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3 E‐RSC MEETING
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7 Meeting held at The W Hotel, 333
8 Poydras Street, New Orleans, Louisiana,
9 70130, commencing at 9:00 a.m., on Thursday,
10 the 22nd of April, 2010.
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0002
1 P R O C E E D I N G S
2 PRESIDENT SUSKIE:
3 Good morning, everyone. Thank you
4 for being here. At this time, I'll call the
5 meeting of the E‐RSC to order. I'd like to
6 ask Ken Anderson to go over the roll call and
7 proxy.
8 SECRETARY ANDERSON:
9 I believe we're all present.
10 PRESIDENT SUSKIE:
11 And the representative ‐‐
12 SECRETARY ANDERSON:
13 And the representative from New
14 Orleans is here, and I have the proxy.
15 PRESIDENT SUSKIE:
16 Okay. I declare a quorum.
17 And we'll begin with some
18 administrative items. Well, before we go to
19 administrative items, I'd like to point out
20 that we have Leslie here with us as a court
21 reporter, and, therefore, please state your
22 name before you speak, and I told her feel
23 free to interrupt anybody, including myself, 24 if I'm ‐‐ we're speaking too fast or need to
25 clarify who's speaking and so forth.
0003
1 Also, before we go any further, I'd
2 like to ask those in attendance to get up and
3 state their name and who they're here on
4 behalf of before we go to the phone, and
5 we'll start over here on the right‐hand side.
6 So, for the record, for those who are in
7 attendance.
8 MR. CHILES:
9 John Chiles with GDS Associates.
10 MR. SPARKS:
11 Michael Sparks, SUEZ.
12 MR. MITTENDORF:
13 Brad Mittendorf, Southern Strategy
14 Group Louisiana.
15 MR. SHUMATE:
16 Walt Shumate Consulting.
17 MS. VOSBURG:
18 Jennifer Vosburg, NRG Energy and
19 Louisiana Generating.
20 MR. COLLINS:
21 Peter Collins, NRG.
22 MS. LANE: 23 Sarah Lane, Tenaska.
24 MR. DASPIT:
25 Larry Daspit, Entergy Corporate
0004
1 Communications.
2 MR. THUMM:
3 Brian Thumm, ITC Holdings.
4 MR. CASPARY:
5 Jay Caspary, Southwest Power Pool
6 staff.
7 MR. NEWELL:
8 Gary Newell, representing
9 Lafayette, LEPA, MEAM and MDEA.
10 MR. BIHM:
11 Kevin Bihm, the Louisiana Entergy &
12 Power Authority.
13 MR. CLAREY:
14 Patrick Clarey, FERC staff.
15 MR. LONG:
16 Robert Long, SUEZ Energy.
17 MR. ERBACH:
18 Don Erbach, (inaudible).
19 MR. BROWN:
20 Matthew Brown on behalf of Entergy
21 Louisiana, Entergy/Gulf States Louisiana. 22 MR. SUFFERN:
23 Matt Suffern on behalf of Entergy
24 Arkansas, Inc.
25 MR. CASTELBERRY:
0005
1 Kurt Castleberry, Entergy Arkansas,
2 Inc.
3 MR. HARLAN:
4 Dave Harlan on behalf of Entergy
5 Arkansas.
6 MR. HENTSCHEL:
7 Brandon Hentschel, SPP.
8 MR. HUNTWORK:
9 Nathan Huntwork with Phelps Dunbar
10 on behalf of CLECO Power.
11 MS. McCULLOUGH:
12 Amy McCullough, Mississippi
13 Business Journal.
14 MS. BURROWS:
15 Lori Burrows, Arkansas Commission
16 Staff.
17 MS. BARFIELD:
18 Carol Barfield, Marathon Oil.
19 MS. TURNER:
20 Becky Turner with Entegra Power 21 Group.
22 MR. ORR:
23 John Orr with Constellation Energy.
24 MR. ESTES:
25 Chip Estes, Southern Strategy.
0006
1 MS. KING:
2 Katherine King with Kean, Miller,
3 representing the Louisiana Entergy Users
4 Group.
5 MR. REED:
6 Presley Reed, representing the City
7 Council of New Orleans.
8 MS. CARLISLE:
9 Lynn Carlisle, South Mississippi
10 Electric.
11 MR. MOVISH:
12 Phil Movish, City of New Orleans.
13 MR. PATTERSON:
14 Kirk Patterson, Louisiana
15 Commission.
16 MR. DARCE:
17 Noel Darce, Louisiana Commission.
18 MR. THOMPSON:
19 Henry Thompson, Consultant, 20 Arkansas Cities Hope, Prescott, Benton,
21 Conway, West Memphis, Osceola.
22 MR. PEDERSEN:
23 Todd Pedersen, West Memphis
24 Utilities, West Memphis, Arkansas.
25 MR. WILSON:
0007
1 Dave Wilson, counsel for Arkansas
2 City.
3 MR. HENLEY:
4 Rick Henley, City, Water & Light,
5 Jonesboro, Arkansas.
6 MR. DODSON:
7 Terry Dodson, Cottonwood Energy.
8 MR. GRENFELL:
9 Bob Grenfell, Entergy Mississippi.
10 MR. WHITMORE:
11 Terry Whitmore, CLECO Power.
12 MR. HILTON:
13 Shane Hilton, CLECO Power.
14 MR. McCULLA:
15 Mark McCulla with Entergy.
16 MR. VONGKHAMCHANH:
17 Kham Vongkhamchanh with Entergy.
18 MR. HURSTELL: 19 John Hurstell with Entergy.
20 MS. PROFETA:
21 Pat Profeta on behalf of Entergy.
22 MS. DESPEAUX:
23 Kim Despeaux with Entergy.
24 MR. SCHNITZER:
25 Michael Schnitzer on behalf of
0008
1 Entergy.
2 MR. PIONTEK:
3 Luke Piontek, Roedel, Parsons,
4 representing Cottonwood.
5 MS. PARSLEY:
6 Julie Parsley, representing
7 Cottonwood.
8 MR. BAUGH:
9 David Baugh, Cottonwood.
10 MR. GREFEE:
11 Richard Grefee, Texas Commission
12 Staff.
13 MR. BRIGHT:
14 Ben Bright, SPP staff.
15 MR. LOUDENSLAGER:
16 Sam Loudenslager, Arkansas Public
17 Service Commission. 18 MS. SCHMIDT:
19 Kristine Schmidt, ESPY Energy
20 Solutions, on behalf of the E‐RSC.
21 MR. CAMET:
22 Greg Camet on behalf of Entergy.
23 MR. BERNSTEIN:
24 Glen Bernstein for Entergy.
25 MR. OFFRING:
0009
1 Charles Offring [phonetic], East
2 Transmission.
3 MR. CRUTHIRDS:
4 Dave Cruthirds with The Cruthirds
5 Report.
6 MS. BIGELOW:
7 Christina Bigelow with Entergy.
8 MR. HOLLAND:
9 Jody Holland, SPP ICT.
10 MR. REW:
11 Bruce Rew, Southwest Power Pool
12 ICT?
13 PRESIDENT SUSKIE:
14 All right. Thank you. I'm proud
15 of Mr. Cruthirds for not advertising his
16 product. 17 CHAIRMAN PRESLEY:
18 He's glad for you to do it for him.
19 PRESIDENT SUSKIE:
20 With that, we appreciate everybody
21 being here present.
22 And those on the phone?
23 MR. OLSEN:
24 Carl Olsen from Entergy Texas.
25 MR. THOMSON:
0010
1 Rob Thomson on behalf of Entergy.
2 MS. RATLIFF:
3 Joan Walker Ratliff, Conoco
4 Phillips.
5 MR. CASHIN:
6 Joe Cashin from Electric Power
7 Supply Association.
8 PRESIDENT SUSKIE:
9 Thank you.
10 Next?
11 MR. WARREN:
12 This is Bary Warren with Empire
13 District Electric Company.
14 MR. RALSTON:
15 Al Ralston, Entergy. 16 MR. MILLS:
17 Roger Mills, Entergy.
18 MS. WATSON:
19 Melissa Watson, Louisiana
20 Commission Staff.
21 MR. HALLER:
22 Peter Haller, Brickfield,
23 Burchette, Ritts & Stone.
24 MR. ROE:
25 Doug Roe, FERC staff.
0011
1 PRESIDENT SUSKIE:
2 Could you repeat that, please?
3 MR. ROE:
4 Doug Roe, FERC staff.
5 PRESIDENT SUSKIE:
6 Doug Roe; Doug Roe, FERC staff.
7 Doug, I know you speak a little bit
8 later on the agenda. You might want to see
9 if you can work out the sound, because that
10 did not sound very good.
11 MR. ROE:
12 Okay.
13 PRESIDENT SUSKIE:
14 Next? 15 MR. PALIZA:
16 Roberto Paliza, Paliza Consulting.
17 PRESIDENT SUSKIE:
18 Thank you.
19 Anyone else on the phone?
20 (No response.)
21 Okay. Next, we'll go to
22 administrative items. Stated at the end of
23 last month's meeting, you may recall the
24 E‐RSC went into executivee session. Th five
25 consultants that submitted proposals, we
0012
1 interviewed two, and at the end of the
2 interviews, the E‐RSC unanimously voted to
3 hire ESPY Energy Solutions, LLC, to be a
4 consultant, and Kristine Schmidt is here
5 sitting next to Sam. They've been a part of
6 our team and will provide an invaluable
7 resource to us, particularly with the FERC
8 experience.
9 And we appreciate you joining us
10 and becoming a part of our team.
11 Last night I asked Kristine if she
12 would take action items notes from various
13 items that we discuss today. Staff talks 14 about how they'd have to go back and look at
15 the transcript to remember all the various
16 action items we have out there. So if
17 Kristine asks you any questions related to an
18 action item, she's going to help track for us
19 today. We appreciate your assistance with
20 Kristine.
21 Next, we have a report from FERC.
22 Patrick?
23 MR. CLAREY:
24 Thank you. I don't have too much
25 to report since the last meeting. After my
0013
1 brief report, Doug will provide you all with
2 an update on the cost/benefit study. I'll
3 just go over the recent addition of the final
4 document to the stakeholder process.
5 First, I'm pleased to report now
6 that Commissioners Moller and Spitzer have
7 committed to attend your E‐RSC meeting in
8 connection with the SEARUC meeting in June.
9 Also, yesterday it was announced that
10 Commissioner Moeller and nominee LaFleur will
11 attend the confirmation hearing before the
12 Senate Energy and Natural Resources Committee 13 on April 27th.
14 On March 18th, the Commission
15 issued a policy statement regarding penalty
16 guidelines for the purpose of adding greater
17 fairness and consistency to its civil penalty
18 authority. Last week the Commission
19 determined that the public interests would be
20 served by affording interested entities a
21 broader opportunity to comment on the
22 proposed guidelines before a final order is
23 issued. Thus, the Commission will suspend
24 the policy statement and the application of
25 the penalty guidelines. The Commission
0014
1 considers its March 18th action as an interim
2 proceeding, and interested parties are
3 invited to submit comments within 60 days of
4 the date of the order.
5 Also, last week the Commission
6 Staff issued their State of the Markets
7 Report for 2009. Not surprisingly, the
8 report noted that 2009 saw lower natural gas
9 prices, on average, down 50 percent from
10 2008, as well as lower demand for
11 electricity, down 4.2 percent in 2009. 12 According to the Staff report, 2009 saw the
13 greatest decline in demand in a single year
14 in the past 60 years. Likewise, with lower
15 demand in fuel costs, wholesale electricity
16 fell by half. During 2009, 25 gigawatts of
17 new generation was added, with 84 percent of
18 the 25 gigawatts being wind and natural gas
19 fuel.
20 This concludes my report. I'd be
21 happy to answer any questions. Thank you.
22 PRESIDENT SUSKIE:
23 When you mentioned the decrease, if
24 I'm tracking right, that was the decrease in
25 electricity sales or consumption?
0015
1 MR. CLAREY:
2 Consumption.
3 PRESIDENT SUSKIE:
4 Okay.
5 CHAIRMAN PRESLEY:
6 4.2 percent, Patrick?
