agree to that.

Q Okay. And so if you were to -- is it your understanding that the CPM costs that are identified in this response are the same CPM costs that we were discussing in the ISO report, meaning the same types of costs?

A They would be.

Q And so if the ISO did incur the 25.9 million we were discussing previously, this number here would reflect Edison's share of that amount?

A That's correct.

Q And to the extent that there were other CPM costs, meaning the difference between this number and the 25.9 million number, those would have been paid by other market participants in the ISO system?

A The 25.9 million number that we addressed earlier is what the Cal ISO is indicating is the totality of the CPM charges associated with the SONGS outages.

And the 13.6 million that you've (1315) calculated here is Edison's share of those charges. The CPM charges for the San Onofre outages were allocated to all scheduling coordinators in the Edison and San Diego service territory.


Can we go off the record for just one second, your Honor?


Off the record. (Off the record.)


On the record. Go ahead, Mr. Freedman.


Q So I guess we can just clarify, then, that the Sum Total amount that was referenced that is handwritten in the exhibit here, Edison does not consider the total amount to be confidential; is that right?

A Not at this time. Not at this time.

Q And that total amount, then, is 13.6 million for 2012.

A Correct.

Q And so the delta, just to close the loop on this, between the ISO's estimate of (1316) costs and Edison's estimate of its costs, in other words, 25.9 minus 13.6, that delta is charged to other market participants or allocated to other users of the ISO system?

A Specifically allocated under scheduling coordinators in the San Diego and Edison service territory.

Q So it would not be allocated to NP 15, for example, scheduling coordinators?

A No.

Q Keeping this in mind, I would like to ask you to turn to -- I would like you to turn to your Energy Resource Recovery Account review of operations. It's testimony, I believe this is SCE-3, dated July 8th.


It's actually 38.


Q Oh, I'm sorry. Exhibit 38. And page 9 of that exhibit.

A I have that.

Q This is not a confidential table; correct?

A It is a public table.

Q Okay. Great. So when you show in this table, Table 17-3, Total Capacity Costs of $33.1 million, is the number we were just discussing, the 13.6 million, is that a subset of this number or is it additive to this number?


A It is a subset.

Q And what are the remainder of the capacity related costs in this table? If you could characterize what they're related to.

A There's two other components that we included in our capacity related costs calculations. The second category is what we refer to as net standard capacity product charges, and the third is bilateral contracts which were entered into to substitute for the RA capacity Unit 3 that was no longer available due to the forced outage.

Q Okay. I would like to turn to another topic, if we can move to your Exhibit 37.


Mr. Freedman, would this be a good time to take a break? It's about 10:45.




Let's take a ten-minute break. And while we are off the record, for the parties that still have more exhibits to mark, we can work on that. And we will come back at 10:55. Off the record. (Recess taken.)


On the record. Mr. Freedman?



Thank you.

Q We're in Exhibit SCE-37 and at Table I-2 on page 8. And this table shows replacement energy costs and replacement energy by month; is that right?

A Yes, it does.

Q And Edison made a revision to these calculations in the July 24th testimony relative to Exhibit SCE-38; isn't that right?

A Yes, we did.

Q And were those revisions in response to DRA's testimony regarding outage rates and nuclear fuel costs?

A Yes, they were.

Q Were there any other reasons why the numbers in Table I-2 were changed?

A There should not have been any other changes.

Q Okay. And would the same hold true, then, for Table I-3 on the following page which shows reporting of foregone excess energy sales?

A That's correct.

Q Okay. Staying in Exhibit 37, I would like you to turn to -- starting on page 1-5 there is a discussion of price benchmarks, and you describe in this testimony why you believe the DLAP, Default (1319) Load Aggregation Point, prices should not be the basis for computing replacement power costs; is that right?

A Yeah. The way I've tried to describe it in the past is that the SP-15 index price is more appropriate than the SCE DLAP price. But we have said previously that SCE DLAP price could be used for replacement energy; it's just not the preferable price benchmark for a variety of reasons.

Q Could you please explain how the DLAP price is calculated as a general matter?

A The DLAP stands for Distributed Load Aggregation Point, and it is the load weighted average price that a buyer of load will pay in the Cal ISO IFM market.

Q And is the DLAP price different for each buyer?

A The DLAP price is different for each utility service territory. So there is an SCE DLAP, PG&E DLAP and an SDG&E DLAP; and anyone buying their load in one of those service territories will pay the applicable DLAP price.

Q You also reference on page 16 the EZ Gen trading hub price, lines 21 through 22. Can you explain the difference between the EZ Gen trade hub price and the DLAP (1320) price?

A The EZ Gen price is the generation weighted average price that generators receive in that existing zone. In this case it's the SP-15 zone, so that would include the Edison and San Diego service territories.

Q So when you refer to the SP-15 price, you're also referring to the EZ Gen price?

A When I refer to SP-15 for the day ahead index, I am referring to the SP-15 zone. The index is being reported on the bilaterally transacted prices that occur between buyers and sellers prior to the Cal ISO's IFM market operations which is what gives rise to the EZ Gen price.

So EZ Gen is a Cal ISO IFM price. SP-15 index is a bilaterally negotiated price between buyers and sellers that precede by a few hours the operation of Cal ISO's IFM.

Q And what entities report the day ahead SP-15 indexes?

A Multiple market participants. But it is voluntary. Not all entities that transact in those markets report.

Q And what entities actually report their market data?


A I can't tell you specifically which market participants report to the trade publications, but they have a fairly robust process in place where they canvass market participants.

Q How many vendors are there that produce this data?

A We currently utilize Platts. I believe there are one or two other vendors that do it. I couldn't tell you off the top of my head. And we also use Clearinghouse prices, ICE, which is the Intercontinental Exchange, has an index price that we use for some of our reporting purposes as well. We are not using it for these calculations though, but the prices track fairly well with the Platts day ahead index.

Q Are the prices reported by the different vendors identical or similar?

A They're typically very similar.

Q I would like you to take a look at what's been marked as TURN Exhibit 9. And, again, this exhibit starts with data responses by Edison to TURN's Set 2, Question 13 A, and proceeds from there.

You're familiar with these data responses, Mr. Cushnie?


A Yes, I am. Q On the first page of the response you write, in response to Question 13 A, in the third line that SCE does not object to the use of its DLAP prices to estimate the cost of replacement energy; is that right?

A I say that as a follow on to my statement which is SP-15 index prices are more appropriate because they reflect the daily bilateral market activity that the precedes the daily Cal ISO IFM.

And I would also note that I was very specific in saying to estimate the cost of replacement energy. I did not say to estimate the cost of foregone energy sales, which is why we, in part, chose the SP-15 data index because it's a single-price source that could be used for pricing both the short position, which are the replacement energy, as well as the long position, which is the foregone energy sales.

If we're going to use DLAP to price replacement costs energy, then we're going to need to come up with some sort of generation-based price index to calculate foregone energy sales.

Q Could Edison use the SP-15 index to determine the pricing for foregone energy (1323) sales, and the DLAP for replacement energy costs?

A Mathematically we could, but I would disagree with that as an appropriate premise. The SP-15 index reflects, again, a price that buyers and sellers negotiated in bilateral transactions. So it's a price that buyers and sellers were going to transact that. When we start looking at Cal ISO, we have DLAP, which is a price at load base, and we have EZ Gen, which is a price that generators are paid.

But more specifically, generators are typically paid at their generation node price, which is often lower than the DLAP price, as both my testimony and TURN witness -- TURN's witness Woodruff indicated as well.

So if we were to use DLAP, I would recommend using potentially the DLAP adjusted for the historical difference between SONGS, Gen nodes when they were running, and then do a further adjustment for the price elasticity function. That way, you would have a load price and a Gen price.

Q Okay. On the next page of this exhibit, in response to Question 13 B, there is a response that provides the difference (1324) between the average hourly SP-15 index price and the average hourly DLAP price for January 9th through December 31st, 2012. Do you see that?

A I do.

Q And according to this response provided by Edison, the average hourly DLAP price for this period is $30.94, as compared to $30.20 for the SP-15 index price; right?

A Correct.

Q And would this mean that a switch to the DLAP price index for replacement energy costs only would result in an increase in the total amount calculated relative to the use of the SP-15 index? A It would.

Q And on the next page of this exhibit there is a response to TURN's Set 2, Question 19 A. And in this response Edison states that the SCE DLAP is a close approximation for the SP-15 trade hub index and is a reasonable benchmark.

Is that still your -- is that still Edison's position?

A One thing I think we need to keep in mind when we look at establishing a reasonable benchmark, is that there is no single definitive price benchmark that can be (1325) used in a situation like this because our energy procurement is conducted on a multi-year forward basis, an annual basis, quarterly basis, monthly basis, balance and month, daily, hour ahead, real time. So there is a continuum of prices in markets that we transact in.

And so for purposes of doing a calculation, we are trying to pick a single-price reference to do both the estimation of the costs of replacement energy, as well as the estimation of the cost of foregone energy sales. ]

And what we pick from conceptual standpoint was the data index price because again it represents the price that both buyers and sellers were willing to transact at in a bilateral market prior to the operation of the IFM.

The Cal ISO's IFM has generation prices and they have loaded prices. And they differ. So if we are to separately price replacement energy and foregone energy sales, then I would say yes, it would be appropriate to use the DLAP for the replacement energy and that we would have to come up with some sort of modified generation index to calculate the foregone energy sales.


I personally think it makes more sense just to use a single price point given that there's a continuum of prices that we have here and the data index conceptually makes the most sense.

Q And you would agree that prices at generation nodes tend to be lower than the DLAP prices, correct?

A Correct.

Q So as a general matter, is it fair to say that the average prices Edison paid for its load exceed the average prices that Edison received for its generation?

A That's correct.

Q Staying in Exhibit 37, starting on page three -- actually, starting on page two, you discuss the definition of replacement energy costs. This gets to some of the discussion we've been having about the distinction between replacement energy costs and foregone energy revenues; is that right?

A That's correct.

Q Starting at the bottom of page two, the very last words on the page, you state "Traditionally a replacement energy cost calculation would consider the incremental fuel and or energy a utility utilized to serve load as a result of an outage."


What do you mean by "traditionally"?

A I'm referring to the period of time prior to restructuring in California. At that time, a utility like Edison would have been fully resourced with sufficient capacity under ownership or contract to carry all of its load plus its planning reserves. And so when a particular power plant was unavailable to operate, it just meant that the utility used a less efficient power plant to generate the required electricity to meet its customers' load. And that difference in fuel burn is what the replacement power cost calculation would have done.

Q Moving to page four, you take issue with some of the costs that TURN has included in its definition of replacement power. And starting on line five and going down, you suggest that TURN should be raising these concerns in Phase 3 of this proceeding; is that right?

A That's correct.

Q So in Edison's -- from Edison's perspective, this whole discussion about foregone energy revenues doesn't belong in this phase of the proceeding?

A No. What I am saying here is the (1328) Commission was very explicit as to what it was asking Edison and San Diego to calculate as part of their Outage Memorandum Accounts. First thing we were to calculate was replacement generation, which in my testimony I refer to as replacement energy. The second thing we were to calculate was foregone energy sales, which we do and separately report that in our OMA. And the third thing was all other market costs incurred to maintain a reliable electric system for customers.