7 MR. CLAREY:
8 4.2. I can ‐‐ I'll e‐mail you all
9 a link to the full Staff's report.
10 PRESIDENT SUSKIE: 11 Any questions of Patrick? Any
12 questions of Patrick?
13 VICE‐PRESIDENT FIELD:
14 Did I understand you to say that
15 was the largest drop in 60 years?
16 MR. CLAREY:
17 Yes. That's correct.
18 VICE‐PRESIDENT FIELD:
19 Thank you.
20 PRESIDENT SUSKIE:
21 Next, we have stakeholder input on
22 the FERC funded CBA, as well as just an
23 update on the CBA.
24 Doug Roe at FERC, or on the phone,
25 could you please give that report?
0016
1 MR. ROE:
2 Sure thing, Chairman Suskie. Can
3 you hear me okay?
4 PRESIDENT SUSKIE:
5 Yes, much better.
6 MR. ROE:
7 Okay. Good deal.
8 Before we proceed with the details
9 of the stakeholder input process, I'd like to 10 take one step back and provide a very brief
11 update on the progress of the CBA. We had an
12 update, conference call and WebEx meeting on
13 Tuesday with CRA stakeholders, and if I'm not
14 mistaken, we had close to 50 persons attend,
15 if not more, on the call. During that
16 meeting, CRA provided an update on its
17 progress towards developing the base case and
18 change case model. We're shooting to present
19 a base case run in May for the Baton Rouge
20 face‐to‐face update meeting.
21 In terms of the work we've done in
22 the past month, this past month was
23 monumental from a data‐requiring standpoint.
24 We were successful in executing nondisclosure
25 agreements and validating generation data
0017
1 with stakeholders. The bottom line is that
2 I'd really like to thank the participating
3 stakeholders for their effort. We've been
4 asking a lot of people, you know, in addition
5 to their already overloaded schedules, and
6 everyone has cooperated extremely well. I'd
7 also like to do especially well of the
8 efforts of Entergy and SPP Staff. They've 9 been working with CRA on data consumption
10 requirements on a daily basis for weeks, and
11 it has not gone unnoted.
12 And to sum up, you know, I noted
13 when the first ‐‐ when the study first
14 started, that stakeholder involvement would
15 be critical to the strength of the study, and
16 I have to report that we've had great
17 participation so far. On to the stakeholder
18 input process itself, I do apologize for not
19 being able to present this in person, but I
20 will be present at the next E‐RSC meeting in
21 May. Now, to sum up from the last E‐RSC
22 meeting on March 18th, I believe, we heard
23 concerns from stakeholders that the input
24 process wasn't clear enough and there wasn't
25 enough detail. So after going back to the
0018
1 drawing board and adding some additional
2 details, and thanks to the efforts of ESPY
3 and the ERC working group, a complete
4 document was rolled out last week for
5 stakeholder review that clarifies the entire
6 stakeholder input process. No comments were
7 received to this document, and it is that 8 exact document that is supposed to be used
9 going forward. The process itself is pretty
10 simple, and the bones of that are the process
11 that I originally discussed in Dallas at our
12 first update meeting. However, this time
13 we've added far more details, and the message
14 remains the same: Now is the time to get
15 involved in the study. We have seen CRA
16 consumption documents on several occasions,
17 and at this point, I expect stakeholders to
18 begin submitting comments either in agreement
19 or disagreement with CRA on those
20 consumptions and input. Now, in terms of
21 providing input into the study's feedback,
22 there are two opportunities. The first way,
23 although it's a little bit more informal, is
24 doing the monthly update meetings that we
25 have at CRA. The second way is through
0019
1 submitting your comments and issues to the
2 E‐RSC Working Group through e‐mail for
3 review. This is accomplished by simply
4 sending an e‐mail with the subject line
5 Entergy SPP CBA and send the issue and
6 explanation to the ERC Working Group and CC 7 Patrick and myself. This is the primary
8 method and the only way to ensure that
9 stakeholder feedback comments will be
10 reviewed. So, for example, if the
11 stakeholder suggests changes to pearl
12 [phonetic] rates and commitment charges
13 during the monthly update meeting, that
14 stakeholder must e‐mail feedback to the ERC
15 Working Group formally to preserve its
16 comments.
17 Now, as part of this process and
18 under the review process, any stakeholder may
19 challenge either any input or assumption that
20 is used by CRA, or the stakeholder may
21 challenge any input or comment submitted by
22 another stakeholder. If that's the case, the
23 stakeholder will have two days to post
24 comments to the previous ‐‐ you know, first
25 spoken stakeholder's comments. Now, once a
0020
1 decision is made by the ERC Working Group,
2 the stakeholder will be notified by e‐mail.
3 If the issue is rejected, the stakeholder
4 will have two business days to ask the ERC
5 Working Group for reconsideration. Now, 6 lastly, as a reminder, all actions taken by
7 the ERC Working Group will be posted and
8 documented on the SPP ERC website.
9 And so that brings up the last
10 holdover issue from the March 18 E‐RSC
11 meeting, and, that is, whether monthly CBA
12 meetings would be transcribed or not. And
13 the answer is that, no, they will not be
14 transcribed. In my opinion, transcription is
15 best suited and usually reserved for
16 hearing‐type situations. The update meetings
17 that we're holding are not hearings and are,
18 rather, intended to promote a productive
19 environment whereby CRA stakeholders can
20 engage in a dialogue ‐‐ in a healthy dialogue
21 regarding the input and assumptions that will
22 be used in the study. Now, effectively, the
23 documentation that I just discussed of the
24 stakeholder process, that documentation
25 effectively eliminates the need for
0021
1 transcription, and, therefore, we can
2 maintain a productive and engaging work
3 environment going forward.
4 So, at this time, I'd like to open 5 the floor to any discussion or questions
6 regarding the stakeholder process. Thank you
7 for your time.
8 PRESIDENT SUSKIE:
9 Thank you, Mr. Roe.
10 Any questions from anybody or
11 comments?
12 To our surprise, Jennifer has a
13 question.
14 MS. VOSBURG:
15 No. First, it's a comment. I do
16 want to recognize the work that FERC and the
17 E‐RSC Working Group did to move forward with
18 the stakeholder process. You know, from
19 where we started back in October with no
20 process to this, while it's not ‐‐ it's not
21 perfect and, you know, we're understanding
22 we're in a unique situation, it does answer
23 the questions about what stakeholders are
24 supposed to do, how it is going to be
25 documented and handled, so it is a great
0022
1 improvement from where we started, and we do
2 appreciate your efforts for that.
3 I would encourage all of the 4 stakeholders to really look at this document,
5 because the burden is placed on the
6 stakeholders to follow‐up. We need to know
7 what the procedure is, so when something goes
8 on and we miss it, you know, the process is
9 here for us to follow to make sure that your
10 issues are documented.
11 One comment I will make, while this
12 doesn't divert on stakeholders and since the
13 Working Group ‐‐ the face‐to‐face meetings
14 and the updates are not going to be
15 transcribed, one of the things that's very
16 important is for the meeting materials be
17 provided to the stakeholders as soon as
18 possible. The meeting on Tuesday that we
19 had, the presentation by Charles River, the
20 stakeholders had not seen it before, and then
21 you get into a situation thate you'r moving
22 very rapidly through it with, you know, okay,
23 does anybody have any question; anybody have
24 issues; moving on. And we understand the
25 need for speed, but there has to be a
0023
1 recognition on the back end that we're seeing
2 it for the first time. Some of the stuff, 3 we're going to have to really think about it.
4 An example was, the commitment pool issue
5 came up. Well, let's throw out what we have
6 and just go with one commitment pool with a
7 ten‐dollar (inaudible). Whoa. You know,
8 it's going to take some time for us to look
9 at that to see, and we can't make a decision
10 right on the phone. But that's just one
11 caution that materials need to be provided to
12 us with enough time that we can have a good
13 dialogue.
14 And, again, I just wanted to thank
15 everybody for their efforts and paying
16 attention to this and recognizing the
17 stakeholder process and procedure for it is a
18 very important issue.
19 PRESIDENT SUSKIE:
20 Thank you, Jennifer. Doug, do you
21 think there will be any problem with helping
22 getting stakeholders the material as soon as
23 possible?
24 MR. ROE:
25 Well, let me first thank Jennifer
0024
1 for her help in the process in completing the 2 stakeholder documents. But in terms of her
3 comment, I totally agree, and I understand
4 that it's very difficult to see information,
5 you know, for the first time and then expect
6 to be able to discuss it right away. We
7 understand it's fairly impossible.
8 You know, the problem we've been
9 having with distributing materials ahead of
10 time is just the time it takes for CRA to
11 accomplish it. It's not that they're behind
12 in doing their work. It's just that the
13 schedule that we imposed did not give them
14 enough time to be able to have a buffer of a
15 one‐week time to distribute materials to get
16 stakeholders enough time. Now, in the
17 future, we're ‐‐ and in the past, we tried
18 our best to distribute ahead of time as much
19 as we can, but in this circumstance, things
20 were a bit delayed, and CRA did not have the
21 opportunity to release documents ahead of the
22 meeting. But we will try our best to do so
23 ahead ‐‐ in the future, and I appreciate your
24 comment.
25 PRESIDENT SUSKIE:
0025 1 Thank you.
2 Any other questions or comments?
3 Sam? Sam, be sure to state who
4 you're with.
5 MR. LOUDENSLAGER:
6 Sam Loudenslager. I gave her my
7 business card.
8 PRESIDENT SUSKIE:
9 Because you're going to be talking
10 a lot today.
11 MR. LOUDENSLAGER:
12 Well, hopefully not.
13 Doug, this is Sam. Charles Rivers
14 owes us a ‐‐ Bruce owes us a follow‐up from
15 the Tuesday call. That material ‐‐ I don't
16 believe it's been sent out yet on the
17 exploder. So would you please remind him?
18 The GE assumptions memo, in particular, and
19 then the four‐page presentation on the NEEM?
20 MR. ROE:
21 Yes, Sam. That document is
22 actually with me right now. I'm not
23 purposefully holding it up. There's just
24 been a backlog. So expect to see that
25 distributed today. 0026
1 PRESIDENT SUSKIE:
2 Thank you, Doug.
3 Anybody else?
4 (No response.)
5 All right, Doug. Thank you very
6 much.
7 And, Jennifer, you're on the agenda
8 next. Do you still wish to comment or ‐‐
9 MS. VOSBURG:
10 No. That was it.
11 PRESIDENT SUSKIE:
12 Okay. Well, thank you very much,
13 Jennifer, for your leadership in that.
14 Sam?
15 MR. LOUDENSLAGER:
16 Yeah. Sorry, Boss. This is an
17 action item. The Working Group and I think
18 ERC was hoping that the E‐RSC would take this
19 process document and either approve it, gut
20 it, do something with it.
21 PRESIDENT SUSKIE:
22 Okay. We have a motion to approve
23 the process before us.
24 SECRETARY ANDERSON: 25 So moved.
0027
1 VICE‐PRESIDENT FIELD:
2 Second.
3 PRESIDENT SUSKIE:
4 With a motion and a second, all
5 those in favor say aye.
6 (All ayes.)
7 All those opposed?
8 (No response.)
9 Motion carries unanimously.
10 Thank you very much for your work
11 and input on this, and thanks for reminding
12 me, Sam.
13 Next, we have the reports from SPP
14 on the SPP ICT. If we could, I think
15 that's ‐‐ Bruce Rew is first.
16 MR. REW:
17 Good morning, President Suskie, and
18 to the E‐RSC. My name is Bruce Rew, spelled
19 R‐E‐W, with the Southwest Power Pool ICT. I
20 have a brief presentation this morning to
21 update you on a couple of the ICT activities.
22 First, I'd like to discuss the SPP
23 reliability coordination. We have performed 24 a summer assessment for 2010. Overall, we
25 see no foreseeable concerns during the
0028
1 summer, with the exception of the Acadiana
2 Load Pocket area, so I want to provide you a
3 brief update on the Acadiana Load Pocket
4 activities that we have under way in
5 progress.
6 As I think you're well aware,
7 there's been agreement for transmission
8 expansion construction in the Acadiana Load
9 Pocket area. Those facilities are in
10 progress, but they're not in‐service yet, so
11 we do anticipate the system to continue to be
12 stressed this summer prior to those
13 facilities coming in‐service. Generation in
14 the Acadiana Load Pocket has limited
15 flexibility for the peak conditions, and we
16 do have and outage and evaluation action plan
17 that's in place for typical weather and other
18 conditions in that area.
19 PRESIDENT SUSKIE:
20 We're on there. It took us a
21 while, though.
22 MR. REW: 23 Okay. Page ‐‐ I'm sorry. Page 4,
24 the reliability coordination for this summer.
25 For the last several years, the Acadiana Load
0029
1 Pocket has experienced high loads during the
2 summer, and we have taken that into account,
3 the historical trends, and worked with the
4 other entities in that area to come up with a
5 mitigation plan. There is still a high
6 probability of congestion management being
7 required due to projected load levels, and if
8 they're anywhere close to what we've received
9 in 2009, we'll have to most likely include
10 curtailment of firm service during the
11 summer.
12 So some of the actions that we're
13 looking at is, certainly, there will be a
14 high level of communication between the
15 entities within the Acadiana Load Pocket to
16 coordinate any situation or event that
17 requires congestion management actions to be
18 taken, and we'll continue to adhere to the
19 NERC reliability standards in facilitating
20 that coordination to assure that we maintain
21 reliability as much as possible during 22 that ‐‐ any situations that are high‐loading
23 or extreme stress in the Acadiana Load Pocket
24 area. We are making progress on the
25 transmission ‐‐
0030
1 PRESIDENT SUSKIE:
2 Bruce, Commissioner Field has a
3 question.
4 MR. REW:
5 Commissioner Field?
6 VICE‐PRESIDENT FIELD:
7 I don't mean to interrupt you, but
8 that is fair, I'll represent. And when you
9 say, "firm curtailments," has there been any
10 investigation to see if there are any
11 industrial or commercial customers that could
12 be interruptible temporarily? I know maybe
13 they're not interruptible on an interruptible
14 tariff now. Any investigation whether some
15 of those could be interrupted with some
16 notice?
17 MR. REW:
18 I think you probably need to talk
19 to the specific load‐serving entities about
20 that. Certainly, any contractual nonfirm 21 customers will have been recognized, but as
22 far as additional customers that will
23 voluntarily do it, I'm not aware of any.
24 You'd have to speak to those load‐serving
25 entities.
0031
1 VICE‐PRESIDENT FIELD:
2 Secondly, are you getting full
3 cooperation and communication from all the
4 load‐serving entities in the Acadiana Load
5 Pocket area?
6 MR. REW:
7 Yes. All the entities in that area
8 are communicating and working together to
9 attempt to solve projected problems during
10 the summer.
11 VICE‐PRESIDENT FIELD:
12 Thank you, Bruce. I will have my
13 office just suggest to them to see if some
14 people might be willing to voluntarily be
15 interruptible and give them some economic
16 incentives to do so during ‐‐ during the
17 summer, because if you've got to interrupt
18 firm demand, it's going to cause problems.
19 MR. REW: 20 And I'll make sure that I pass that
21 on to the reliability coordination folks to
22 communicate that fact to the Acadiana Load
23 Pocket entities, as well.
24 VICE‐PRESIDENT FIELD:
25 How do you make a decision on who
0032
1 is going to be interrupted? In other words,
2 residences and then businesses or...
3 MR. REW:
4 Well, our process would use the TLR
5 process, where we look for transactions that
6 are part of the process that get curtailed.
7 In other words, they are identified as having
8 an impact on the transmission facilities, and
9 they would be curtailed using that recognized
10 process.
11 VICE‐PRESIDENT FIELD:
12 Well, I want to make sure that the
13 load‐serving entities are all advising their
14 customers this might happen, because, you
15 know, nobody can do business anymore without
16 electricity. My home might get hot and be
17 uncomfortable for a few hours, but if it
18 shuts businesses down and causes people to be 19 sent home, then that's a problem.
20 Well, just keep me posted, Bruce,
21 if you will, and I appreciate you
22 coordinating it with the load‐serving
23 entities.
24 MR. REW:
25 Will do, Commissioner Field.
0033
1 The next line, I just have a brief
2 definition of Transmission Loading Relief and
3 Local Area Problem. There's been some
4 discussion about that. Transmission Loading
5 Relief is the interconnection‐wide process
6 that looks at congestion, and it uses
7 interchange transactions involving other
8 Balancing Authorities to reduce the
9 congestion or reduce the loading on
10 transmission facilities, and these
11 transactions are usually considered regional
12 or interregional in nature and caused due to
13 the flows on the transmission system. So
14 these are ones that are entered into what's
15 called the NERC IDC process, and the
16 reliability coordinators across the country
17 all use the standardized process for TLR. 18 And in a minute, I'm going to get into the
19 metrics, and it talks about the different
20 levels of TLR from firm service and nonfirm
21 service.
22 So any questions on the TLR
23 process?
24 CHAIRMAN PRESLEY:
25 I've got one, Bruce, not on TLR but
0034
1 on LAP. I'm just wanting to see, have y'all
2 ever been advised of any issues related to ‐‐
3 in the Choctaw County Entergy tie‐in with TVA
4 and north central Mississippi any type of LAP
5 problem there that you've been made aware of?
6 I had talked with some people at TVA that
7 kind of brought this up, and I didn't know if
8 that was on your radar or not.
9 MR. REW:
10 I'm not aware of it. I could, you
11 know, double check and see if it's been
12 mentioned, but may be not a high concern for
13 us. But I'm personally not aware of an issue
14 in that area.
15 CHAIRMAN PRESLEY:
16 If you could check and let me know. 17 It's the tie‐in with TVA, Choctaw County.
18 Thank you.
19 MR. REW:
20 Okay. And then the Local Area
21 Problem, or LAP, this is a condition where
22 the NERC TLR process is identified as not
23 being the most effective. In other words,
24 there's usually no transactions that are
25 impacting it, or very few transactions, and
0035
1 the problems are usually inside the Entergy
2 Balancing Authority and are considered local
3 in nature. And this is where, you know, we
4 would look at using that procedure to provide
5 relief on the transmission system other than
6 using the TLR process. So this is entirely
7 within the Entergy Balancing Authority
8 Process.
9 MR. BOOTH:
10 Bruce, quick question: Do
11 transmission owners in SPT also have an LAP
12 equivalent? I mean, TLRs are for
13 interregional transactions, right? The LAPs
14 are vital to intra and Entergy transactions.
15 I'm just curious if other transmission 16 owners, those in SPP, have a corollary for
17 the intra.
18 MR. REW:
19 Yes. The SPP RTO, it would be
20 different because of the Entergy imbalance
21 market. So they would use the Entergy
22 imbalance re‐dispatch if there is a condition
23 like that.
24 MR. BOOTH:
25 So if Entergy ultimately ended up
0036
1 doing SPP, would the LAPs go away?
2 MR. REW:
3 Yes, I would assume that they
4 would, that you wouldn't continue to use that
5 LAP procedure.
6 MR. BOOTH:
7 Okay. Thank you.
8 PRESIDENT SUSKIE:
9 All right.
10 MR. REW:
11 Next, I would like to give you an
12 update on the construction plan. Entergy
13 Services provides a report that's posted on
14 OASIS that gives information related to the 15 progress of construction plan projects, and I
16 provided you the OASIS link there. This
17 report includes projects that are in
18 completed, that are under construction and
19 that are in the design and scoping stage.
20 The data that's included in that report
21 includes the project driver, project name,
22 the LE, or local entity ‐‐ this is like
23 Entergy/Gulf States, for example ‐‐ the
24 current projected in‐service date, the 2010
25 funding comments, the project status and then
0037
1 any other comments. There's an open comment
2 field. And on the next line, I've provided
3 you just an example of one page from that
4 report that's posted to give you an idea of
5 what it looks like, and that's updated on a
6 quarterly basis.
7 Any questions on that report before
8 I transition to a metrics update?
9 PRESIDENT SUSKIE:
10 I would like to ‐‐ one question.
11 And I think I ‐‐ I believe I have it right,
12 looking at the reports. If I recall, there
13 were two projects that were in the ICT base 14 plan but not in Entergy's construction plan.
15 Is that ‐‐ am I correct with that?
16 MR. REW:
17 Okay. Jody just informed me that,
18 right now, it's exactly the same; there is no
19 difference.
20 PRESIDENT SUSKIE:
21 But there was two, and the issue
22 was Entergy had asked SPP to re‐evaluate it,
23 is my understanding, and then y'all were in
24 the re‐evaluation process, and I assume,
25 through that, came into an agreement with
0038
1 Entergy, and now the ICT base plan and the
2 Entergy construction plan are identical.
3 MR. REW:
4 (Nods head.)
5 PRESIDENT SUSKIE:
6 Okay. I just want to make sure I
7 understood that correctly.
8 VICE‐PRESIDENT FIELD:
9 Bruce, just since we're in charge
10 of the rates, is it correct that if it's a
11 169 kV line and above, then it's shared by
12 all Entergy customers, and if it's 138 or 13 anything below 169, then it's paid for by the
14 rate payers of the utility in which district
15 it's serving?
16 MR. REW:
17 Well, remember, we don't deal with
18 the cost allocation and that. You should
19 really ask Entergy on that.
20 PRESIDENT SUSKIE:
21 Commissioner Field, I think Kim
22 can.
23 Is it 230 and above?
24 MS. DESPEAUX:
25 Yes, Commissioner. It's generally
0039
1 230 kV ‐‐
2 VICE‐PRESIDENT FIELD:
3 230.
4 MS. DESPEAUX: ‐‐ and above that's
5 equalized among the operating companies under
6 the system agreement, and then ‐‐ but there's
7 also a piece of the cost that is paid for
8 under our open access transmission tariff by
9 third parties, as well. But below 230 is ‐‐
10 generally, the cost stays with the legal
11 entity. 12 VICE‐PRESIDENT FIELD:
13 The territory in which it's being
14 built.
15 MS. DESPEAUX:
16 Yes.
17 VICE‐PRESIDENT FIELD:
18 Okay.
19 CHAIRMAN PRESLEY:
20 Bruce, one question.
21 PRESIDENT SUSKIE:
22 And that was Kim Despeaux.
23 COURT REPORTER:
24 Thank you.
25 CHAIRMAN PRESLEY:
0040
1 One question. Going back, I just
2 happened to pull the sample page in your
3 presentation that had some Mississippi
4 projects on it, so it raised my level of
5 questioning. I see Getwell to Church Road,
6 and then the last ‐‐ on the last box, Getwell
7 Area Improvements. If I remember best, prior
8 to the Charleston meeting, there was a
9 Batesville to Getwell recommendation. Just
10 for your information, Sardis is a little 11 north of Batesville.
12 And my question is: Does this
13 represent bringing in those ‐‐ that base plan
14 action item, say from, I think, 2008 that was
15 taken off the table by Entergy? Is that
16 now ‐‐ does these ‐‐ do these two
17 recommendations fully encompass what att tha
18 time was one action item? Does that make
19 sense? Are we catching up to where we ‐‐ it
20 was left off a year ago?
21 MR. HOLLAND:
22 Yes. This is Jody Holland with
23 SPP. Yes, Commissioner Presley. We worked
24 with Entergy, and Entergy has developed the
25 construction plan a year later. And I'm
0041
1 looking at the notes, and the latest update
2 talks about the Getwell area improvements and
3 the Getwell to Church Road. I would have to
4 confirm exactly, but I believe this is a
5 progress ‐‐
6 CHAIRMAN PRESLEY:
7 That's like from here to the
8 hallway out there. That's very close. But
9 Batesville to Getwell is a long way. I don't 10 see any reference to that.
11 MR. HOLLAND:
12 In the latest update that was
13 posted a couple of days ago, maybe yesterday,
14 actually, it states in the other comments,
15 creates first leg of Getwell to Batesville
16 230 kV conversion, so it's the start. So
17 it's showing progress, but it's not
18 everything. I might point to Charles Long.