So we categorized the cost in accordance with the October 2012 OII. Which categories of costs and how much of those costs should be subject to disallowance is component of Phase 3 of this proceeding. We're just doing categorization and the estimation consistent with the OII.

Q TURN isn't proposing any disallowance in this phase, is it?

A I'll need to go back and look at the TURN testimony specifically. But there were recommendations for the Commission to -- there were sort of alternative disallowance proposals to either remove costs -- remove base rates from rates or to remove fuel purchase power cost from rates. I would (1329) consider that to be a disallowance.

Q Mr. Cushnie, are you familiar with the basic approach that was used by Edison to estimate the cost effectiveness of the Steam Generator Replacement Project in Application 04-02-026?

A I briefly reviewed some material that was presented to me this morning.

Q That was material that we circulated on Friday to your attorneys?

A Correct.


Your Honor, by agreement, TURN's not going to introduce this exhibit which we had prepared.

Q Mr. Cushnie, I believe you're prepared to answer a couple of very basic questions; is that right?

A Yes, I am.

Q Is it your understanding that Edison assumed in the analysis presented in that proceeding that all of the power that would be produced by San Onofre off the steam generator replacements would provide monetary value to customers?

A I agree the study assumed that all the energy produced would provide a value to customers.

Q So Edison did not in that (1330) application model only the value of SONGS production sufficient to satisfy its net short position?

A It looked at the entirety of the production.

Q And so if Edison had presented a cost-effectiveness analysis that used your current definition of replacement energy costs as the basis for the amount of production to be valued, the results would have been different, correct?

A If Edison only looked at the forecast generation that would have technically net load in a short hour situation, then the results would have been different.

Q Staying in Exhibit SCE-37, let's go back to pages eight and nine where there are Tables I-2 and I-3. Are you there?

A Yes, I am.

Q Again, these tables separately identify replacement energy costs and replacement and foregone energy sales.

And so would it be fair to say that the amount of SONGS generation that would have been used to meet Edison's net short would essentially be -- let me back up for a (1331) moment.

Did you use as the basis for these calculations a forecast of SONGS generation that would be the sum of the replacement energy megawatt hours and the foregone energy sales megawatt hours, in other words, 8.5 million plus 5.17 million?

A The sum of the replacement energy in megawatt hours and the foregone energy sales megawatt hours would equal to total plant output less a forced outage rate assumption.

Q And how did you create this energy production forecast?

A Edison's share of the maximum output of Units 2 and 3 multiplied by 24 hours multiplied by the number of days that the unit was forecast to be available to operate less the 2.15 percent forced outage rate factor.

Q Let's move to page 19, still in Exhibit SCE-37. And starting on line three, you respond to arguments raised by TURN about a downward bias related to the use of -- the debate appears to be about the with or without SONGS day ahead position.

Can you explain what the difference is between those two?


A Edison's share of SONGS is approximately 1,680 megawatts. And if SONGS is not available and nothing else changes, then Edison's net open position will be different by 1680 megawatts. The issue here is because Edison was aware that SONGS was not available, how do we isolate the impact of SONGS not being available relative to all the other portfolio actions that we're taking to manage our bundled customer exposure to the marketplace?

So what we said here is that the best estimate of what our net open positions would be as a result of SONGS being out would be those positions that existed prior to the daily trading activity that we entered into, which again predates precedes the IFM by several hours.

Q Well, let's go through this a little bit more carefully in TURN Exhibit 10, Exhibit TURN-10 that I had circulated. Maybe we can walk through these data responses. The first page is a response to TURN Data Request Set 3, Question 6A.

You're familiar with these data responses, are you, Mr. Cushnie?

A Generally.

Q So this first response here (1333) essentially says that Edison computes its day-ahead energy position every day between 5:30 and 6:00 in the morning?

A It's saying it's calculated every day between 5:30 and 6:00 in the morning as shown in Column C of the subject spreadsheet. We obviously calculate our net open positions over a continuum of time. And we constantly updated those. But for purposes of doing this calculation, it is just updated once at 5:30 to 6:00 in the morning.

Q I'd like you to turn to the next page which is Edison's Response to TURN Set 3, Question 6C. My understanding is here Edison is saying that the computation of Edison's net position was based in part on physical trades conducted after the SONGS outages began; is that right?

A Are you asking about the response to Question 6 or something I said earlier?

Q I'm asking about the response.

A So the Response to Question 6C is stating that all utility-owned and contract supply physical generation resources that are included in our residual net position modeling in the year 2012 were executed prior to January 31, 2012.

So, in other words, we did not (1334) acquire any new utility-owned generation. And we did not acquire any physical supply resources to be included in our portfolio that -- we did not acquire any of those resources in 2012 for use in 2012.

We did enter into many financial products which also have the effect of hedging our net open position. And those transactions were provided in a separate data request.

Q And we'll get there in just a moment. This is a confidential exhibit that we're going to get to after this.

And specifically the Response to TURN Data Request Set 3, Question 5, refers to physical trades, right? That's what's referenced here at the bottom executed --


What question were you referring to?


Q We're still on Response to Question 6C. There's a reference here to another TURN data request that I believe you were mentioning, Mr. Cushnie.

A Correct. I was mentioning the financial transactions which we responded to in Question 6D. And then there's a list of physical trades that we executed in 2012 that we responded with to your question TURN (1335) SCE-3, Question 5.

And what I want to distinguish for you here is physical trades are just the transaction of physical products as opposed to what we were talking about in our response in this question, which would be the acquisition through contract of a generation resource that we would be able to control and dispatch.

Q And in the next response which would be the next page, Edison's response to TURN Data Request 3, Question 3, Edison provides some general guidance about how it manages its net open capacity position; is that right?

A That's correct.

Q And Edison states it uses a variety of products, term durations, and strategies to ratably manage its net open position for both RA capacity and energy; is that right?

A That's correct.

Q And that includes both physical and financial products?

A Correct.

Q And then in the final page of this data -- this exhibit which would be Response to TURN Set 2, Question 17D, very last sentence states that Edison managed its open (1336) position using daily and forward markets.

And by "forward market," does Edison mean purchases that were made before Edison makes its computations of its day-ahead energy position?

A By "forward markets," we mean those transactions that term greater than the day-ahead transactions that we enter into. The day-ahead transactions that we enter into come in two forms. There will be bilateral transactions that we enter into, which are the basis for the SP-15 index that we propose to use. And then there's the Cal ISO data transactions that we enter into which give rise to DLAP prices to EZ Gen prices to specific generator node prices. So here forward markets are anything that was transacting more than a day forward.

Q Okay. I'd like you to turn now to what has marked as Exhibit TURN-11C. This is a Response by Edison to TURN Data Request Set 3, Question 5. The first page that I will ask you a question or two about is not confidential, though. My understanding is that the specific data that is provided in the following pages is confidential. I'm not going to ask you to recite any of the numbers or even refer to the particular numbers. (1337)

Have you had a chance to take a look at this response?

A Yes, I have.

Q And the question asks for Edison to provide a list of physical forward products including prices that Edison executed between February 1st and December 31st, 2012.

What's your understanding of the forward transaction information that was provided in this response? What does it include?

A SCE provided all the transactions it had engaged in that were contracted more than a day in advance of day-ahead market. And for a term typically of a month or series of months, there were a few balance-a-month transactions.

Q And how did these forward transactions affect Edison's computation of its net position?

A They would have been included in the net open position calculation. And therefore if we were short, we would have been less short. If we were long, we would be more long.

Q Then going to the actual table itself, I assume it's okay if I ask questions about the headings of the columns. (1338)

A Yes.

Q I assume that trade date which is the first column refers to the date on which a transaction is executed; is that right?

A Correct.

Q And begin and end dates -- those are the dates where the product began delivery and ended delivery; is that right?

A That's correct.

Q And then "buy slash sell" -- that's an indication of whether Edison was a buyer or a seller?

A Correct.

Q So is it fair to say that many of these forward transactions were made -- some of them were made before the outages began on January 31st of 2012?

A Number of them were made prior to January 31st.

Q And other forward transactions were executed before Edison realized the seriousness of the situation at Units 2 and 3?

A Any time we have a power plant outage in a nuclear facility, we think it's serious. I need some help understanding what line you're looking for me to address.

Q I guess it would be between (1339) January 31st and the date -- after January 31st, but before Edison realized that the units would not come back on-line as scheduled.

A Okay. In terms of our procurement activity, we utilized the best information that was available to us at the time. I personally was in contact with the VP at San Onofre. And he would provide periodically his assessment as to when we'd be allowed to return Unit 2 to service and when we thought we could return Unit 3 to service.

In all instances, we expected to be able to return the units to service in 2012. And our management of the net open position therefore was very near-term oriented. And it wasn't until the July 7th announcement from our CEO Ted Craver we were shutting the plants down did we then assume that the plants were not returning to service.


You mentioned the 7th.


I said July. Was it June 7th?




Time flies.


Luckily we're still in 2012 for these hearings.





Q So is it fair to say then that as Edison managed its net open position during the outages in 2012, that the expected date for the units to restart changed over the course of the year?

A It periodically changed. They were pushed out.

Q And how did these changes affect Edison's purchasing strategy?

A The changes were always of a one to two month forward return date beyond what we were assuming. And so when we assumed that the unit's returning at a later date than we had originally planned, that increases our net short position or makes our long position less long.

And when that gets factored into our overall management of the portfolio, recognizing that there's other resource assumptions that are changing as well, other resources may be more or less available. And we're also looking at updated load forecasts.

So I can't attribute any specific transaction to SONGS planning assumptions. But clearly the magnitude of SONGS outages created a large open position for us that we sought to manage in advance.

Q And is it fair to say that Edison (1341) would not have made the same amount of forward transactions that are shown in this data response if SONGS had returned to service as originally anticipated?

A It's hard to say because the implied market heat rate with SONGS out of service was a lot higher than what it had been when SONGS was in service, which meant that Edison resources were then running at a greater rate than we would have forecast. And so there's an offset that goes on there. And so it's not clear to me in all instances that we would have done anything materially different than what's on this sheet.

Q Are you suggesting that Edison ran its own units to a greater extent than would have otherwise occurred without the outages?

A Correct. A lot higher market heat rate meant that resources ran greater durations than they would have otherwise operated.

Q And did that affect the net energy short estimates that Edison developed?

A Correct. The units that were running more than we thought reduced the net short calculation and increased the long position calculation.

MR. FREEDMAN: Okay. Thank you very (1342) much, Mr. Cushnie.

Those are all of my questions, your Honor.


Thank you, Mr. Freedman.

It's about 11:35. Mr. Geesman, you've requested half an hour; is that correct?



ALJ DUDNEY: So my plan would be we'll

do Mr. Geesman before lunch. And then after lunch, we'll start with Ms. George. Okay.

Go ahead, Mr. Geesman.


Q Good morning, Mr. Cushnie.

A Good morning, Mr. Geesman.

Q Did Edison make any attempt to coordinate the development of its testimony in this phase of the proceeding with San Diego Gas and Electric?

A I would not characterize our interaction as coordination as much as we did share drafts in some cases shortly before submitting them.

Q Did you make any effort to develop a common methodology?