19 CHAIRMAN PRESLEY:
20 Before you do that, ‐‐
21 MR. HOLLAND:
22 Okay.
23 CHAIRMAN PRESLEY: ‐‐ when ‐‐ let me
24 make sure I've got my years right. When we
25 were in Charleston last year, in '09, this
0042
1 was ‐‐ this was part of the base plan in '08
2 that was taken off the table by Entergy in
3 their construction plan; is that correct? So
4 even with this, we're two years behind on the
5 Batesville to Getwell upgrade?
6 MR. HOLLAND:
7 I don't recall. I can do some
8 research, and I can take an action item. 9 CHAIRMAN PRESLEY:
10 Well, that would be ‐‐ I mean, if
11 you could just shoot me a quick e‐mail on
12 that. I know in the 2009 presentation that
13 Chairman Suskie made, that's when ‐‐ that was
14 part of that difference in the reports, so it
15 had to been the 2008. My concern is that
16 we're now, two years later, building a
17 transmission facility that was recommended
18 two years ago, and I'm just trying to make
19 sure what you've shown ‐‐ you just happened
20 to pull this page, and it has to do with it,
21 Bruce. But I just want to make sure that
22 what these two items are encompass the entire
23 project that was recommended two years ago,
24 that we're not piecemealing it.
25 MR. HOLLAND:
0043
1 Okay. I don't know the answer. I
2 do know that we've had, for instance, load
3 changes in the last couple of years, and that
4 may have played into it.
5 CHAIRMAN PRESLEY:
6 If I could just get the year that
7 it was first recommended in the base plan ‐‐ 8 MR. HOLLAND:
9 Okay.
10 CHAIRMAN PRESLEY:
11 ‐‐ and when Entergy decided not to
12 do it and then when they decided that,
13 obviously, this year that they're ‐‐ since
14 they're symmetrical, the base and the
15 construction are, we know the answer to that.
16 MR. HOLLAND:
17 So Getwell to Batesville?
18 CHAIRMAN PRESLEY:
19 Yeah.
20 MR. HOLLAND:
21 Batesville.
22 CHAIRMAN PRESLEY:
23 Thank you, sir.
24 PRESIDENT SUSKIE:
25 Does Entergy have any comments on
0044
1 that?
2 MR. LONG:
3 No.
4 PRESIDENT SUSKIE:
5 Okay. Thank you.
6 All right. Sam has question. 7 MR. LOUDENSLAGER:
8 Sam Loudenslager, Arkansas
9 Commission. I know ‐‐ I heard that there is
10 no difference in the construction and base
11 plan. Does that include ‐‐ are those plans
12 in sync in terms of a needed‐by date?
13 MR. HOLLAND:
14 No. They are not in sync in terms
15 of a needed‐by date. As far as projects go,
16 they are completely in sync, but there are
17 some need‐by dates that, I guess, cannot be
18 constructed in time. Some need‐by dates may
19 be this summer, for instance, so there are
20 mitigation plans in Entergy's construction
21 plan to meet those needs, just not the
22 ability to construct by, for instance, this
23 summer.
24 PRESIDENT SUSKIE:
25 Do you think it's possible ‐‐
0045
1 because I know what Sam is talking about
2 there, when there's a difference ‐‐ this is
3 one of the things we talked about last
4 month ‐‐ when there's a difference in the
5 date that it can be in‐service. I realize 6 there's a number of reasons that can affect
7 that. Theoretically, one could be regulatory
8 delay by one of our commissions. And so I
9 think it would be helpful to us and I don't
10 know if Entergy would ‐‐ may be best, since
11 y'all would actually go through the
12 regulatory process, when there's a difference
13 in the in‐service ‐‐ the need date and the
14 actual in‐service date, if we could have some
15 type of explanation. What's the difference?
16 And it could be, hey, Mississippi Commission
17 or Arkansas Commission, we'd like your
18 approval. You know, it could be along those
19 lines, or it could be court actions, eminent
20 domain, or whatever the case may be. I think
21 that probably would be helpful to us so that
22 we can see this is going to be delayed a year
23 or six months. Well, maybe the Commissions
24 can do something to help facilitate and move
25 that long.
0046
1 CHAIRMAN PRESLEY:
2 Are the differences in the need‐by
3 date ‐‐ could you just kind of go ‐‐ are they
4 ‐‐ could you explain a little bit further on 5 that? I mean, are your need‐by dates earlier
6 than Entergy's?
7 MR. HOLLAND:
8 Typically, yes.
9 CHAIRMAN PRESLEY:
10 Your base plan shows that these
11 transmission updates are needed earlier than
12 they show they're needed.
13 MR. HOLLAND:
14 At least than they show they can be
15 in‐service. It's typically an issue of
16 construction or, as you said, Chairman
17 Suskie, a issue of some other delay. So I
18 believe the answer to your question is, yes,
19 we can work with Entergy to provide that.
20 Let ‐‐ Entergyt migh want to answer that
21 themselves.
22 And then as far as the question,
23 Commissioner Presley, on the need‐by date, we
24 show that maybe a project is needed this
25 summer of 2010, but the in‐service date
0047
1 couldn't be till maybe summer of 2012 due to
2 that construction lead time. And so there
3 would be some mitigation plan in place to 4 make sure the system is reliable.
5 CHAIRMAN PRESLEY:
6 Well, we're talking about two
7 different things here. You're talking about
8 your perspective as a need‐by date and their
9 perspective as ‐‐ perspective of an
10 in‐service date.
11 MR. HOLLAND:
12 Yes.
13 CHAIRMAN PRESLEY:
14 I'm talking about, are there
15 differences between SPP, ICT and Entergy on
16 the need‐by, just a pure, we need it by this
17 summer? Is there an argument there?
18 MR. HOLLAND:
19 Typically not, because we're
20 looking at the reliability, and we compare
21 the reliability assessments that we do and
22 that Entergy does.
23 CHAIRMAN PRESLEY:
24 I mean, if there were to be a
25 difference, if you were to say it's needed by
0048
1 July of 2010, and they would say, no, it's
2 not needed till July of 2011, at that time, I 3 just feel, personally, we should have some
4 sort of trigger in which we're able to, at
5 least, go through that and see what the
6 reason is behind it. Because that is the
7 type of thing that can just get bigger that
8 delays these projects out because there's a
9 ‐‐ there is a dispute between the ICT and the
10 company on just a pure need‐by, not the
11 in‐service. That's a whole different item.
12 Just the basic premise of when we need it.
13 MR. HOLLAND:
14 We do ‐‐ by the tariff, we do
15 perform a reliability assessment separate
16 from Entergy's reliability assessment. We
17 present that to the Long‐Term Transmission
18 Issues Working Group, and if there is
19 something that we can't work out, then it's
20 discussed there.
21 CHAIRMAN PRESLEY:
22 Mr. Chairman, I guess what I'm
23 trying to get at is, we've had every kind of
24 problem in the world with the base load ‐‐
25 with the base plan, excuse me, and the
0049
1 construction plan, and if this is a nuance in 2 which, again, we could have space between
3 what the ICT says and what Entergy says, I
4 think that, at that point, ought to come to
5 us to look at what's going on, why there's an
6 argument on need‐by.
7 PRESIDENT SUSKIE:
8 Yeah. So if you could, an
9 additional report, if there is a difference
10 in Entergy's view of in‐need ‐‐ need date and
11 SPP's need date, that would be beneficial.
12 Mr. Schnitzer?
13 MR. HOLLAND:
14 We'll commit ‐‐ we'll commit to
15 that.
16 PRESIDENT SUSKIE:
17 Okay.
18 MR. SCHNITZER:
19 I'm Michael Schnitzer on behalf of
20 Entergy. Mr. Chairman and Commissioner
21 Presley, I think, in response to what you
22 just asked for, we'll get at this, but my
23 understanding is, presently, where there is a
24 difference in the date betweene th ICT's base
25 plan and Entergy's construction plan, the
0050 1 date in Entergy's plan is the earliest date
2 that they think it's feasible. So it's not a
3 case where we have a difference of opinion
4 between two different in‐service dates, both
5 of which are feasible. The dates that are in
6 the Entergy plan may be later than some of
7 the dates in the ICT plan, but it's because
8 Entergy doesn't believe that particular
9 upgrade can be built by the earlier date.
10 So I don't think it's ‐‐ getting to
11 your question, I don't think it's a
12 difference in when is the need; it's a
13 difference in how quickly can the facility be
14 put in‐service. And I think the information
15 you asked for, which will be provided, will
16 make that distinction, which I think is the
17 nature of your question.
18 CHAIRMAN PRESLEY:
19 Mr. Schnitzer, I guess, again, I
20 understand where you're coming from on that,
21 but, obviously, this is a area, again, where
22 there could be space between the company and
23 the ICT in which delays are made just because
24 there's an argument, and that, then, puts
25 this control particularly in Entergy's hands 0051
1 of whether to say, well, no; we don't need it
2 by then; go fly a kite; we don't want to do
3 it. At that point, it needs to be triggered
4 where, at least, this committee has a chance
5 to understand what's the reasoning behind it.
6 MR. SCHNITZER:
7 I understand, Commissioner, and I
8 wasn't in any way trying to suggest that your
9 question ‐‐
10 CHAIRMAN PRESLEY:
11 I guess, though, just ‐‐ we're
12 talking about apples and oranges.
13 MR. SCHNITZER:
14 That's right. I just want toe mak
15 clear that in the current situation, that the
16 difference between the schedule in the ICT
17 base plan and construction plan, to the
18 extent that there is a difference on some of
19 these elements, it's a feasibility issue from
20 a construction feasibility time frame issue,
21 not ‐‐
22 CHAIRMAN PRESLEY:
23 So you're representing today that
24 there are no disagreements on need‐by? 25 MR. SCHNITZER:
0052
1 I think that Entergy has the dates
2 in there that it thinks are the earliest it
3 can for of all the elements that ‐‐
4 CHAIRMAN PRESLEY:
5 No, no, no. I understand that.
6 I'm saying is there a difference ‐‐ wait a
7 minute. Let's let him answer. You've been
8 talking about this.
9 MR. SCHNITZER:
10 Yes.
11 CHAIRMAN PRESLEY:
12 I just want to know is there a
13 difference between today, when the SPP ICT
14 says we need it by this date and y'all say,
15 no, we don't need it by that date. It's that
16 simple.
17 MR. SCHNITZER:
18 Yeah. I would have to ‐‐ that's a
19 slightly different point than the one I was
20 making. I'll let ‐‐ I'll let Charles Long
21 respond to it. But I think Entergy is
22 looking at how quickly they can get it done
23 and, you know, whether their need date is 24 exactly the same or not, it's can they get it
25 done by when they need it. But I'll let ‐‐
0053
1 with your permission, I'll let ‐‐ I'll let
2 Charles Long respond to that specific
3 question.
4 MR. LONG: In the ‐‐ this is Charles
5 Long with Entergy. In the current plan, the
6 ICT and Entergy agreed on the need‐by dates
7 on all the projects that are in there, so the
8 delays in the current plan are simply ‐‐ we
9 may need it by 2011, but we have 20 miles of
10 line to build and it's going to take longer
11 than that. That's all the difference is.
12 But your point ‐‐ there still could
13 be an opportunity in the future where we may
14 not agree, although I think the chances are
15 pretty slim. You know, we look at the same
16 reliability metrics when we do the studies,
17 so I think the chances are pretty small that
18 would happen, but it's not impossible.
19 PRESIDENT SUSKIE:
20 And I think the request is, if
21 there is that agreement, we'd like to get
22 briefed on it. And, also, the issue of, if 23 there's a practical ‐‐ the in‐service date
24 and need date don't match because of
25 practical things, I think it would be helpful
0054
1 to us ‐‐ for instance, the Acadiana Load
2 Pocket. I don't understand it, but Jimmy
3 Field is very familiar with it. He can help
4 facilitate that. The same thing if you have
5 issues in Arkansas. It could be regulatory.
6 You know, commissioners ‐‐ we could make
7 phone calls to county judges and say, hey, we
8 really need this line in‐service; can you
9 help. And so I think that's going to be a
10 good ‐‐ for us to be educated so we can go
11 back to our perspective states and maybe
12 assist and facilitate that moving forward.
13 MR. BOOTH:
14 Mr. Long, if Entergy's need date is
15 earlier than Entergy's feasibility date, does
16 Entergy identify mitigation measures that it
17 will take to ensure that the need is
18 satisfied?
19 MR. LONG:
20 Yes, we do. And those are shared
21 with the ICT. 22 MR. BOOTH:
23 Thank you.
24 PRESIDENT SUSKIE:
25 Thank you.
0055
1 Bruce?
2 MR. REW:
3 Next, I would like to transition us
4 to the metrics. The ICT has worked with
5 several folks to put together a draft of ICT
6 metrics. The metrics report that you're
7 going to see today is based off the one that
8 Southwest Power Pool has been using in its
9 quarterly reporting to its boards for the
10 last several years. We've identified several
11 of those that we would like to present today
12 as an example for discussion. Let me just
13 briefly describe each of these as I walk
14 through them.
15 The first one, 1a, is congestion.
16 In this graph, it shows the hours and the
17 gigawatt hours curtailed for the last year on
18 the Entergy system. I'll just kind of slowly
19 step through these, and ask me questions.
20 PRESIDENT SUSKIE: 21 Sure. Is there any way to do a
22 comparison to the Entergy system to other
23 systems as in, you know, what ‐‐ if you take
24 the entire number of megawatts the system
25 has, you know, let's say in a month or a year
0056
1 or however you want to categorize it, and
2 compare it to how much was required to be
3 curtailed, then, say, compare that to SPP or
4 Southern Company or TVA? You know, it's just
5 a thought I have for a good comparison.
6 MR. REW:
7 Well, with the SPP system, that
8 would be pretty easy, because the reports are
9 very similar. We already developed that
10 metric. For other reliability coordinators,
11 that could be significant work to develop it,
12 because it is some work for us to develop
13 these metrics. It's not readily available,
14 where we just pull it down, so that's
15 something I would just have to check on to
16 see if there are reliability coordinators
17 that had similar reports that we could pull
18 the data from.
19 PRESIDENT SUSKIE: 20 Yeah. I would be curious to see ‐‐
21 I guess since it's simpler, since you have
22 the data to ‐‐ easier for you to compare SPP
23 versus Entergy ‐‐ and, of course, you can't
24 ‐‐ it's not ‐‐ you can't just do the number
25 of TLRs. I think what ‐‐ you've got to
0057
1 compare it to the scope and size of the
2 systems, I think would be a fairer analogy.
3 And I know after Charleston, Entergy
4 submitted some filings in rebutting comparing
5 that they were similar to other
6 organizations. But I'll be kind of curious
7 to try to get a ‐‐ the best apples‐to‐apples
8 comparison. I think that would be helpful.
9 Yes, sir?
10 MR. PEDERSEN:
11 Todd Pedersen, Westminster
12 Utilities. Just looking at this 1a, I was
13 just quickly looking at the table itself
14 where December '09, January '10, February are
15 exactly the same hours. But if you look at
16 the graphs, they're not the same, so
17 somewhere in there, it appears to me that the
18 link from your graph to your table is not 19 matching up.
20 MR. REW:
21 Okay, yeah. I see that. Yeah,
22 we'll check up on that, Todd, and see. But
23 the graph ‐‐ obviously, the graph is
24 fluctuating, so those numbers should be
25 correct in the graph. We probably just need
0058
1 to carry eit over in th table down below.
2 MR. PEDERSEN:
3 Okay. If you look ‐‐ if you
4 compare the TLR times for January '10, it's
5 showing 138, and the actual, just for that ‐‐
6 I don't ‐‐ I just think the link between the
7 graph ande th table are not...
8 MR. REW:
9 Okay. We'll follow up on that,
10 Todd.
11 MR. PEDERSEN:
12 Thank you.
13 PRESIDENT SUSKIE:
14 So you believe the graph is
15 correct, but numbers in the table below may
16 not be?
17 MR. REW: 18 Yes. These numbers here are all
19 the same, but when you look in the graph
20 right here, they do vary in the graph.
21 PRESIDENT SUSKIE:
22 Thank you.
23 Patrick?
24 MR. CLAREY:
25 Following up on a question of other
0059
1 reliability coordinators reporting this. I
2 think Midwest ISO reports it in a similar
3 fashion, Bruce. I'll send you their monthly
4 link.
5 MR. REW:
6 Thanks, Patrick.
7 PRESIDENT SUSKIE:
8 Commissioner Field?
9 VICE‐PRESIDENT FIELD:
10 Bruce, do you have the ability or
11 havee th technology to know if any of these
12 curtailments were interruptibles or firm?
13 Are these all firm?
14 MR. REW:
15 In the next couple of metrics, I'll
16 go into the different TLRs ‐‐ 17 VICE‐PRESIDENT FIELD:
18 Okay.
19 MR. REW:
20 ‐‐ that have occurred, what levels
21 they're at.
22 Okay. So it's a good transition,
23 Commissioner Field, to the next slide, which
24 is 1b, and that shows ‐‐
25 PRESIDENT SUSKIE:
0060
1 Did y'all coordinate that
2 transition?
3 VICE‐PRESIDENT FIELD:
4 We have records of that.
5 MR. REW:
6 This shows congestion by TLR level,
7 and then we break it down into 3A all the way
8 up to 5B and NNL. So this depicts what your
9 question was, Commissioner .Field
10 VICE‐PRESIDENT FIELD:
11 Explain it to me, because I don't
12 see it just looking at it.
13 MR. REW:
14 If you look at ‐‐ I'll just pick
15 the first one, March of '08. 16 VICE‐PRESIDENT FIELD:
17 All right.
18 MR. REW:
19 We have a ‐‐ level 3A is
20 color‐coded there, which is the ‐‐ I guess
21 like the teal color, and it's at the bottom,
22 and then you move up from there. Level 3B
23 has .9, and Level 4 is .3, and that's all
24 depicted on the graph under the first column
25 of March '08. It probably would be better to
0061
1 look at, like, October '08, which has much
2 larger numbers. You can see the very large
3 one, the bottom color there, which is like
4 the teal color.
5 VICE‐PRESIDENT FIELD:
6 Does the teal color mean that ‐‐
7 are those customers firm customers?
8 MR. REW:
9 The firm customers are in ‐‐ TLR
10 Level 5 are the firm customers.
11 VICE‐PRESIDENT FIELD:
12 So that's ‐‐
13 MR. REW:
14 So that would be the gigawatt hours 15 curtailed at TLR Level 5.
16 PRESIDENT SUSKIE:
17 Is that 5A and 5B?
18 MR. REW:
19 Yes.
20 VICE‐PRESIDENT FIELD:
21 Both of them. Okay. So that the
22 brown and the light brown or tan are the firm
23 customers?
24 MR. REW:
25 Yes, that's correct.
0062
1 VICE‐PRESIDENT FIELD:
2 Okay.
3 MR. REW:
4 It would be the top ‐‐ top ‐‐
5 actually, the top three.
6 VICE‐PRESIDENT FIELD:
7 Well, that makes sense, then. The
8 interruptibles are curtailed first, and then
9 you move into the current customers.
10 MR. REW:
11 Yes, that's correct.
12 VICE‐PRESIDENT FIELD:
13 Okay. 14 PRESIDENT SUSKIE:
15 And what is "NNL Assigned"?
16 MR. REW:
17 That's Needed Network Load. That's
18 the ‐‐ when you have a firm curtailment and
19 part of it's assigned to the network service,
20 that represents the amount of generation
21 re‐dispatch that they've had to do to curtail
22 their loading on the transmission line.
23 Okay. The next slide is 1c, and
24 that also covers congestion, but this in the
25 amount of hours, versus 1b was the gigawatt
0063
1 hours. So this is ‐‐ this represents the
2 amount of time that you're in it.
3 Any questions on this one?
4 MR. SCHNITZER:
5 Bruce?
6 MR. LONG:
7 This is Charles Long with Entergy
8 again. I just want to make sure there's no
9 confusion about what a TLR is, because some
10 of the questions that Commissioner Field has
11 asked just makes me aware. These aren't
12 actual load curtailments of customers 13 curtailed. This is TLR 5 where generation
14 (inaudible) takes place essentially, right?
15 MR. REW:
16 Yeah. That's correct. Like, for
17 the TLR 5, that is a transaction that is
18 curtailed. And what usually happens is, the
19 load‐serving entity obtains other resources
20 to continue providing the service. It's not
21 shedding load at TLR level 5. They're two
22 different things. It's not a load shedded.
23 It merely represents a firm transaction
24 that's been curtailed.
25 VICE‐PRESIDENT FIELD:
0064
1 Gee, I'm glad you clarified that,
2 because I had the impression that maybe these
3 were ‐‐ would have actually been interrupted
4 and curtailed.
5 MR. REW:
6 No. I'm sorry, Commissioner Field.
7 That's not where we're shedding load ‐‐ we're
8 shedding load at all. It's curtailing firm
9 service.
10 VICE‐PRESIDENT FIELD:
11 All right. 12 MR. LOUDENSLAGER:
13 Sam Loudenslager, Arkansas Staff.
14 Would be it be helpful for Bruce to kind of
15 walk through for you folks what each of the
16 different TLR levels kind of means?
17 PRESIDENT SUSKIE:
18 Please. I thought about asking
19 that question myself, so please.
20 MR. REW:
21 The TLR Level 3, that is your
22 nonfirm service, and the different levels
23 there entail the different length of service
24 for nonfirm. So you curtail the shorter
25 nonfirm service first and then longer
0065
1 nonfirm. For example, you curtail a daily
2 nonfirm service first before you curtail a
3 monthly nonfirm. So you do recognize the
4 length of time for nonfirm curtailments. The
5 Level 4 are other readjustments to the system
6 that can occur prior to a TLR Level 5. And
7 then level 5 ‐‐
8 PRESIDENT SUSKIE:
9 What are some examples of a Level 4
10 curtailment? 11 MR. REW:
12 A Level 4 would be, for example,
13 cutting all nonfirm. If there's anything
14 else left on it prior to going into firm
15 curtailments.
16 PRESIDENT SUSKIE:
17 Okay.
18 MR. REW:
19 And then the TLR ‐‐ I'm trying to
20 recall the difference between 5A and B.
21 There's two levels of firm curtailment in TLR
22 Level 5. One of them is whether you curtail
23 it immediately, and then the second one is if
24 you curtail it at the top of the next hour.
25 So that's in anticipation of the next hour
0066
1 still being ‐‐ experiencing a loading. And
2 then, again, the NNL is where it's been
3 identified that network service is also
4 contributing to the loading on the
5 transmission facility, and because it's a pro
6 rata, share the paying type of curtailment,
7 they do get assigned part of that reduction
8 in flow requirement on the line, and they
9 provide some NNL relief is what we call it, 10 where they do some re‐dispatch to reduce the
11 loading on the identified transmission
12 facility. So the network customers also
13 contribute to that.
14 VICE‐PRESIDENT FIELD:
15 Bruce, is it safe to say that the
16 utility's obligation is to dispatch the most
17 economical power that it can for its
18 customers under normal conditions?
19 MR. REW:
20 I don't ‐‐ I can't answer that.
21 VICE‐PRESIDENT FIELD:
22 Assume that that's true.
23 MR. REW:
24 Okay. Assume that that's true.
25 VICE‐PRESIDENT FIELD:
0067
1 At what level ‐‐ is it TLR 4 or 5
2 that they have to re‐dispatch from other
3 units which may not be as economical?
4 MR. REW:
5 Well, they would have to do that at
6 a TLR Level 5.
7 VICE‐PRESIDENT FIELD:
8 5. So every time you have a 5, 9 then that signals that the ‐‐ if my
10 assumption is right, and I believe it is,
11 that they, under an obligation to supply
12 those customers released cost power, then
13 when we reach TLR 5, then they're
14 re‐dispatching from somewhere in the system,
15 and the units are not as economical; it's
16 costing the ratepayers every time we have a
17 TLR 5, if my assumption is correct?
18 MR. REW:
19 Yes. If your assumption is correct
20 that they're dispatching it based on those
21 economic units, then, if we would require
22 them to re‐dispatch it, it would be
23 re‐dispatched into a higher cost unit.