A Based on intervenor testimony, we did have several discussions as to whether or (1343) not it made sense to see if we could coalesce around a common methodology. And in some cases, we were able to reach agreement. And in other cases, we have different methodologies.

Q In those areas where your methodologies differed, what prevented you from coalescing?

A Difference of opinion. Q Difference of opinion as to what would help the Commission in this investigation or difference of opinion as to what would help the particular company?

A I can't speak for San Diego Gas and Electric. I can speak for Edison. And in our case, where there were differences, we believe what we were presenting made the most sense and we believe the most understandable for the Commission to follow.

Q When you said made the most sense, you mean the most intellectually appropriate?

A Conceptually appropriate.

Q And would you think that the Commission had an interest in being presented with a common methodology?

A Typically, the Commission prefers the parties work out differences of opinion prior to the hearing. It reduces the amount (1344) of factual dispute the Commission has to entertain in a hearing. And if it reduces the policy differences, then there is that much less the Commission has to decide in a decision.

Q What would be an example of an area where you were unable to coalesce, but felt quite strongly that Edison had the more conceptually correct position?

A The one that comes to mind is Edison's choice of the SP-15 data index price as the appropriate price benchmark, and I believe San Diego Gas & Electric is using a what they refer to as a Cal ISO SP-15 index price, which I think is the EZ Gen up price.

And I've explained in some earlier testimony there is not necessarily a right price benchmark to use, but we do believe the use of the SP-15 data index is the most appropriate because it is a price that both buyers and sellers were willing to transact that bilateral negotiations, and we are using the price index to price both short positions with respect to replacement energy and long positions with respect to foregone energy sales.

Q Can you think of another aspect of your methodology where the two companies were (1345) unable to coalesce, but Edison felt its position was more conceptually appropriate?

A I want to say that there were some differences in how we categorized grid management charges, so it was a matter of which bucket that you put them in. But I can't say for sure.

Q Can I ask you to turn to the cross-examination exhibit that has been identified preliminarily as A 4 NR-20.

A So I have some materials that were presented to me prior to the start of the hearings and don't have exhibit numbers on them.

Q This is one with a cover that says "Alliance For Nuclear Responsibility Cross-Examination Exhibit."

A Correct, but the version I have has a blank exhibit number.

Q Okay. Okay. It is a -- the first page starts with the July 31st e-mail from Edison to me transmitting the data response which begins on the third page of the exhibit, and it's identified as Question 29.C Supplemental. Do you see that?

A I have that.

Q Are you familiar with this data (1346) response?

A I briefly read it this morning.

Q You had no familiarity with it prior to this morning?

A I believe my attorney sent it to me over the weekend, but I was not in a position to access it in a written form and so I waited until this morning to review it.

Q You did not participate in compiling the response to Question 29.C Supplemental?

A I certainly did not draft it. I cannot recall if I reviewed it or not. I have been reviewing many data requests in this proceeding, and some of them are very similar in our responses. And so I just have a hard time recalling if I actually specifically reviewed this one.

Q Were you involved in any discussions last week that may have contributed to this July 31st response?

A Not to my awareness. I may have been involved in a discussion that maybe someone else would provide you with this response, but I was not asked to speak to this particular issue where we might be amending our response to you.

Q Are you able to answer a few basic (1347) questions about the content of the response?

A Yes, I am.

Q Are you familiar with Mr. Craver's June 7th prepared statement which is posted on the Edison website in which this exhibit excerpts two paragraphs from?

A I've read portions of it. I did not read it in its entirety.

Q Do you know what methodology Mr. Craver's referenced analysis used for buying replacement power from the market?


Objection, your Honor. As stated in the data response, our position is that the analysis that was done at the time is privileged. So what's been provided here is an explanation of how Edison -- as stated here, how Edison believes a reasonable analysis could be conducted. But the content of the specific analysis that Mr. Craver referenced we contend is privileged.


Your Honor, I asked if he was familiar with the methodology. We can get into Mr. Weissmann's objection, if you would like. I would ask that he explain the basis of the privilege.


Okay. So I think, Mr. Weissmann, I'm not sure if I fully understand the objection. But I think (1348) Mr. Geesman's question as he just rephrased it, which is simply is the witness familiar with the method, doesn't seem to raise privilege concerns to me. So let's go forward with that and see what else comes up.


Q Mr. Cushnie, are you familiar with the methodology that was used to support Mr. Craver's statement?

A I believe I was familiar with portions of the analysis.

Q Were there any variances from the methodology used to support Mr. Craver's statement from that which you have used in your testimony?


Objection, your Honor.


Now we're getting into the privilege, yes.


The objection is that the content and scope of this analysis that was referenced is privileged; it was attorney-client and attorney work product. And so we object to inquiry into the contents of what that historical analysis was done.


Mr. Geesman?


Your Honor, simply labeling what is clearly an economic methodology as attorney work product seems pretty expansive to me. There is virtually (1349) nothing that could not fall within that umbrella.

I'm asking a very focused economic question. I don't see where the attorney-client privilege or the attorney work product privilege comes into play.


Mr. Weissmann, I agree with Mr. Geesman. I don't see why this would be an attorney product. We have an economic witness on the stand and we're asking an economic question.

MR. WEISSMANN: Well, I think to answer

this more fully, your Honor, we need to have a fuller context of exactly how this analysis was carried out and to what extent it was directed by attorneys.


Okay. Mr. Geesman?


I don't understand what he just said.


Well, what I'm saying is that this is an analysis that was done that was not just an economic analysis, but also included direction from attorneys about assumptions to be made that touch on legal advice, and that's intertwined with the economic analysis that was done.

We don't really have a full record at this point, your Honor, as to exactly what (1350) this analysis was and who was involved in it and how it was undertaken. And so my concern -- my concern is is that if we start to go down this path of revealing parts of the analysis, we don't want to be in the position of having been said to have waived any privilege that might attach to any portion of this analysis. That's our real concern.

So I -- frankly, I don't have a particular concern about the economic part of it. My concern is really that it's intertwined at some point with legal analysis. And we don't want to be said to have waived the privilege that might apply to any aspect of this analysis.


All right. Mr. Weissmann, I think I agree with Mr. Geesman in that the objection you're stating is rather vague and broad. But I am sympathetic to the concern.

So, Mr. Geesman, if we can try and ask the narrow questions focused on the economics, let's see if we can steer clear of Mr. Weissmann's concern.

Do you think that's a possibility?


Yes, your Honor.


You can try.


As long as your Honor (1351) makes clear that the questions that are asked and the responses that are given are not in your view privileged, that addresses our concern.


Okay. That is my view, that I think we can stay clear of privileged issues there. And I ask you to try and do so.


Thank you, your Honor.

Q Mr. Cushnie, were there variances in the economic methodology used for calculating replacement power costs between that which supported Mr. Craver's statement and the methodology you've used in your testimony?

A And to help me answer your question, is there anything specific you mean by your term "variance"?

Q Were the assumptions identical?

A No. The assumptions would have been very different. The analysis presented in my testimony in this proceeding as Phase 1 A proceeding is categorizing and estimating the market costs that the Commission has asked us to do and report in our OMA, replacement energy, foregone energy sales and other miscellaneous costs associated with maintaining a reliable electric service.


The economic analyses that were performed that underpinned Mr. Craver's statements had to forecast prices as opposed to using actual prices, had to forecast how the system would evolve without San Onofre.

Our analysis that we did here in Phase 1 A did not forecast what the system was doing as a result of San Onofre being out. You know, we had to make assumptions about gas prices, power prices, carbon prices, how the grid might evolve in terms of the transmission.

So there were a lot of planning level assumptions that we had to make that far exceed what we had to do for a fairly straightforward estimation of the costs that were incurred as a result of the outages in 2012.

Q Focusing only on 2012, what were the material differences between the two methodologies?

A The analysis that Mr. Craver is referring to was a forward-looking analysis, the balance of 2013 through 2022.

And the analysis in my testimony was specific to 2012. They were very different time periods.

Q Mr. Craver's analysis did not cover (1353) 2012 at all? A The analysis he was referring to was analysis that the company was using to assess the cost effectiveness of returning SONGS Units 2 and 3 to service.

My analysis in Phase 1 A is looking at what the costs are that we incurred as a result of SONGS 2 and 3 not being available, and we have categorized them and estimated them in accordance with the Commission's OII.

Q Did the analysis supporting Mr. Craver's statement address 2012 at all?

A I don't believe it did. But I was not privy to the final analysis that Mr. Craver and the management team looked at when they made this decision; it was not broadcast through the company; it was kept at a very high level.

Q Did the methodology upon which Mr. Craver's statement was based address foregone energy sales?

A The economic analysis -- the economic analyses that we did to support the cost benefit and assessment for SONGS looked at the entirety of the production of the resources.

Q Was that an answer of "yes" to my question?


A We didn't calculate it as foregone energy sales. We just calculated it as market value of the energy.

Q Did the methodology upon which Mr. Craver's statement was based include the same other market costs as your testimony categorizes them?

A It included capacity related costs. I don't specifically recall that it included any of the other costs that we talked about.

So, for example, I don't recall auxiliary load costs being part of it; it would have been baked into the assumption, presumably. We certainly would have captured PIRP costs. Congestion would have been estimated.

Q Does that complete your answer?

A At this time, yes.


Thank you very much, Mr. Cushnie. Your Honor, I'm complete.


Okay. Thank you, Mr. Geesman. All right. It is almost noon. So let's take lunch and come back at -- can we come back at 1:20 and get started? All right. And, Miss George, we'll start with you. If you would like, I'll come (1355) down at about one o'clock.


I can't hear you.

ALJ DUDNEY: Off the record.




And on the record. Welcome back from lunch. And while we were off the record, Miss George has passed out a couple of WEM exhibits. I believe the witness has those.

Miss George, when you're ready, you may begin.


Q Hello. Is this on? Okay. Good afternoon, Mr. Cushnie.

A Hello, Miss George.

Q What procurement authority were you operating on under in 2012?

A SCE was operating under its Commission approved AB 57 bundle procurement plan.

Q Okay. Well, I have looked at your compliance filings, and it says that the first quarter you were operating still under the D.07-12-052 from --

A That's probably correct.

Q -- from 0612 -- whatever that was procurement proceeding. And then in the second quarter it said that, you know, the (1357) D.12-01-033 had been passed and so you were operating under that. That's correct?

A That sounds correct.

Q And is that true for the rest of the year or did it change from then on?

A Our procurement plan has not changed, to the best of my knowledge, since then. There may have been a very modest modification with respect to who we're allowed to transaction with, but the framework of the plan itself remains unchanged.

Q And for the purposes of the replacement resources for SONGS, are we talking about the system need or just the bundle need?

A So Edison's AB 57 procurement plan addresses our bundled customer need.

Q Right.

A So the procurement that we were doing that is part of our ERRA account entries is for bundled customers.

Q Okay. So that's what's in the ERRA. But in practical terms did you need to replace any energy in the system -- for the system?

A No. The California Independent System Operators is responsible for running (1358) the markets that secure all of the energy requirements to meet the system requirements. As a load serving entity, Edison actually doesn't actually have to do anything, the Cal ISO will procure on our behalf. But we elect to be proactive, and so we do seek to build and maintain a portfolio for our bundled customers that we can then schedule or bid into the Cal ISO markets. So we're effectively self supplying most of our resources when we do that.