24 VICE‐PRESIDENT FIELD:
25 So, see, that's why it's important
0068
1 to us as regulators to know how they compare
2 to other companies, as Chairman Suskie asked,
3 because we think there ‐‐ it appears that
4 there's quite a few TLRs, but we don't know
5 whether that's inordinate or whether that's
6 typical. In other words, but this is a lot
7 of re‐dispatching; every time you get to a 8 TLR 5, we know the most economical power is
9 not reaching the consumer, and they're paying
10 additional dollars in their rate, if my
11 assumption is correct.
12 PRESIDENT SUSKIE:
13 Jimmy and Patrick, I just can't
14 help but pass up this opportunity. So every
15 time it's re‐dispatched and Louisiana gets
16 higher costs, Arkansas pays more money to
17 Louisiana. Sorry. Couldn't pass that one
18 up.
19 VICE‐PRESIDENT FIELD:
20 Thank you.
21 PRESIDENT SUSKIE:
22 Well, it's $391 million this year.
23 Anyway, I couldn't pass up that opportunity.
24 Sorry about that, Patrick.
25 CHAIRMAN PRESLEY:
0069
1 He knows ‐‐ he knows that figure
2 down to the penny.
3 VICE‐PRESIDENT FIELD:
4 (Inaudible) ‐‐ a bunch this year.
5 PRESIDENT SUSKIE:
6 Every time I go to my mother's 7 house, she pulls out her energy bills and
8 sees the line that says, "FERC‐ordered
9 payments."
10 MR. REW:
11 Okay. Let me go on to 1f. 1f
12 identifies congestion by flowgate, and this
13 is for the previous 12 months. So this
14 identifies the flowgates in which we've had
15 the largest number of gigawatt hours
16 curtailed on it, and it also shows the
17 percent of time in the TLR.
18 Any questions on 1f?
19 MR. LOUDENSLAGER:
20 I ‐‐ this is Sam Loudenslager with
21 the Arkansas Staff. I would just point out
22 that in the SPP RTO, this chart is very
23 important. We use this ‐‐ the Cost
24 Allocation Working Group uses this kind of as
25 a starting point in trying to figure out
0070
1 where those ‐‐ where projects might be most
2 economic in relieving congestion issues
3 across the footprint. One of the things that
4 we've asked the ICT to do is to pull this
5 data together for you folks and to break it 6 down on a state‐by‐state level, as well.
7 What we should be able to do is compare these
8 over time to figure out if congestion
9 problems are getting fixed or not, put pretty
10 simply.
11 Now, having said that, Bruce I do
12 actually have a question. I know the SPP,
13 there's the ‐‐ looks like a greater reliance
14 on temporary flowgates than I see in the
15 Entergy region. Is that ‐‐ is that true or
16 not? Do you know what I'm talking about?
17 MR. REW:
18 Yes. In the SPP RTO, there is a
19 mechanism in place where they issue temporary
20 flowgates to relieve constraints that are not
21 in the permanent list, and a lot of times
22 those will pop up as being in their most
23 constrained list; whereas Sam pointed out in
24 the Entergy one, there isn't the use of ‐‐
25 the large use of temporary flowgates. So the
0071
1 flowgates that we've identified here are, you
2 know, ones that have been in place and are
3 recognized.
4 CHAIRMAN PRESLEY: 5 Bruce, let me ask you: I noticed
6 we're on the ‐‐ Mississippi only shows up on
7 here twice, but we're at the top, with 115
8 gigawatts curtailed, and then the percentage
9 of 4.73 percent in TLR. Is there any way to
10 know, of that 4.73, is that a TLR 5, or can
11 you quantify that?
12 MR. REW:
13 Jody is telling me that we do have
14 that information, we just don't have it with
15 us. But you can ‐‐ it is available to
16 identify, you know, exactly what the TLR
17 level is on that particular flowgate, whether
18 it's 3 or 5 and the amount of time, so that
19 is available.
20 CHAIRMAN PRESLEY:
21 Okay. Over here in the proposed
22 solutions, I'm looking at this ‐‐ so we're
23 looking at a time frame of when?
24 MR. HOLLAND:
25 So, Commissioner Presley, these are
0072
1 shown as economic projects and suggestions
2 for the economic study process that we call
3 the ISTEP. So these ‐‐ though these are 4 solutions, there's no commitment to
5 construct.
6 CHAIRMAN PRESLEY:
7 And so using the assumption that I
8 think is right that Commissioner Field used a
9 minute ago, if involved in this ‐‐ I mean,
10 115 gigawatts curtailed is the largest on the
11 page,d an so, at that point, we're having to
12 run higher‐cost units from Mississippi
13 ratepayers to make up for that. Can y'all
14 just kind of let us know, maybe, again, in a
15 ‐‐ just a follow‐up e‐mail, what of that was
16 a TLR 5 so that we can have some sort of
17 idea; also, any type of chart for the
18 solution, if you can.
19 MR. HOLLAND:
20 Certainly. We'll take that up next
21 time.
22 PRESIDENT SUSKIE:
23 Mr. Long?
24 MR. LONG:
25 There are ‐‐ several of these on
0073
1 here do have solutions that are already
2 underway. The top one that he mentioned is 3 under construction right now. I think we had
4 half of it finished a few days ago. We're
5 still working on the other end of the line,
6 but it should be done very shortly, within
7 the next couple weeks.
8 CHAIRMAN PRESLEY:
9 Okay.
10 MR. LONG:
11 And then there ‐‐ the ones that are
12 in the ISTEP are studied, you know, through
13 the economic process, and they're evaluated,
14 you know, as kind of a cost/benefit to see
15 what needs to be done with those. But
16 several of these, we are under construction
17 already.
18 CHAIRMAN PRESLEY:
19 Since that's such a big amount, I
20 just ask maybe you could coordinate that with
21 some EMI officials and give the PSC in
22 Mississippi official notice when that's
23 completed. Also, Bob Grenfell in the room
24 from Entergy Mississippi, we'd be interested
25 to know any data that the company has, Bob,
0074
1 related to the dispatch or re‐dispatch that 2 was made that involved that. If that's close
3 to being done, we'd like to know.
4 Thank you.
5 PRESIDENT SUSKIE:
6 Mr. McCulla?
7 If you could pass the mic. back.
8 MR. McCULLA:
9 This is Mark McCulla from Entergy.
10 I just wanted to clarify. You raised the
11 point about the generation being moved to
12 Mississippi. These flowgates ‐‐ this
13 particular flowgates in Mississippi doesn't
14 necessarily mean that generation in
15 Mississippi shifts. It means transactions
16 that flow across that flowgate have a certain
17 impact, but it doesn't necessarily mean
18 generation in Mississippi gets shifted.
19 CHAIRMAN PRESLEY:
20 But is this flowgate not tied to
21 Grand Gulf? When I say that, I mean, as I
22 read it, you're referencing ‐‐ SPP references
23 a Grand Gulf upgrade.
24 MR. McCULLA:
25 He'll have to answer that.
0075 1 CHAIRMAN PRESLEY:
2 I feel like we're on Donahue. Just
3 start throwing the mic. out there.
4 MR. LONG:
5 Mr. McCulla's statement is correct
6 about the generators and how they move. They
7 can be ‐‐ you know, they have to be sort of
8 near, but they don't necessarily have to be
9 in Mississippi, but we ‐‐
10 CHAIRMAN PRESLEY:
11 I understand. I've got all that.
12 My concern is this, to save you some time,
13 and that is that Grand Gulf obviously is the
14 cheapest generator, period, for Entergy's
15 customers. And so if this flowgate issue is
16 barring that generation and we're having to
17 fire up something else to make up for it, you
18 know, common sense tells us that we're
19 costing ratepayers money.
20 MR. LONG:
21 Yeah. I can assure you Grand Gulf
22 will never re‐dispatch, because, if it's not
23 100 percent, something is typically wrong
24 with the plant, not the transmission.
25 CHAIRMAN PRESLEY: 0076
1 I understand.
2 MR. LONG:
3 The reason Grand Gulf is mentioned
4 is because this was an element that was
5 identified in the Grand Gulf upgrade study as
6 an element that needed to be upgraded.
7 That's why it's listed in the comments.
8 CHAIRMAN PRESLEY:
9 Thank you.
10 PRESIDENT SUSKIE:
11 Thank you.
12 Jennifer Vosburg?
13 MS. VOSBURG:
14 Just before you move off the
15 slides, one of the ‐‐
16 UNIDENTIFIED SPEAKER:
17 Can't hear you.
18 MS. VOSBURG:
19 One of the ‐‐ one of the
20 discussions we've had in the Working Group
21 meeting was in employing our LAPs. Have we
22 made any progress on that particular issue?
23 PRESIDENT SUSKIE:
24 Sam? 25 MR. LOUDENSLAGER:
0077
1 We're getting there, and we're
2 trying to pull the information together so
3 that it can be reported by state, as well, as
4 we discussed at the stakeholder meeting.
5 We've gotten some additional information
6 that ‐‐ it's ‐‐ we still have to kind of look
7 at it a little bit, Jennifer.
8 MS. VOSBURG:
9 And the issue was that the ICT did
10 not have LAP information; it was going to
11 have to come from Entergy?
12 MR. LOUDENSLAGER:
13 Right. And that exchange has been
14 made. That information has gone from Entergy
15 to the ICT and to the Working Group, and
16 we'll be talking about it next week.
17 MS. VOSBURG:
18 Just looking at the 1b slide, if
19 you could pull that up. And I noticed the
20 NNL is listed on here. I don't want to get
21 down to the details, but just maybe some
22 background information on what's actually
23 being captured here. Just looking at the 24 numbers, the difference between the Level 5
25 and the NNL responsibilities seems so off.
0078
1 We thought they were kind of supposed to be
2 done at the same time. I'm just trying to
3 figure out what you're actually capturing
4 there. They're supposed to be re‐dispatched
5 at the same time you have the Level 5.
6 MR. REW:
7 Well, Jennifer, this is Bruce
8 again. That's something we'd have to look
9 into. It could be a situation where there
10 weren't any TLR Level 5 transactions
11 available for re‐dispatch. It could be a
12 situation where you have a lot of
13 transactions on it, so the amount of TLR
14 Level 5 on the transactions is significantly
15 greater than the NNL. So there's a lot of
16 different things that can occur that can
17 cause it to maybe look unusual up there, but
18 that's something we could follow up on.
19 MS. VOSBURG:
20 Is there any additional reporting
21 that can be done on the NNL? Just what
22 additional reporting can be done on the NNL 23 side of it? I mean, we're hearing that, you
24 know, that the nuclears don't get backed
25 down, but we do have coal that is being
0079
1 backed down.
2 PRESIDENT SUSKIE:
3 Give the mic. back. You know, this
4 kind of is like a talk show, but something
5 tells me we'd have very few viewers.
6 CHAIRMAN PRESLEY:
7 Pull us the first day.
8 MR. REW:
9 Jennifer ‐‐ this is Bruce again ‐‐
10 I don't know if off the ‐‐ offhand what would
11 be available for reporting on the NNL.
12 That's something we'd just have to look into
13 to see what we could report.
14 PRESIDENT SUSKIE:
15 Mr. Newell?
16 MR. NEWELL:
17 This is Gary Newell. The actual
18 TLR 5 reports that are submitted to NERC have
19 in them a chart that shows the assignment of
20 this NNL responsibility among control areas
21 that are affected by a Level 5 TLR. So if, 22 for example, during a TLR 5, it may be that
23 more than one control area is assigning an
24 NNL target by the reliability coordinator.
25 And, in fact, in the Acadiana Load Pocket,
0080
1 when there has been TLR 5s there, typically,
2 there's an NNL responsibility, some of which
3 goes to Entergy, some of which goes to CLECO,
4 some of which goes to Lafayette and the NRG,
5 Louisiana Generating.
6 One question I did have, Bruce,
7 about this, when you showed me ‐‐ and this
8 may explain some of the discrepancy. I don't
9 know. But when you show "NNL Assigned," is
10 that just the NNL assigned to the Entergy
11 control area? Because you may have a
12 curtailment that's, you know, saying 3
13 gigawatt hours and maybe one gigawatt hour is
14 assigned to Entergy and would show up here,
15 and there might be two other gigawatt hours
16 assigned to other control areas. Do you
17 know?