The only thing that could be considered potentially system related were certain activities that the company undertook to maintain grid reliability in the South territory. We did enhance certain demand response programs in 2012 to increase the amount of demand response and its ability to respond to an emergent condition. ]

And we did do some very limited transmission enhancements on the system. I'm not an expert as to what we did on the transmission side. And the balance of the system-related activity was performed by the CAISO in the form of doing the CPM designations that we talked about earlier this morning where the Cal ISO contracted for (1359) certain generation resources under its CPM authority to backstop San Onofre's outage.

Q All right. So the things that you did for the South Orange County grid reliability -- you mentioned the enhanced DR and some transmission fixes.

Are those being charged to the bundled customers in this exercise with ERRA? Or are they separated out?

A So the transmission enhancements would be part of our TAC, TAC. It's Transmission Access Charge that the Cal ISO charges on behalf of the utilities. So that would be paid for by all customers that pay TAC.

Q That would not be in the SONGSMA? That would not be recorded in the SONGS OMA?

A The OMA?

Q Uh-huh.

A Bear with me. I'll take a quick look at the account entry just to verify that we did not record it in the OMA. Actually, at line 41, 42, and 43, it looks like there is a transmission upgrade sub-account. And I would imagine that the Commission ordered Edison to do this just to keep track of our total expenditures. But, again, transmission-related expenditures are (1360) authorized through the TAC, which is a FERC-regulated tariff.

Q All right. But other system- related -- you mentioned enhanced demand response.

Was that charged to bundled customers or to the system? Or is it somehow split between them?

A I'm not an expert on our ratemaking with respect to demand response. Most demand response programs, if not all of them, are charged to all Edison system customers. With respect to these particular demand response enhancements that we did, I believe they would have been charged to all Edison customers, not just our bundled customers. But that is something that I would have to double-check to verify.

Q So it would be fair to say that we have kind of a mix between the bundled and the system. When you need it more for the system, that was included in this replacement costs?

A Correct. So the demand response enhancements we did were designed to provide very targeted I'll call it resource contributions to the South Orange County grid during periods of time where we would have (1361) had high loads and were potentially facing a transmission contingency. We would have then been able to fall on these demand response programs, which would have either reduced severity of the situation or mitigated it.

These resources were not procured to meet the energy requirements of bundled customers or system requirement -- or system customers. The program is for exclusively designed as a grid reliability measure.

Q If you'll open the Neil Miller section of the exhibit, page 507.

A Which exhibit?


Which exhibit is this, Ms. George?

MS. GEORGE: This is Exhibit 24.

THE WITNESS: Yeah, I show 510.


Q My recollection it's somewhere in here -- but I'll have to check -- is that Mr. Miller testified in the procurement hearings last summer in 2012 that they were interested in using demand response, but they didn't find any that they could actually use.

Is this the demand response program that we're talking about?

A I can't speak to what Cal ISO's Mr. Miller was referring to. I can address (1362) to a limited matter what the Edison demand response programs were that we did to enhance grid reliability in South Orange County.

Q I think what I'm asking is whether or not the ISO recognized that as a resource addition?

A They did not recognize it from the standpoint of increasing the amount of resource adequacy capacity that was available to load-serving entities to use to meet their RA requirements. In terms of their emergency operations, I'm not sure what they did to account for this. It may have been something that just Edison was planning on employing if Cal ISO wasn't going to recognize it.

Q All right. So in any case, you did conduct some demand response programs for the replacement of San Onofre?

A We implemented some programs. I can't tell you to what extent we called upon them. But we did implement some programs.

Q And is that cost listed?

A We did capture those demand response costs. For 2012, we recorded $2,769,000.

Q And there was also a 10/10 program. Is that the energy efficiency incentive? Or is that a demand response incentive program?


A The 10 and 10 is a demand response program. It's one of the four programs that we implemented in the summer of 2012.

Q So does this 2.7 million include the 10/10 program?

A Yes, it does.

Q Okay. One of the things that we're considering and the Commission asked us to consider is the foregone sales of nuclear power.

Can you tell me why do you think we should be considering the financial implications of something that didn't happen?

A In what sense do you want me to opine on that?

Q Well, I'm asking you what does it have to do with replacement power cost since it didn't happen?

A So consistent with what the Commission instructed Edison to do in its October 2012 OII, Edison is complying with that investigation requirement by recording in our OMA our estimate of the foregone energy sales revenue. What the Commission is going to do with that estimate presumably will be heard in Phase 3 of this proceeding.

Edison has not taken a position at this point in time as to what the Commission (1364) should do with any of the costs that we have recorded in the OMA other than to say we should be entitled to recover all prudently incurred cost, which is what the quarterly compliance review process and the ERRA review process reviewed to determine and then allow us recovery in rates.

Q So with the nuclear power costs, the foregone sales -- would that increase the amounts that Edison would receive?

A No. That amount that we had calculated recorded into the OMA does not go into the ERRA. It's just an accounting exercise.

Q Generally speaking, does Edison follow the loading order in its procurement?

A Yes.

Q And does it follow the loading order in terms of the requirement in DO 712052 to go back and look for more renewable energy in its procurement -- more than it got from its other programs?

A So all of us in procurement is open to resources that meet the identified need. So we're purchasing just energy. Any resources that can provide energy is eligible to bid their output to us. And we will award based on the lowest evaluated cost. To the (1365) extent that there's an RPS resource that would be bidding into that solicitation, we will give it credit for its RPS value.

The challenge we have in doing RPS procurement outside of the Commission-defined programs is that the Commission requires all of our contracts to be preapproved. And that's a very lengthy process. So if we need energy for tomorrow, for example, I can't buy an RPS-eligible product because I have to get it preapproved. And we have asked the Commission for authority to do short-term RPS procurement. And to date, the Commission has not granted us that authority.

Q My understanding is that there are small providers of preferred resources that are in a queue that had been waiting for years and, in fact, that Edison has been sued by one of them for not allowing them to connect.

Is that a preapproval problem?

A I would need to know the specifics of that situation. What I will say is that Edison has a lot of standard procurement programs for small renewable projects. We refer to them as feed-in tariffs.

And to the extent that they meet the criteria of that feed-in tariff and (1366) they're awarded a contract, then it's incumbent upon that resource to get on-line. And there are resources both renewable and nonrenewable that encounter inter-connect challenges for a variety of reasons. And some of those energies challenge Edison on those inter-connect challenges that they have.

And so without knowing the specifics of what I think you're talking about, I really can't opine any more on it.

Q But there are hundreds of these small projects in the queue; is that right?


Your Honor, excuse me. I'm going to object on scope. I believe that the scope of this phase is costs that were incurred, not alternative resources that might have been procured.


Sustained. Ms. George --


This is a question of availability of the resources, I believe. That's the way I'm looking at it.


Right. But the intent of this phase is to quantify the costs that were incurred more than to understand what other options there could have been.


All right.

Q Were there any preferred resources that were used to (1367) substitute for San Onofre's power except for the demand response programs that you described?

A Edison bid or scheduled all of its preferred resources into the market on a regular basis. Except to the extent those resources were provided schedules by the Cal ISO, they met a portion of system requirements.

Q When you say Edison its preferred resources, and so these are preferred resources that Edison already owned or had under contract?

A Most of our preferred resources are under contract. There are very limited amount of small hydro projects that are considered preferred resources. And we have a very limit amount of solar projects that are utility-owned. So most of the preferred resources are contracted. All of our contracted and utility-owned resources were bid -- were scheduled into the Cal ISO markets and were utilized in 2012.

Q Was there a solicitation by which new resources were allowed to compete for replacing San Onofre?

A Other than the standard programs that we run for renewable resources, these (1368) feed-in tariffs that I was discussing, there was not a solicitation that I recall beyond those.

Q And did you have a solicitation of any kind for conventional resources to replace San Onofre?

A No.

Q Why not?

A In 2012, we were operating under the premise that San Onofre would be returning to service within one to three months of any given operating day. So our planning horizon showed Units 2 and 3 -- Units 2 and 3 returning to service in fairly short order.

And so it didn't make sense to conduct a solicitation that would take months to run for a need we didn't think was going to exist. So we did our procurement as we typically do in the shorter term markets. And we sought to maximize the dispatch of the resources that are in our portfolio.

Q When you decided to put Unit 3 in a preservation mode, didn't you need to procure resources to replace that power?


Your Honor, objection. Scope.


I'm just trying to (1369) understand how the decisions were made about this supposed emergency replacement problem that they had.

---+++ MR. WEISSMANN: My objection, your Honor, is we're getting beyond subject of the costs that were actually incurred.



We're actually not getting -- you'll see I have a lot of questions about the actual cost. But the question of whether or not resources that were already being paid for, in part, whether they were allowed to participate in this exercise of replacing San Onofre.


Okay. Ms. George, go ahead. I think that keeping it focused on how the resources were used and what resources were procured is appropriate. Go ahead.


Q Does Edison design its energy efficiency portfolios?

A Edison participates in a CPUC proceeding on which the parameters of the energy efficiency programs are established. And then Edison executes on those programs in accordance with the Commission decisions.

Q And so it does design some of the programs?


A It proposes designs.

Q Proposes designs. And then does Edison decide which third parties are allowed to design and execute third-party programs?

A Parties that are conducting energy efficiency measures outside of the utility procurement process are free to do whatever they want. Edison doesn't control that. For third parties that are participating in the utilities energy efficiency programs, then they would have to conform with the requirements of the energy efficiency program that the Commission approved and that Edison is administering.

Q In other words, Edison has control over the ratepayer energy efficiency funded programs?

A Subject to Commission direction.

Q Subject to Commission direction. And there are no competitors for that?

A Not that I'm aware of. Not for the CPUC-authorized energy efficiency expenditures that are allocated to the utilities for administration purposes.


I'd like to refer you to Edison's SCE-3, the ERRA testimony. What is the number because I got SCE-03 on one that came out in April.



Yeah. I believe for purposes of this proceeding, this hearing, it's been marked as 38.


38, okay. Thanks.

Q This is talking about the foregone energy sales net revenue. And there was actually a similar quote in the very first page about the market prices whether they're lower. I mean, this one says the market prices would have been lower if SONGS-based load generation had been available to the market. But the actual price reduction cannot be known.

Do you see that section?

A Yes, I do.

Q And then at the end of that sentence, it says "An estimate of the impact" -- I'll just read the whole thing:

"The actual price reduction that would have been realized cannot be known because market participants would have undoubtedly bid and operated the resources differently in an environment in which SONGS was not experiencing an extended outage. But an estimate of the impact can be provided by examining previous changes in market prices as a result of changes in load and resources."


What sorts of things would affect changes in load?

A My reference here was primarily to weather. So as temperatures change, as cloud cover changes, as humidity changes, that will drive a different load result. And if you think about the market clearing function that we have in California, at its essence, it's a supply and demand curve. So as you move further up the demand curve, you're paying a higher price. As you move down the demand curve, you're paying a lower price.

Q Are there other things that affect changes in load?

A Obviously, demand-side management programs can have a permanent effect on load, if they're energy efficiency. For demand response, if it's a permanent load shift, that will change the load. If it's just a callable program, then it will just have a episodic change on load.