18 MR. REW:
19 I believe that's NNL assigned to
20 the Entergy Balancing Authority, but I'll 21 have to confirm that. My understanding was
22 that it was really the Balancing Authority in
23 Entergy. Let me ‐‐ let me confirm that.
24 MR. NEWELL:
25 Okay.
0081
1 PRESIDENT SUSKIE:
2 There was something I've been
3 curious about. If there's numbers out there
4e of th cost of the curtailment to address
5 whether it's by, you know, utility or what.
6 What are the costs to these things? You
7 know, not just Entergy, but also other
8 Entergy customers, but also other, you know,
9 utilities and other customers. And I don't
10 know ‐‐ I assume, obviously, it varies year
11 to year. That's something I'd be curious
12 about.
13 Mr. Newell?
14 MR. NEWELL:
15 Yeah, President Suskie. This is
16 Gary Newell again. I ‐‐ you'd have to look
17 at each ‐‐ you know, each TLR and see which
18 units moved to satisfy the NNL
19 responsibility. It would be a task, but I 20 can tell you this much just from Lafayette's
21 experience: When Lafayette's generation has
22 been re‐dispatched during a TLR 5, typically,
23 what happens is that their firm transmission
24 schedule for delivery of energy from the
25 Rotamaker station, which is up on the CLECO
0082
1 transmission system, that schedule is
2 reduced, and Lafayette is forced to operate
3 their gas‐fired generation within the ‐‐
4 basically, within the city limits. It's very
5 close inside the city system. And the cost
6 spread between those two is the cost between
7e th relatively low cost coal, powder
8 [phonetic] river coal, burned at Rotamaker
9 versus natural gas‐fired boilers that are
10 very old and relatively inefficient. So I ‐‐
11 I think, you know, rough numbers, the
12 Rotamaker is ‐‐ usually generates somewhere
13 in the 30 ‐‐ 30‐dollar‐megawatt‐hour range,
14 and the units inside the city generate more
15 like up around $70 a megawatt hour. And it's
16 a huge penalty whenever Lafayette is
17 re‐dispatched during TLR 5, and those
18 typically occur because of congestion on 19 flowgates located outside Lafayette's system.
20 They're on Entergy flowgates which, just
21 because of the topology of the system, happen
22 to be best ‐‐ the loading is reduced best by
23 operating Lafayette generation and CLECO
24 generation, and then we get ‐‐ we get the
25 cost penalty, ande th relief goes to the
0083
1 flowgate. That will give you an order of
2 magnitude on the difference.
3 SECRETARY ANDERSON:
4 You know, without the ‐‐ it seems
5 to me that the actual cost is really
6 critical. We get that every ‐‐ every month
7 in ERCOT, the cost of economic dispatch, the
8 amount and the cost. Otherwise, how do you
9 make a decision on whether transmission is
10 economic or not?
11 VICE‐PRESIDENT FIELD:
12 I think you're right, Ken. We need
13 that information. When you look at hthe grap
14 at the bottom right‐hand corner ‐‐ that's not
15 the same one.
16 SECRETARY ANDERSON:
17 You're talking about on page ‐‐ 18 VICE‐PRESIDENT FIELD:
19 No.
20 CHAIRMAN PRESLEY:
21 Page 1c.
22 PRESIDENT SUSKIE:
23 I think you're 1c.
24 VICE‐PRESIDENT FIELD:
25 Average monthly TLR 5s in time of
0084
1 hours is increased from 2007, at about 70 or
2 75; 2008, to maybe 90; and then, in 2009,
3 it's all the way up to 150 hours a month
4 average. So that's a ‐‐ that's quite a bit
5 of re‐dispatch that's being required on the
6 system.
7 CHAIRMAN PRESLEY:
8 And, obviously, 2010 is not ‐‐ I
9 mean, our TLRs mainly are in the summer, so
10 that's ‐‐ when we look at that number,
11 there's no grand reduction.
12 MR. REW:
13 Yeah. That's just for the first
14 quarter.
15 VICE‐PRESIDENT FIELD:
16 If they can do it in ERCOT, why 17 can't we have that information? As
18 regulators of a monopoly, it seems like we
19 should be ‐‐ I'm not saying you, Bruce, have
20 ‐‐ are the one to have it. We should have
21 that information to know how much re‐dispatch
22 costs.
23 That's interesting, Ken, that y'all
24 have that information. Then you can make a
25 judgment, well, if we can cure it with a
0085
1 $40 million transmission relief, then ‐‐ and
2 we might save, you know, hundreds of millions
3 of dollars, that seems like that's
4 information that this committee needs to help
5 make the decisions.
6 PRESIDENT SUSKIE:
7 Kind of throw that as an action
8 item, you know, what would be a good way to
9 gather that information. Because I assume
10 Entergy doesn't have the information on
11 Lafayette's costs and ‐‐ but where Lafayette
12 can say, hey, when had to curtail these four
13 or five times, they cost "X" amount of
14 dollars to our ratepayers. So I assume it's
15 almost each utility‐specific. 16 Mr. Newell?
17 MR. NEWELL:
18 Actually, President Suskie, we've
19 screamed about it everywhere we can and as
20 many times as we can.
21 PRESIDENT SUSKIE:
22 Well, you're now in the forum, I
23 believe.
24 MR. NEWELL:
25 Great. It ran to a total of about
0086
1 $2 million last summer for Lafayette, and
2 Lafayette is a small ‐‐ a pretty small piece
3 of the total picture. You know, there has
4 been some progress made on, as I understand
5 it, dealing with re‐dispatch costs related to
6 the construction‐related outages in the
7 Acadiana Load Pocket. But I think you're
8 still ‐‐ that's just sort of a subset of the
9 hours that are expected in the future to have
10 TLRs, but it ‐‐ you know, it ran, as I say,
11 about $2 million for just one summer for a
12 small system, so it ‐‐ if you look at it in
13 totals, it's probably going to be a pretty
14 significant number. 15 PRESIDENT SUSKIE:
16 That would be something for the
17 Working Group to throw up a curious study or
18 something along those lines. All right.
19 Thanks.
20 Mr. McCulla, at one point did you
21 have your hand up during all that discussion?
22 MR. McCULLA:
23 No.
24 PRESIDENT SUSKIE:
25 Okay. I thought I may have
0087
1 forgotten you. I apologize.
2 MR. REW:
3 Okay. I think we've completed 1F,
4 and we're moving on to 3b. 3b transitions us
5 to looking at transmission utilization in
6 megawatt hours, and this provides ideas to
7 the amount of network service as well as
8 point‐to‐point service that's being sold on a
9 monthly basis.
10 Any questions on this slide?
11 PRESIDENT SUSKIE:
12 Any questions anyone?
13 (No response.) 14 MR. REW:
15 Okay. Then the next several
16 slides, which we're switching to 16a, this
17 covers transmission service studies and
18 generation interconnection studies. On 16a,
19 we discuss the amount of transmission service
20 that's in progress in the different phases,
21 whether it be a system impact study or a
22 facility study. And this kind of gives you a
23 trend over the past five quarters as to the
24 amount of transmission service request volume
25 that we're working with.
0088
1 MR. LOUDENSLAGER:
2 What is SISR? What is FSR?
3 MR.W: RE
4 Okay. SISR is a System Impact
5 Study Report. FSR is Facility Study Report.
6 PRESIDENT SUSKIE:
7 And "service granted"?
8 MR. REW:
9 That would be the service that has
10 definitely signed a service agreement with so
11 that we've gone through the study process and
12 the customer has agreed to take service to 13 the point where we've signed the service
14 agreement for a long‐term service.
15 PRESIDENT SUSKIE:
16 Okay. Questions?
17 MR. CHILES:
18 Bruce ‐‐ John Chiles here ‐‐ a
19 question about your graph. Does this include
20 the affected system studies, as well, or is
21 this just a request for transmission service
22 in the Entergy footprint?
23 MR. REW:
24 Just the Entergy footprint.
25 MR. CHILES:
0089
1 Okay. So I guess the studies
2 you're doing for transactions of SPP,
3 transactions to TVR are not included in these
4 numbers?
5 MR. W:RE
6 That's correct.
7 MR. CHILES:
8 Is there any way we could get those
9 included?
10 MR. REW:
11 Yeah. We could create a graph that 12 would show those.
13 MR. CHILES:
14 Thank you.
15 PRESIDENT SUSKIE:
16 Any other questions?
17 (No response.)
18 All right. Next slide.
19 MR. REW:
20 Okay. 16b, this shows the amount
21 of proposed transmission upgrades for the
22 different studies. For example, System
23 Impact Study Report that have been completed,
24 we have identified so many dollars in
25 transmission upgrades that would be needed to
0090
1 provide the transmission service that's
2 requested.
3 Okay. Then the next ‐‐ actually,
4 the last two slides switch over to generation
5 interconnection. Wee have th feasibility
6 study, this FBS, and System Impact Study is
7 SIS, and then FS is Facility Study. So the
8 steps are you move from the Feasibility Study
9 to System Impact Study to the Facility Study.
10 And then the next slide, which is 11 16d, covers the amount of megawatts that have
12 been completed in the facility studies for
13 generation interconnections. We do have
14 LGIA, which is a large generator
15 interconnection agreement, executed.
16 PRESIDENT SUSKIE:
17 Is that it? Any questions from
18 anybody?
19 Sam?
20 MR. LOUDENSLAGER:
21 I think I'm Jennifer's ‐‐ male side
22 of Jennifer. No offense, Jennifer.
23 Bruce, I think it might be helpful
24 if you go through and define for the
25 Commissioners and for the folks in the room
0091
1 that may not be as familiar as some folks are
2 what each of those studies actually reflect
3 that were ‐‐ I think it was on the previous
4 slide. Yeah.
5 MR. REW:
6 I'll let Jody Holland walk through
7 that process.
8 MR. HOLLAND:
9 This is Jody Holland, SPP. Sam, 10 you were talking about the generation
11 interconnection slide?
12 MR. LOUDENSLAGER:
13 FS, SIS, FBS.
14 MR. HOLLAND:
15 Yes, yes.
16 MR. LOUDENSLAGER:
17 You defined what they ‐‐ you
18 spelled out the acronym, but didn't define
19 it.
20 MR. HOLLAND:
21 Okay. The Feasibility Study is a
22 really high‐level study to help a customer
23 determine whether he wants to move forward
24 with the process. So it has a short time
25 line and a short cost. Then if they decided
0092
1 to move forward, there is the System Impact
2 Study, which is a lower in‐depth study, but
3 not as in depth as a facility study. And so
4 as the studies progress, the customer gets a
5 better feel for the actual cost. So by the
6 time the Facility Study is performed, there
7 is a guarantee on the bandwidth of the cost
8 of the estimate and then cost of the upgrade. 9 And then once you have a Facility Study, the
10 customer can determine whether he wants to go
11 forward with the large generator
12 interconnection agreement, which would then
13 have the customer interconnecting to the
14 transmission group.
15 Does that suffice?
16 MR. LOUDENSLAGER:
17 Yes.
18 MR. HOLLAND:
19 So on the next page, it would be
20 when the LGIA is executed. That would be
21 actually interconnecting to the grid.
22 PRESIDENT SUSKIE:
23 Any other questions?
24 Sam, again.
25 MR. LOUDENSLAGER:
0093
1 I take it we're moving off this
2 topic, so I'd like to get some feedback, and
3 I'm sure SPP would like some feed ‐‐
4 PRESIDENT SUSKIE:
5 Dave Wilson, I think, had a
6 question on this topic, so before we
7 transition ‐‐ 8 Mr. Wilson?
9 MR. WILSON:
10 Thank you. John asked for an
11 update on these charts to show the similar
12 data for SPP. Is that going to be able to
13 show simultaneous requests on both systems?
14 MR. REW:
15 Well, my understanding is John
16r asked fo Affected System Studies, which are,
17 when there's a transmission request in one
18 area, if it's identified that it affects
19 facilities in another area ‐‐ for example, if
20 a SPP transaction was identified to affect an
21 Entergy facility, then we would do an
22 Affected System Study in Entergy system to
23 see what the impact is, and that's ‐‐ we'll
24 gather data on and provide additional
25 information for.