Q Take a look at O&M 24, page 673, at the bottom of the page. It says "Have you used energy efficiency funding to reduce the needs for power in the emergency with SONGS out of service?"

Do you see that?

A Yes, I do.


Q And you state that you didn't know about any -- "I'm not aware of any incremental energy efficiency programs that the company has undertaken as a result of the San Onofre being out of service."

Is that still your position that you don't know of any energy efficiency that was undertaken?

A No. Since the time of the hearings and long-term procurement plan, I have become aware of four programs that the company undertook to enhance local area reliability in South Orange County area.

Q But those were demand response programs?

A Those were demand response. I'm still not aware of any energy efficiency programs.

Q I wanted to refer you to the page 674 in that same exhibit, bottom of the page: "Are demand side resources required to be cost-effective, energy efficiency in particular?"

A Yes, I have that.

Q And you stated -- this is in the procurement hearings last summer in 2012 -- that your understanding is that they're all required to be cost-effective as defined by (1374) the Commission.

And then you defined that as cost-effective as they are cost-effective relative to the next competing resource to meet that particular need.

So when you say that you used Edison's -- the resources that Edison had and deployed them based on which one was more cost-effective, this would indicate, would it not, that energy efficiency was the most cost-effective resource that you had?


Could you restate the question? because I lost it. I apologize.


Q Given this statement in the procurement proceeding about cost- effectiveness, would you say that regarding the need for replacement power for SONGS, that energy efficiency would be the most cost-effective alternative?

A I'm going to answer that question in two parts. My testimony that you referred to here in last summer's long-term procurement plan proceeding was referring to cost-effective in the context of other resource commitments that a utility could make. So it's a long-term resource assessment; it's not a dispatched decision from day to day. (1375)

From what I understand your question to be, you were asking if because we needed to replace San Onofre generation at times, should we have been purchasing energy efficiency because it's more cost-effective? Energy efficiency programs, as I'm sure you're aware, take a while to implement and put in place.

Edison has limits on what it could do with its energy efficiency programs governed by the CPUC's authorization of our energy efficiency spending. And so for purposes of day-to-day procurement, there are no energy efficiency programs available to us to acquire relative to other resource types.

Q There are none available to you?

A I cannot buy energy efficiency for delivery tomorrow.

Q How long does it take for Edison to screw in a light bulb?

A That's not an energy efficiency program.

Q There are many energy efficiency programs that involve screwing in light bulbs.

A No. I understand. But energy efficiency as defined by the Commission's programs -- again, I'm not the expert here -- (1376) establish a minimum baseline using existing codes and standards. And the energy efficiency program that you implement has to produce energy savings above that baseline standard.

And these programs have to be performed in accordance with the program rules of the Commission's energy efficiency decisions. And so when we look at something like day-to-day procurement, we can't do programs like that for tomorrow and the next day. These are long-term programs that we're implementing.

Q I'd like to refer you to the I think it's 118. It's energy efficiency -- this is the energy efficiency report from Edison, monthly report as of January 31st, 2012. And what I've done here in this exhibit is to spare everybody the multiple pages of program descriptions. We just cut to the chase, and we're focusing on the bottom line, the actual totals of the budgets and expenditures.

And it's the third page down. So in the budget, you'll see it's divided into four pieces. And the first one is adopted budget. And the second is the revised budget. And then it's a program expenditures (1377) to date. In other words, the expenditures starting in 2010. This is a three-year cycle. So the 2012 is the last of the three-year cycle, as you mentioned in your rebuttal testimony.

And then the fourth line was the report month, how much was spent in that month. And then there were -- the last one is commitments. Those are -- commitments means future programs.

So just focusing on the expenditures to date and the adopted program budget you'll see that the expenditures are about $608 million, and the total budget is 12 -- you know, 120 million. So it's essentially half of that money is left to be spent in 2012, around $600 million at that point.

So is that more than all of the other money that was spent on replacement costs in 2012?

A Are you asking if the 608 million that the company reported spent to date is more than the replacement costs or the residual --

Q I'm asking you to do a little subtraction in your head. You know, how much it spent to date was 608 million. It has a (1378) budget of 120 million. And so 6 is half of 12. So, essentially, you've got 600 million left to spend in 2012, minus the commitments, of course, which are 99 -- so it's actually 500 million. But, essentially, $500 million that is more than all of the replacement costs; is that correct?

A So I'll answer your question this way: Edison has calculated roughly 259 million of replacement energy expense in 2012; 131 million of foregone energy sales; offset by 66 million of estimated costs in replacement energy sales that would not have been realized because the units would have been on a planned outage.

Further, we had capacity related costs of 33 million, and other miscellaneous costs of 16 million. The net total of all those are 373 million, which is less than 500 million.

Q And you agree that energy efficiency is cost effective compared to the next competing resource?


Objection, your Honor. Misstates testimony.




Q Well, we had the cost effectiveness discussion a little while ago (1379) from the procurement proceeding. If you don't like my paraphrase, would you like to offer another one?

A I believe what I said were words to the effect that energy efficiency must be cost effective. And the Commission, as I understand it, defines "cost effective" as relative to another long-term planning resource that you would otherwise install but for the energy efficiency. It's not related to the day-to-day procurement and dispatch of existing resources.

Q All right. Well, you had Unit 3 was in preservation mode as of June. Is that the correct date?

A I don't recall the exact date that Unit 3 was laid up.

Q I believe that was in the time line. Let's say give or take a few months. It was almost half of the year. So at that point in June, right at the beginning of summer, you knew that that resource was not available for the rest of the year.

So saying that you're -- that you, you know, thought it was going to come -- you didn't think it was going to come back on line. So in that sense would it have been cost effective to use energy efficiency?



Your Honor, I object to scope. We're really getting into an alternative procurement plan idea.


I'm going to sustain it at this time, Mr. Weissmann.

Yes, Miss George, I think we have strayed beyond quantifying the actual costs incurred. So...


I'm trying to determine whether the energy efficiency costs are going to be counted or not. Energy efficiency costs were incurred.


Well, I think counsel is pointing out other energy efficiency funds that might have been available. That might be an appropriate subject for the Commission to consider in the energy efficiency docket. But here we're focused on the costs that were incurred.


I'm sorry. If you'll let me pursue a line of questioning, I believe you will see that this has everything to do with the cost of the resources.


This has to do with the cost of the replacement resources or the cost of --


Yes, the cost of replacement resources, including, you know, (1381) whether or not you're going to count the energy efficiency costs.

Q You know, for example, your energy efficiency programs, are you telling us that there was no energy efficiency done in the West LA Basin in 2012?

A I'm not going to tell you that. I'm not aware of anything that was specifically done as a result of the San Onofre outages. It doesn't mean the company didn't do something. I'm just personally not aware of anything that we specifically did as a result of the SONGS outages.

Q I believe that you -- your testimony states that any -- a resource is not -- let me find this. It's in SCE-38, page 1.

SCE manages its bundled customer requirements on a portfolio basis; therefore, it does not ascribe a specific demand or need for its individual energy related transactions; therefore, it is not possible to tag specific energy transactions as having occurred as a result of the SONGS outage.

Why would you exclude energy efficiency when you say that it is not possible to tag specific energy transactions as having occurred as a result of the SONGS (1382) outages?

A So to make sure we are not confusing concepts here, this passage that you just cited pertains to how Edison manages its bundled customer portfolio. So how does Edison meet the energy requirements of its bundled customers? How does Edison meet its resource adequacy obligations for its bundled customers? And SONGS is just one resource of many that we manage.

Q And isn't energy efficiency another?

A Energy efficiency is managed through energy efficiency programs. And once those energy efficiency programs are implemented, the reduction in load accrues to the benefit of all benefiting customers. So that energy efficiency savings may accrue to customers that aren't Edison's bundled customers; they may be direct access customers, for example.

We account for the reduction in load as a result of energy efficiency in our load forecast. So we forecast lower requirements. And if our forecasts are correct, we will actually meter lower requirements. And a lowered metered load results in a lowered bill from the Cal ISO. (1383) So energy efficiency is captured in our portfolio of management through load reduction.

My passage here is talking about how do we handle our resource procurement. And our resource procurement doesn't tag particular transactions to a cost. We have a net open position; it's either long or short. And so if we're short, we're buying. If we're long, we're seeing selling. But we don't attribute the purchase or the sale to a particular action in the portfolio.

Q But energy efficiency reduces that need.

A Yes, it does.

Q And in that sense it does meet -- it is an equivalent, isn't it?

A Well, it's the highest resource in preferred loading order. So all else being equal, we prefer to reduce the load through energy efficiency than to procure a supply side resource to meet the load.

Q And but you said you didn't do that when you had a major emergency?

A The second component of your question is what are we doing as a result of the San Onofre outages as it pertains to maintaining system reliability. So from a (1384) grid --

Q Well, pardon me.


Can you let him answer the question, please?


Go ahead, Mr. Cushnie.


From grid reliability perspective, Edison did do things. Edison sought to implement demand response programs that were within our control that were targeted to the South Orange County area. We did some limited transmission upgrades that were within our wherewithal to do in a short period of time.

The Cal ISO did their CPM designations on a handful of resources to make sure they were available and could operate to maintain grid reliability, again, in the South Orange County area. But we did not do any targeted energy procurement because that's a bundled customer requirement.


Q In energy procurement or energy efficiency program?

A Energy procurement. Just general energy procurement. We did not do anything targeted for the loss of SONGS.

And on the energy efficiency side, I am not personally aware of anything that (1385) the company did to have a targeted energy efficiency program that was outside of what we were already authorized to do to deal with the Summer 2012 reliability concerns. I can surmise why we didn't, but I don't know for sure.

Q You could surmise why you didn't?

A Why we didn't, yes. Because those programs would not have been consistent with the -- with the adopted energy efficiency programs that we have from the Commission or they would not have been able to be implemented in a timely manner.

Q Even though that money was supposed to be spent by the end of the year?

A The company's management of its energy efficiency budget is governed in the energy efficiency dockets that the Commission oversees. I don't know what the spend projection was that they had for the balance of 2012.

I do believe that the spending that was authorized for -- into 2012 was granted late in the cycle; and, therefore, that may have been why they weren't able to spend as much as they might have otherwise been able to.

Q Is there any communication between (1386) the procurement department and the energy efficiency folks?

A There is much more communication with the demand side management folks because those resources are dispatched. Energy efficiency, when the programs get implemented, they communicate that to us so that we can account for our load forecast.

Q You mentioned in response to Mr. Shapson this morning that there was congestion in the LA Basin due to the SONGS outage.

A Correct. I said the levels of congestion were higher post-outage than prior to the outage.

Q And so that costs money. The CRRs, Congestion Revenue Rights, is that a cost or is that a benefit? I'm not clear.

A So the congestion is a cost to generators. And if you have a CRR, which is a Congestion Revenue Right, a financial instrument, you get paid the cost of congestion. And so it nets out. So if you are a generator that incurred $10 of congestion costs and you have a CRR that gets $10 of congestion revenue, they net out and you're indifferent to the cost of congestion.

Q You, as the utility, are (1387) indifferent? Or the generator is indifferent?

A The generator that holds CRR is indifferent.

Q And what about the utility?

A The utility is impacted to the extent that it holds more or less CRRs relative to the congestion that was realized. If we have more CRRs, then we're better off because the higher congestion means more revenues for our customers. If we have less CRRs, it means that our customers incurred a net cost increase as a result of the congestion.

Q So you're saying there is a benefit to having a congestion situation.

A Theoretically there is a benefit if you are long CRRs and you are basically resource for the balance of your energy needs.

There's a lot of other things that you would need to consider. You can't just look at that in isolation. But you could conceivably be better off with congestion, depending upon your CRR position and your net short position.

Q Does the congestion drive up the costs -- (1388)

A Congestion drives up --

Q -- of the energy?

A It drives up the market bearing price of energy.

Q So in that sense does the utility see that as a benefit or as a detriment?

A Edison prefers to see market prices be set at a competitive level, which generally would mean lower than what we typically see.

Q And would energy efficiency reduce congestion?

A It depends. Congestion is from point to point. And so certain energy efficiency or supply side resources can actually aggravate the congestion. If you have a constrained path and you put less load on the constrained side, then you have more energy that is trying to move from the constrained side to the unconstrained side, and that will actually aggravate congestion. So it has to be in the right location.

Q And you would know what's the right location?

A Generally we do. But the grid is very dynamic. So at any given hour, depending on what our plants are operating, the congestion can flip on you in certain (1389) locations.

Q So --

A So, for example, sometimes congestion coming from Northern California into Southern California can be quite expensive. In the Spring, for example, when there is a lot of hydro energy coming out of the Pacific northwest and there are not a lot of loads in the northwest, there is energy flowing north to south. But in the summer, in the old days, there would be more energy flowing south to north.

So congestion could be north to south or south to north, depending on the conditions of the year.

Q So could Edison plan for a power plant to go into any area where there was a congestion? I mean, is that one of the things that you could do is have a resource that was in the right place for the congestion issue?

A That's our objective is to site resources and DSM programs in locations where they relieve congestion on average.

Q And energy efficiency can be done almost anywhere; right?

A Correct.

Q So that would be very easy to (1390) deploy in a particular location?

A Correct.

Q And so it could have been deployed in South Orange County, and probably was in these programs; is that true?

A I would imagine that our energy efficiency programs did capture some opportunity in South Orange County. But that would have been done as part of the system-wide energy efficiency programs that we have. Orange County being part of the system-wide requirement, would have picked up a portion of our energy efficiency programs and funding.

What I'm not clear about is whether we did anything targeted to South Orange County as a result of the SONGS outages.

Q Did you keep track of what you had accomplished in energy efficiency in South Orange County so that you could know whether you benefited from it or not?

A The Edison company would be keeping track of it. My organization does not, other than to take into account the aggregate energy efficiency savings that we believe are being realized because that's an input into our load forecast.

Q Thanks. Was Huntington Beach an (1391) effective location for replacing power from SONGS?

A The Cal ISO determined that Huntington Beach was an effective resource, and, therefore, location to maintain grid reliability as a result of the SONGS outages.

Q There are a number of once-through cooling old power plants down there. Is that the only one that was available to be restarted?

A I believe the other once-through cooling facilities were largely available and already made available to the Cal ISO under the State's resource adequacy program. And Huntington Beach 3 and 4 had been retired, and Cal ISO brought them back for a limited duration in the Summer of 2012 to help enhance grid reliability in the South Orange County region and the San Diego service territory.

Q I would like to refer you to the WEM-24, Dr. Hunt's testimony.

A Do you have a page number, please?

Q I'm looking for it. Hang on a second. 861. I think it's in the end of it. I don't have a physical copy here.

A I have that.

Q Do you see on line 4 that "AES (1392) filed a petition with the Energy Commission requesting the transfer of ownership of Huntington Beach 3 and 4 from AES to Edison Mission Huntington Beach"?

A I see that.

Q Your rebuttal testimony said that you didn't own the resource. Is that -- would it make a difference if Edison mission Energy did own the resource?

A Yes. Edison Mission Energy and Southern California Edison Company are two separate legal companies, and Edison Mission Energy at that time was an affiliate of Southern California Edison. Both were owned at that time by Edison International.

The PUC has strict codes of conflict in place to prevent the unregulated affiliates from utilizing regulated assets to further their business interests.

I work for Southern California Edison, part of the regulated utility. I do not have insights into what Edison Mission Energy is doing, nor do I provide them assistance in their work objectives.

Q I understand that. However, your statement in your rebuttal testimony was that Edison International or Edison Mission Energy did not own Huntington Beach; and Dr. Hunt's (1393) testimony last year was that they do. And so what I'm asking is since that was a resource that you -- you mentioned that the ISO procured that resource.

So did Edison not have any contract with the resource? Cal ISO market?

A The California Independent System Operator issued CPM contracts to Huntington Beach 3 and 4, and those contracts were issued to AES. So the arrangement to run Huntington Beach 3 and 4 were between the Cal ISO and AES.

AES sold its ownership interest in Huntington Beach 3 and 4 to Edison Mission Energy so that Edison Mission Energy could acquire some emissions offsets to build their Walnut Creek power plant.

When Cal ISO sought to return Huntington Beach 3 and 4 to service, Edison Mission Energy made arrangements with AES to return those assets back to AES to be able to be utilized in a CPM contract with the Cal ISO.

I don't know the arrangements that Edison Mission Energy had with AES to first purchase the units, and I don't know what the arrangements were to return the units back to AES. Those were contracts that were between (1394) those two entities, which Edison has no part of -- Edison utility has no part of.

Q But this testimony of Dr. Hunt is in August of 2012, and he's not mentioning any return of Huntington Beach to AES.

A His answer at line 10 says, "Well, I'm familiar with the ownership change. Now, what this document doesn't incorporate is that Huntington Beach was then leased back to AES. And AES is now operating Huntington Beach, not Edison Mission Energy."

I don't know whether it was leased or sold. I just know there was a commercial rrangement to return the ability to operate the units back to AES.

Q Thank you. And you mentioned in SCE-37 on page 21 -- this has to do with the preferred resources: "So the extent that SCE failed to meet the State's goals in this regard, the Commission should address the deficiency in the relevant Commission docket."

Are you suggesting that SCE missed their goals?

A You said page 21?

Q Page 21, yes.

A And line numbers, please?

Q 1 to 3. Maybe it's 38 and not -- (1395)

A No. I have the cite. I'm just reading it.

Q It's the rebuttal testimony.

A So, to begin with, no, I'm not suggesting that Edison did not meet its obligations or goals with respect to utilizing preferred resources.

What I was attempting to address was to the extent that a party such as WEM was indicating that Edison should have done more, that that would be a subject of review in the applicable docket for that resource type.

Q Do you have the chart, the colored chart for -- I handed those out. Here. Here we are. These are -- should I give one to the witness?


Is this something that was distributed in advance?


This was part of our comments in December and it's out of the procurement proceeding in --

Here, I'll give you one for the witness.


Consistent with the ground rules, your Honor, we have not been given this exhibit in anticipation of this cross-examination, so we would object. (1396)


All right. Mr. Weissmann, would you care to take that a step further? Could we -- and propose a solution, perhaps?

Could Miss George mark this as an exhibit, and we'll talk about it tomorrow, for example?


Well, I was hoping Mr. Cushnie would be excused today. But perhaps we could look at it over a break.



Miss George, would that suit you to perhaps pursue another line of questioning?


Yeah. I can finish my other questions and then come back to it afterwards. That's fine.




Thank you.

Is the nuclear fuel -- has that been removed from this part of the proceeding? I'm a little confused. Are we still talking about nuclear fuel costs here?


There was rebuttal -- there was DRA testimony and rebuttal testimony on the subject of nuclear fuel as it relates to the computation of the replacement power cost.


Okay. That's what I thought. And then I heard from someone else (1397) that it was removed, and I thought maybe I missed something.

Q I want to ask you just a couple of questions about the greenhouse gas costs. At what point is SCE involved in the creation of nuclear fuel? Do you buy it at the mine and then take it all the way up? Or at some other point?

A Miss George, that's not my area of esponsibility, and I don't think I'm competent to address our nuclear fuel procurement practices. That was done at the power plant.

Q What about greenhouse gas costs? Are you familiar with those?

A I'm familiar with those, yes.

Q Are you aware of any greenhouse gas costs involved in the procurement of nuclear fuel?

A There's not any GHC emissions created that I am aware of in our purchase of nuclear fuel. Keep in mind that California's Cap-and-Trade Program is looking at GHG emissions that are produced in the State of California. And for energy that's delivered to California, the originating source will make assumption about what the portfolio mix of GHG emissions would have been for that (1398) area.

The mining and enrichment of nuclear fuel, to the best of my knowledge, is done outside of California; therefore, it wouldn't be subject to California's Cap-and-Trade Program.

Q And no other states have any greenhouse gas costs that might be imbedded in the cost of the vendor to you?

A I'm not aware of any other formalized GHG programs. There may be some, but I couldn't answer that question.

Q What about the back end of the cycle? Did Edison pay for the greenhouse costs to haul away the steam generators?

A The Cap and Trade Program went into effect January 1, 2013. And it applies to generation resources. I don't believe the program applies to mobile sources in the Commission at this point in time. I don't know that it ever will.

Q Did Edison build that truck? Or did you pay somebody to build that?

A I believe the truck previously existed, but I'm not sure.

Q The 80-wheeled truck or whatever it is.

A I seem to recall reading an (1399) article -- internal company newspaper article that it's a very specialized truck to make arrangements to utilize it. But that's the best of my recollection.


Thank you. Those are all my questions for now.


So, Ms. George, just to make sure I understand correctly, that's all your questions except for this colored chart?


ALJ DUDNEY: So we'll take a 15-minute

break. And then you come back at 2:45, and we can move on. Okay.

Off the record.


Let's go back on the record.

While we were off the record, I told the parties about the idea of ending early today and starting early tomorrow morning. So that would be try to wrap up around 3:30 this afternoon and resume at 9:00 a.m. tomorrow. Everyone has I think indicated that that's okay.

Mr. Geesman noted that he may not be able to get here promptly at 9:00 due to obligations in another proceeding. But I think it's quite feasible that we will just (1400) schedule his turn to cross-examine the witnesses after he's here.

So is there any objection to that plan?


None from DRA, your Honor.


Hearing none, we will plan to do that. But, again, we'll just review whoever's at the stand at the end of hearings today.

So, Ms. George, go ahead.


Q During the break, we were looking at this exhibit. And do you understand that it's from a planning assumptions in the procurement Case R.10-05-006?


Your Honor, I'm not sure what the question is, but we do object to the use of this exhibit as something that we don't know the data sources or anything else about this chart. This is not something Edison prepared.


Well, the data sources are the administrative law judge ruling in the procurement proceeding. I filed this in the comments in December -- and WEM's comments. And so that is already in the record. And this was part of that document, actually. (1401)


It's not in the record of this proceeding, your Honor. There's no foundation for this document. With that said, if she wants to ask witness a question about it, see where it goes. But I just want to register our objection to the document.




I'm a little confused. When you have comments in a proceeding -- in this proceeding, and my understanding is that those are in evidence. All of our comments are on the record in this proceeding. And so I'm a little confused about you're saying that it's not in evidence in this proceeding because I believe it is.


I thought you said it was in the long-term procurement proceeding.


No. I'm saying the source of this document is the long-term procurement proceeding. But the chart itself was filed in our December comments. I think it was actually in our reply comments, but.


Well, that wouldn't be evidence.


Excuse me?


That would not constitute evidence.


That's what I'm asking.



So, Ms. George, let me see if I can state my understanding of this document. And both of you can go from there. And we'll figure out what to do with it. So in the long-term procurement proceeding, there was an administrate law judge ruling that set forth some planning assumptions.


That's right.


And then what Ms. George has done here is redisplay some of those planning assumptions and make some additional calculations there. And then this document as it's presented here was submitted as an attachment to earlier WEM comments in this proceeding; is that correct?


Actually, it was on the page. We just stuck it in the documents.


Okay. This was in --


It was in our comments in this proceeding, yeah.


Okay. Mr. Weissmann.


Again, your Honor, we don't have any record about how this has been compiled, what data sources were used, what assumptions were used. It's not in evidence. And having said that, if she wants to ask the witness a question about it, he can answer to the best of his ability. But I do object to (1403) the introduction of this document into evidence.


Okay. So Mr. Weissmann has agreed to allow Ms. George to ask questions about this, and we'll see how it goes.

Okay. Ms. George, go ahead.


Q You a witness in the procurement proceeding in 2012, right?

A Yes.

Q And also in 2011?

A I don't recall being a LTPP witness in 2011. I would have to search my records.

Q I think you actually were.

Are you familiar with the LTPP planning assumptions?

A I'm generally aware of the planning assumption process the Commission employs for LTPP.

Q And, essentially, it lays out the different resources, the amounts expected in future years, usually a ten-year window; is that correct?

A That's correct.

Q So this particular chart utilizes the planning assumptions from that proceeding in 2011. And then it just subtracts the nuclear power plants and demonstrates that (1404) there's plenty of power even without nuclear power plants, that as of 2011, with nuclear power in place, there's 150 percent of demand statewide, given all of the programs that we have.

And if you took the power -- the nuclear power plants out of that picture, you'd still have 140 percent. This is just a mathematical exercise that we did in this chart.

And then there's a visual upper right hand that shows how much that excess power there is and the fact that it's sort of a flat, not really -- there's not really an expansion of energy need.

And nuclear power is just a pink line across the top. So you're pretty familiar with the demand in California and the demand in Edison's territory, right? That's what you deal with as a procurement planner all the time.


Wait, wait, wait, wait. I'm not sure what he's supposed to do with that preamble.


Q I'm just asking whether that's his bailiwick, is understanding how the procurement -- you get this many demand side resources and then this many supply side (1405) resources. And you try to make the system work. That's the basic idea.

A So my job as director of portfolio planning and analysis for Southern California Edison -- my organization is responsible for developing all of our price forecasts, our load forecasts, our developing or portfolio planning assumptions with respect to procurement, and for doing our flow modeling of the system to understand the impact of congestion. We do a few other things as well.

All of this comes together to help us develop a procurement plan for meeting our bundled customers' requirements. We have a separate organization in the company called Integrated Planning that does the traditional utility resource planning functions where they look at the physical structure of the grid. And they look at the interplay between transmission, new resources, long-term demand side management programs. And they are the organization that participates in these long-term procurement plan proceedings consistent with the values that you've provided here in this table.

So, in summary, my group is responsible for figuring out what actually to (1406) buy and how to buy it, where to buy it. And the other group is responsible for figuring out what does the state need.

In looking at this table and subject to the recognition that I haven't had a chance to verify all of these data points, the energy demand that's being record for SCE seems very low compared to what our system demand is. Our system demand I would think would be between 22 to 23 thousand megawatt level. And everything here is three to four thousand megawatts below that.

Q Well, that could account for -- I mean, some of the demand side resources are obviously incorporated. The goals of the energy efficiency programs and the expectations for demand response and CHP -- they're all incorporated into these figures. That's how the planning assumptions work. So it sounds like your other department is more -- would be more familiar with this type of accounting.

But so you think the demand is actually a little higher than what this shows?

A Well, certainly in 2011, 2012, and 2013, that's a -- it's lot higher. The demands that we've realized have been (1407) considerably higher than these. And they are not our peak demand. Our peak demand occurred I want to say in 2006 or 2008. So these demand levels are significantly below what we actually experience today.

Q So you would disagree with the planning assumptions, if they were in fact the ones here. And I also want to put a caveat -- I know this is getting to be a compound question. But basically these do not reflect the need, the once through cooling replacement needs. This was the previous LTPP where they did not look at those numbers?


Your Honor, objection to scope.


May I describe what the issue is here?


Go ahead. Describe where you're going.


Q Was there really a power shortage due to the SONGS outage? Your testimony says that the market prices were higher due to the SONGS outage.

Is that really the only possible reason why the market prices were higher?

A No. TURN actually introduced an exhibit that was an excerpt from a Cal ISO (1408) study that said market prices were higher for a variety of reasons including higher than average demand, hydro conditions being lower than average. And I don't recall the third one. But the fourth was San Onofre's being on a forced outage.

Q Was market manipulation one of those?

A Cal ISO did not identify market manipulation as a reason why prices were otherwise higher.

Q But there was market manipulation in 2011 and 2012; is that correct?

A It's not my place to say whether there was market manipulation. That's the FERC's job. I will note that the FERC has fined several entities for market manipulation. So presumably there was something going on. But I don't have access to understand whether the markets are being manipulated. I can have my own personal opinion on that, but I don't have any facts to back it up.

The other thing I wanted to address, Ms. George, is my testimony did not say that there was a energy shortage. My testimony said that with the absence of SONGS, that there was a local grid (1409) reliability concern in South Orange County.

What that means is in the event of high loads and transmission constraints, there may not be enough generation to reliably serve the load in South Orange County. And by that, we mean not there's not enough energy, but that the grid itself will collapse because it becomes unstable because the generation is not in the right location.

My testimony on prices being higher are just a simple supply and demand observation. If you remove 2150 megawatts of low-cost baseload generation from the supply demand market design that we have, you move higher up the supply curve to serve the same load. And therefore prices are higher.

Q But there's no energy shortage. Is that what you're saying?

A There's no energy shortage. There are sufficient resources to meet the load except for the potential for transmission constraints during peak demand.

Q Is there a glut of power?

A I would not define it as a glut. There are times where we have more energy than we can use.

Q Was San Onofre part of the energy that you had that was more than you could (1410) use?

A Since late January, both units were unavailable. So, no, San Onofre was not part of the energy that we received that we could not use.

Q Was it in January 2012 or earlier?


Your Honor, objection to scope.




Q Was J.P. Morgan subsidiary acting as a broker for SCE in 2012?

A Not as a broker. Edison did have contracts that J.P. Morgan was a counter party to. Therefore, we would have to exchange the necessary information to schedule resources.

Q I'm talking about their subsidiaries as a -- I believe as a broker, J.P. Morgan Energy Ventures and another one called Becka (phonetic). Are you --

A I'm familiar -- I'm responding to your use of the term "broker." A broker typically is an entity that facilitates the transactions between parties. They know what the prices people are willing to pay to buy power, what prices people are willing to accept to sell power. And they bring counter (1411) parties together to consume or to execute those transactions.

Q Okay. So the answer to that question is no?

A No. J.P. Morgan and its affiliates were not brokers for Edison.

Q But they were counter parties?

A Certain affiliated companies to J.P. Morgan were counter parties with SCE in 2012.


Okay. Thanks. That's my questions.


Thank you, Ms. George.

Mr. Shapson.


Q Just a couple questions here. I want to ask you about the ANR-20 which contains Mr. Carver's statement. A I have that.

Q You had some discussion with Mr. Geesman about the analysis. And I'm just curious. Please, I'm not asking anything about the content of the analysis. I'd like to know if you can tell me though what the format of the analysis was. And by that, I mean, for example, was it a database, spreadsheet, or report, something like that?


A I can only comment on the components of the analysis that I was responsible for. I don't have complete visibility to everything that was rolled up and aggregated for Mr. Craver and his management team's consideration. The work product that we delivered to the managing team of this effort was predominantly in the spreadsheet form.

Q And again without reference to any information that was contained in there, how many spreadsheets are you talking about?

A It was an ongoing exercise. We provided updates sometimes as frequently as twice a week and at other times three or four weeks would elapse before we would provide updates. It would take me a while to sit here and try to think about exactly how much it was to give you a good idea. It was a lot of data flow.

Q Okay. And just so we're clear, I'm not looking for exactly. If you can estimate how many Excel spreadsheets we're talking about.

A Recognizing that some spreadsheets contain numerous tabs.

Q Thank you for that clarification.

A Probably anywhere between I'd say (1413) 40 and 60.


Thank you. And just so we're clear, your Honor, I understand that I asked a question about CRRs for 2013, which was objected to. And I believe that was sustained, correct? And that just for the sake of time, if I ask Sempra the same question, I assume that will be objected to and sustained as well.

Can I go on that assumption?


Mr. Walsh's witnesses?






Thank you. No other questions.

ALJ DUDNEY: Thank you, Mr. Shapson.


Q All right. Mr. Cushnie, I have a few questions for you as well. So in Exhibit SCE-3, I don't think you need to turn to it. This is kind of a general question. At different points in that document, in describing the term Q, which is the quantity of power purchased, I think there are some slight differences in the way you describe Q you in terms of the net short and net long calculations. I just wanted to ask you to (1414) clarify.

Is there an actual difference in how a net open position would be calculated in those two situations?

A And you're talking about Exhibit SCE-38?

Q I was looking at Exhibit -- yes, I think it's what's now called SCE-38.

A So Q is defined differently depending on whether we're calculating the replacement energy megawatt hours or the foregone energy sales megawatt hours. When we're calculating the replacement energy, Q is defined as those megawatt hours in which Edison had a financial net short position. And when we're calculating foregone energy sales, Q is equal to those megawatt hours that Edison was financially long had San Onofre been operating. And they are capped by the amount of generation that San Onofre can produce.

Q Okay. Thank you. Now, the forced outage rate we talked about a little bit -- can you explain how that is factored into Q? For instance, that percentage is subtracted off of the generation in every hour? Or is it only applied to 2.15 percent of hours?


A So we reduce each hour by the 2.15 percent forced outage rate assumption that we calculated.

Q Okay. Thank you. Then can you explain how the price elasticity assumption was applied in different time periods?

A So we calculated price elasticity on an on-peak and off-peak basis for each month of the relevant reporting period. And we -- and it was basically in a regression analysis that looked at how implied market heat rates differed between a scenario where SONGS operated versus a scenario where SONGS did not operate. So we looked at the difference in implied market heat rates multiplied by the assumed gas price for that applicable period to get a price elasticity delta.

And then we compared that delta to the power price that existed to come up with a percentage. And then we used that same percentage difference to apply to the actual index prices that we were using for our calculations for the foregone energy sales.

Q Okay. So just to make sure I understood your answer, so for each month, you would have an on-peak adjustment and an off-peak adjustment. And you would apply (1416) those adjustments to every hour during that month?

A For the relevant on-peak or off-peak hour.

Q Okay. Thank you. In your testimony, you suggest using that price elasticity adjustment only for foregone sales and not for the purchased power. Why the different treatment?

A So for replacement energy, Edison when it had to buy energy to meet the financial net short position as a result of the outage was paying the price that was reflective of what the market settled at as a result of San Onofre not being available. So by way of example, if the market price was $40 had San Onofre been operating, then that was the price we had to pay to serve our customer's short position.

In contrast when we calculate foregone energy sales revenue, what we're looking at is for those hours where we would have been financially net long had San Onofre been operating, what would have been the market price we would have got for selling the nuclear output?

We don't have that price available today because the only price we have is the ( 1417) price that existed without SONGS. So we view this price elasticity function adjustment to estimate how much lower market prices would have been had SONGS been operating. And then that is the -- that lower market price is the one that we used to calculate the foregone energy sales net revenue.

Q All right. Moving on a little bit, we talked earlier about the difference between the day ahead -- and that's the Platts Index of the SP-15 data prices versus the day ahead IFM prices in the ISO market.

Can you just briefly explain what the causes of those differences are? And in particular, if there's any systematic difference.

A In the IFM, there's two general types of prices. There's a price that load pays to be served through the IFM. There is a price that generation receives for selling its electrical output into the market.

The Cal ISO's MRTU market design is comprised of many hundreds of load nodes and generation nodes. For I'll call it ease of understanding, the load points can be load weighted averaged up to a single price, which is what we refer to as the DLAP. And the generation nodes can be generation weighted (1418) averaged to a single price, which we can call the EZ Gen hub price. The DLAP price tends to be higher than the EZ Gen hub price because in order to move generation to load, you incur transmission line losses and congestion. And it's the delta between those two that is effectively the combined congestion and line losses that are incurred to serve load.

And for that reason, why I have been advocating to use the Platts test SP-15 index price, which is a price that both buyers and sellers are willing to transact that bilaterally prior to the operation of the IFM. And in theory, that price should land somewhere in between the DLAP and the EZ Gen hub price. And it allows us to use a single price reference point for doing our calculations.

Q Okay. Now, in Exhibit SCE-37 you comment that many of Edison's financial hedges besides CRRs were more valuable because of the SONGS outage.

Can you give a quick example of some of the other hedges that might have been more valuable in that situation?

A Sure. So Edison may have purchased a 10,000 heat rate call option. And when (1419) SONGS was running and the applied market heat rate was running around 8500, that 10,000 heat rate call option would not strike, there would be no return to ratepayers on that call option.

With SONGS out of the marketplace, the applied market heat rate may have risen to 10,500, causing the call option to be in the money by 500; and now there's revenues that are flowing to customers as a result of that call option.

So this is what I was referring to saying that the higher implied market heat rate higher market prices as a result of SONGS being out of commission, resulted in many of Edison's forward transactions being more valuable for its customers. And nobody has suggested that that additional value also go into any sort of replacement power cost calculation in reducing the impact, just were cherry picking the one that lost money.

Q Okay. Did SCE buy any CRRs during 2012 because of the SONGS outage for part or all of the remainder of 2012?

A Are you asking did Edison buy CRRs at the SONGS nodes, or did we buy CRRs at other generation nodes?

Q What I'm trying to ask is in (1420) response to the changes in congestion patterns that I guess would be expected due to the SONGS outage, did SCE in any of the monthly auctions for 2012 make purchases in response?

A So without revealing anything confidential, Edison's AB 57 procurement plan allows Edison to acquire CRRs where there is an expected use of the grid. And what that means is if we anticipate flowing energy from point A to point B, we can seek to acquire CRRs through the Cal ISO's allocation process and then, subsequent to that, through the auction process.

And what we do in prioritizing our CRR allocation nomination request is we look for the highest value CRRs first and seek to maximize our allocations at those points, and then move down in descending order those that are deemed to be less valuable.

So by design, as we observed congestion patterns shifting on the grid, our assessments of value for particular CRRs would go up or down and, as a result of that, our allocation requests would potentially shift from the ones that were previously considered valuable to those that are now considered more valuable.


But there was not specific effort made to say: SONGS is out. Here's what we need to do as result of that. All of our CRRs are managed on portfolio basis, and our allocation and auction practices did not hange as result of SONGS being out. The values may have changed as a result of SONGS being out, but we didn't change anything.

Q Okay. So in the numbers presented in your testimony for the CRR revenues, do those numbers include any CRRs that would have been procured after the beginning of the outage because of the events you just described in terms of the change in valuations?

A A two-part answer here. First, Edison did not seek to acquire CRRs at the SONGS generation nodes once the units were on outage because we didn't have an expected use of the grid.

Second, through the Cal ISO's management of load migration, as customers moved from one LSE to another, the Cal ISO does apportion CRRs in very, very small amounts between the load-serving entities. And so I do believe that Edison over the period of 2012 did pick up, you know, somewhere in the neighborhood of 5 to 10 (1422) megawatts of CRRs at the SONGS locations as a result of load migration. But it's not anything we requested. It's just something that occurs as part of the Cal ISO's load migration allocation process.

Q Okay. So my next question is kind of comparing the Edison testimony and the San Diego testimony. One thing that jumped out at me is that what's listed as the real-time imbalance charge line item is actually far larger in San Diego's case than in Edison's. And I suspect that the reason for that is that San Diego perhaps included some additional, I think it was, station loads in their line item. And so I wanted to ask you.

There is no reason that the real-time imbalance charge per se would be larger in San Diego's case than Edison's; correct?

A Assuming that San Diego was not scheduling output from San Onofre the day and hour perhaps the unit was forced out, our numbers should be proportional. Edison reported for its real-time imbalance charge just the imbalance charges that we incurred for the balance of January 31st, when Unit 3 first went out, and the entirety of February 1st, 2012, because that day that (1423) schedule had already been submitted to the Cal ISO. After that there were no imbalance charges incurred as a result of day ahead schedules.

We are charged for the auxiliary load at the power plant in the real-time imbalance market because the auxiliary load is not load that can be scheduled with the Cal ISO. It's normally served by the power plant. And so Edison elected to call that auxiliary load and showed it as a separate component of our miscellaneous costs.

And you have refreshed my memory, as I believe San Diego was reporting it as imbalance energy charge, which is how it's served in the Cal ISO's market.

Q SONGS station power costs, which I think is what we are referring to as the auxiliary load costs, is -- how is that counted in the SONGSMA? Is that an O&M cost?

A Edison is recording it as an OMA cost. We report it under our Huntington Beach sub account line item.

For example, if you were to look at Edison's August 1, 2013, OMA submittal to the Energy Division, on the last page there is a memo item that identifies the components of the Huntington Beach sub account and we have (1424) a line item there that says: Auxiliary load costs charged in real-time imbalance market, and we detail what those are.

Q And then can you briefly describe how their real-time imbalance charges and the PIRP, Participating Intermittent Resource Program, charges are calculated by the ISO?

For example, is that a fixed dollars per one hour charge or is there some other method?

A So the real-time imbalance energy charges accrue based on the Cal ISO's five-minute real-time market. And if you are short, you are charged the real-time imbalance charge.

The PIRP charges are part of the Cal ISO's Participating Intermittent Resources Program that allows intermittent resources to schedule into the Cal ISO consistent with the Cal ISO's forecast for their output. And if they do it that way, then Cal ISO integrates all of their imbalances so that they're not subject to the five-minute imbalance market; that they have net in balance over the period of the month.

And then there is uplift that occurs because of that. And the Cal ISO allocates that uplift to all negative (1425) uninstructed deviations in the market.

So the auxiliary load at the plant because it's being served in the imbalance market, it shows up as a negative uninstructed deviation. And so portion of these PIRP charges are allocated to that negative uninstructed deviation. So it's just a cost that follows the imbalance.

Q So if SONGS were simply treated as a customer rather than a generator, those charges would not be incurred; is that correct?

A I believe the PIRP charges are only allocated to generators.

Q Okay. Now, I would like to ask a clarifying question.

When you discussed with Miss George earlier the Edison Mission Energy purchase of Huntington Beach, do I correctly understand that Edison Mission Energy had purchased the air credits only, or had they purchased also the physical plant?

A My understanding is that Edison Mission Energy purchased those components of Huntington Beach 3 and 4 that would be necessary to qualify for retiring the units and being eligible to access AQMD's Priority Reserve Bank for air emissions credits. And (1426) in order to do that, they had to disable Huntington Beach Units 3 and 4, which I believe they said they put holes in the boilers.

When Cal ISO determined that they wanted to return Huntington Beach Units 3 and 4 to service, then Edison Mission Energy entered into some sort of contractual arrangement with AES to return the components of Units 3 and 4 that they had purchased to allows AES to operate them as units, and AES then repaired the boilers so the units could then operate.

I don't know if the components were returned in the form of a lease or a sale. That's beyond my knowledge. But to answer your question, Edison Mission Energy actually purchased certain components of Huntington Beach 3 and 4 so that they would be eligible to access the Priority Reserve Bank.


All right. Thank you,

Mr. Cushnie. That's all I have.

Mr. Weissmann?


I'll be fast. I know we're almost out of time, so I'll try and be quick.



Q Just a few questions, Mr. Cushnie. First of all, Mr. Geesman earlier today asked you about some of the work that was done to support the -- that was referenced by Mr. Craver, and there was some question about whether that analysis looked at costs incurred for procurement in 2012.

Over the course of the break, were you able to ascertain whether 2012 costs were included?

A Yes. I was able to confirm that we did not look at 2012 costs. It was a forward-looking assessment that began in 2013 in its initial form.

Q Okay. Mr. Shapson asked you some questions at the beginning of the day about forced outage rates and what they would have been if you looked at a 15 or 20-year look back on SONGS operations.

Over the course of the day, were you and your staff able to compile some data on that question?

A Yes, we were. My staff reports that if we used a 15-year forced outage rate, the forced outage rate would be 2.98 percent; and if we used a 20-year average, it would be (1428) 2.83 percent.

Q And just remind us: What was the rate that was used in your testimony?

A The 10-year average was 2.15 percent, almost a full percent lower.


Okay. Thank you, Mr. Cushnie. Those are all the questions I have.


Okay. Recross, Mr. Shapson?


Q I'm sorry. The numbers that you just gave are the averages for SONGS?

A Yes. Q Okay. So you were able to contact your staff and get this information during the lunch break or some other break?

A Yes.

Q Did you ask them to find out for you the industry average for those two time periods as well?

A No.

Q Why not?

A There is only so much information they are going to be able to obtain in a limited period of time.

I will tell you it took one of my (1429) staff members a long time just to get the 10-year average -- industry average that I put in my testimony. And the document that we used only provided ten years' worth of data.


Thank you.


Mr. Freedman?

Mr. Geesman?




Miss George?

All right. If you have nothing further --


Nothing further, your Honor.

I assume we can move exhibits later on.

ALJ DUDNEY: Sure. We can move the

exhibits -- let's do that first thing in the morning.

All right. Mr. Cushnie, you're excused.


Thank you.


And we will resume at 9:30 in the morning. Excuse me -- 9:00 a.m. in the morning. Thank you.

(Whereupon, at the hour of 3:33 p.m., this matter having been continued to 9:00 a.m., August 6, 2013 at San Francisco, California, the Commission then adjourned.)


Topic revision: r6 - 27 Aug 2013, RaymondLutz
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