0094
1 MR. WILSON:
2 So it's not going to be a discrete
3 study of ‐‐ studies on the SPP system without
4 comparisons of what's going on in the Entergy
5 system?
6 MR. REW: 7 I'm not sure I understand your
8 question. If you're looking for metrics on
9 the SPP system, that's provided quarterly
10 already for the processes that they have.
11 MR. WILSON:
12 All right. Thank you.
13 PRESIDENT SUSKIE:
14 Sam? Jimmy?
15 MR. LOUDENSLAGER:
16 I never talk over a Commissioner.
17 Go ahead, Jimmy.
18 VICE‐PRESIDENT FIELD:
19 Thank you, Sam.
20 Bruce, you may do this and I'm just
21 not aware of it. But, like, you make a
22 monthly report on TLR 5s to the utilities and
23 to the state Commissions?
24 MR. REW:
25 Well, the TLR 5 reports ‐‐ any time
0095
1 we have a TLR 5, we report it to NERC, and we
2 have a limited amount of time to report it.
3 But other than that, we provide a summary of
4 all the TLR events in our quarterly reports.
5 VICE‐PRESIDENT FIELD: 6 So on a quarterly basis, all the
7 Commissions could have access to them, and
8 then if we wanted to delve into them and try
9 to ascertain the economic cost to someone
10 whether, it's LUS or Entergy's ratepayers or
11 somebody else's, we could do that just by
12 looking at those reports?
13 MR. REW:
14 Yes. And we're sending those to
15 the Commissions, and if you're not getting
16 it, just let us know, and we'll make sure
17 that you get one directly, the quarterly
18 reports.
19 VICE‐PRESIDENT FIELD:
20 We may have and I'm not aware of
21 it, but that's good. I just wanted to make
22 sure we get that information.
23 MR. REW:
24 The plan is that, once we come to
25 agreement on these metrics, that we'll
0096
1 include these in the quarterly reports, as
2 well.
3 VICE‐PRESIDENT FIELD:
4 Thank you. 5 MR. THOMPSON:
6 Commissioner, I don't believe that
7 the quarterly reports will ‐‐ Henry Thompson
8 with Arkansas Cities. I don't believe the
9 quarterly reports will give you the
10 information to determine the economic impact
11 that you're asking about. It will simply
12 show what the TLR 5s were. I may be wrong
13 about that.
14 VICE‐PRESIDENT FIELD:
15 No, I think you're right.
16 Mr. Thompson, I think you're absolutely
17 correct, but, at least, that would be a
18 starting point to make an inquiry to
19 determine what the re‐dispatch costs were to
20 the ratepayers ‐‐ somebody's ratepayers.
21 PRESIDENT SUSKIE:
22 Looking at the Working Group
23 members, kind of a thought I have ‐‐ like for
24 stakeholders' thought, one, could you look at
25 2009 and have each load‐serving entity say,
0097
1 here is how much this re‐dispatch costs our
2 company, and if it's feasible to break it
3 down to, say, a typical residential customer 4 or something. And then, on the flip side,
5 and if you are a merchant plant and you were
6 curtailed, how much did that cost you. And
7 if you had to, you know, shave your product
8 that you're selling. Just ‐‐ I'm just
9 thinking out loud. I don't know the details
10 of what would be best, but just some ideas
11 out there to help take a good look at it.
12 I'd be curious to see if Entergy can trace
13 these curtailments and the impact it has by
14 state.
15 Ms. Turner?
16 MS. TURNER:
17 Becky Turner with Entegra. We
18 do ‐‐ we've tracked that information over the
19 last several years, and we'd be happy to
20 provide it to the E‐RSC Working Group or the
21 E‐RSC in terms of costs.
22 PRESIDENT SUSKIE:
23 Thank you, Becky. Work with the
24 Working Group to come up with some mechanism
25 so we can ‐‐ kind of a standard reporting
0098
1 form in, say, the same time frame or whatever
2 that they're on. 3 MS. TURNER:
4 Okay. Sure. Absolutely.
5 PRESIDENT SUSKIE:
6 Jennifer?
7 MS. VOSBURG:
8 NRG Louisiana Generating would be
9 more than willing to work with the Working
10 Group on that issue, as well.
11 PRESIDENT SUSKIE:
12 Okay. Does Entergy ‐‐
13 Mr. Schnitzer?
14 MR. SCHNITZER:
15 Just ‐‐ can everybody hear me all
16 right?
17 PRESIDENT SUSKIE:
18 What's important, I think, is the
19 court reporter.
20 MR. SCHNITZER:
21 Michael Schnitzer. Just a couple
22 of things here. The first with respect to
23 your suggestion about using 2009 and trying
24 to see what could be done with that. I think
25 that's something we could work with. But I
0099
1 just wanted to point out that, at least, 2 Entergy believes that a lot of the TLR 5s ‐‐
3 and those are the ones that were of
4 particular concern ‐‐ a lot of them related
5 to the Acadiana situation, where there is a
6 plan to resolve it. So I would just suggest
7 that any historical analysis that we
8 contemplate, kind of separate out what's
9 already been attending ‐‐ what's already been
10 attended to versus maybe what hasn't been
11 focused on thus far. Otherwise, you might
12 get a little bit of a misleading picture, you
13 know, if we don't reflect what's already in
14 process to be resolved.
15 PRESIDENT SUSKIE:
16 Yeah. And I think it would be fair
17 to say, okay, well, how much did this cost,
18 and then what's being done to remedy it? And
19 I think that shows, you know, things that
20 work well. Let's do more of that.
21 MR. SCHNITZER:
22 That's right. You know, Bruce can
23 speak to that, but I think that the work in
24 the Acadiana area coordinating the systems
25 had a reliability piece, had an economic
0100 1 piece, and that was all part of the plan, and
2 it was based on just that kind of analysis,
3 and that's ‐‐ I just wanted to point out ‐‐ I
4 can't speak to other systems, but from
5 Entergy's perspective, a lot of the 5s
6 were ‐‐ you know, were in that.
7 The second point is, I think Sam
8 was getting ready to ask for feedback on some
9 of these metrics, and I think that we would
10 like to suggest some changes or some
11 complimentary information having just gotten
12 this yesterday. And, in particular, I think,
13 Commissioner Field, it's what you were
14 indicating, that Schedule 1f, for example,
15 broken out by TLR level might be more
16 meaningful than just all 3, 4s and 5s
17 together, as the ‐‐ as the chart is shown, is
18 one thing that we think might be either a
19 substitution or an addition. But if there is
20 going to be a process for providing feedback
21 on these proposed metrics, we'll kind of save
22 the more comprehensive set of comments for
23 that. It's whatever you want to do.
24 PRESIDENT SUSKIE:
25 Okay. We'll go to that next, I 0101
1 believe.
2 Mr. Newell?
3 MR. NEWELL:
4 This is Gary Newell. I guess I
5 wanted to disagree with Mike's suggestion and
6 we not take a look at the Acadiana Load
7 Pocket. I think he's right; it is a
8 situation that's being addressed through
9 transmission upgrades, but those are not
10 going to be completed for another two
11 summers. And I think, you know, we're
12 looking at the prospect of significant
13 potential re‐dispatch during the next two
14 summers. So until those are done, it's going
15 to be continuing to be a significant issue
16 for the load‐serving entities in the Acadiana
17 areas. And I think it might be informative
18 and useful to see what the magnitude of that
19 is and the magnitude of the upgrades that are
20 being undertaken, which is also very
21 significant. So I think that remains a good
22 case study, and, obviously, everyone will
23 recognize that progress is being made to
24 resolving that. But it would be, I think, 25 useful and informative to be able to see what
0102
1 the magnitude of re‐dispatch costs has been
2 in that area.
3 PRESIDENT SUSKIE:
4 And we're open to the time frame.
5 I just threw up 2009, you know, to get some
6 boundaries. But who knows? I'd definitely
7 like to defer to the Working Group.
8 MR. SCHNITZER:
9 Just a quick response,
10 Mr. Chairman. I don't believe I stated what
11 Mr. Newell said I stated. I've said ‐‐ I
12 didn't say that we shouldn't look at
13 Acadiana. I said that we should break that
14 out so that we don't look at 2009 on an
15 aggregate basis. And, matter of fact, we'd
16 be happy to look at Acadiana as an example.
17 We, of course, have a different
18 interpretation of the events there as
19 Mr. Newell expresses, but we'd be happy to
20 actually have a pretty full discussion from
21 our perspective of what's going on there and
22 what the plans will do. So we would welcome
23 that opportunity. 24 PRESIDENT SUSKIE:
25 Sounds good. And I always think
0103
1 it's real interesting. I think the leader in
2 helping bring solution to that was
3 Commissioner Field, so I appreciate your
4 leadership on that.
5 VICE‐PRESIDENT FIELD:
6 It was needed.
7 MR. LOUDENSLAGER:
8 Chairman?
9 PRESIDENT SUSKIE:
10 Yes.
11 MR. LOUDENSLAGER:
12 If we're ready to move off, before
13 we do that, I would like to get some feedback
14 from you folks. I would encourage the
15 stakeholders to provide any input they have
16 on these proposed metrics by the 28th, next
17 Wednesday, so the Working Group can start
18 kind of reviewing and reflecting on that ‐‐
19 those suggestions at our meeting next
20 Thursday, but ‐‐ and their input is very
21 important, as is y'all's input. So if y'all
22 have issues or ‐‐ and we've got a list of 23 action items that I'm going to, if it's okay
24 with you guys, ask Kristine to go through
25 before we move on to the next topic, just so
0104
1 we make sure we've captured those correctly,
2 so...
3 PRESIDENT SUSKIE:
4 Great thought, Sam. As far as the
5 information we would like, I think we
6 expressed it as we went through the
7 presentations earlier.
8 Any other thoughts?
9 MR. LOUDENSLAGER:
10 Let me put it a little bit
11 different. Is this generally the
12 direction ‐‐ is this helpful for you guys in
13 terms of a general direction of reporting
14 information to you? It's a graphical way of
15 seeing what's happening. I know you want
16 more, but is this generally the right
17 direction?
18 CHAIRMAN PRESLEY:
19 The only thing I would just make a
20 suggestion on is, we had ‐‐ I think on 16f ‐‐
21 well, on several of them, where we're in the 22 first ‐‐ obviously, we're in the first
23 quarter of '10, if there could be just a
24 little bit more of a comparison of the
25 quarter that we're in or where we are in the
0105
1 calendar year compared to where we were in
2 the calendar year before. Obviously, I know
3 you've got three full years.
4 Bruce, I'm looking at ‐‐ such as,
5 on 1c, Congestion, Average Monthly TLR 5 Time
6 In Hours. You've got 2007, 8 and 9, the full
7 year there, and then 10 so far. Is there any
8 way to break out kind of where in '07, '08
9 and '09, during the first quarter, it was?
10 You see what I mean?
11 MR. REW:
12 Commissioner Presley, what we do
13 when we try to capture that is we'll look
14 at ‐‐ on the individual months up above, you
15 can look at, like, March '09 versus
16 March 2010, and I'm on 1c. And you'll see
17 that there was more congestion in March '09
18 than there was in March 2010.
19 CHAIRMAN PRESLEY:
20 Right. 21 MR. REW:
22 So it gives you an idea there.
23 CHAIRMAN PRESLEY:
24 I didn't know if maybe in those
25 small graphs just on the TLR 5, you know, on
0106
1 the bottom right, if there could just be an
2 adjustment. It's not a bigm proble if it is.
3 MR. REW:
4 Okay. We'll look at that.
5 CHAIRMAN PRESLEY:
6 Sometimes just have that
7 side‐by‐side comparison.
8 MR. LOUDENSLAGER:
9 Before the break, do you want to go
10 through the action items real quickly?
11 PRESIDENT SUSKIE:
12 Sure.
13 Kristine?
14 MS. SCHMIDT:
15 I'm Kristine Schmidt of ESPY Energy
16 Solutions. And, actually, I'm going to go
17 all the way back to the first action item,
18 which was the request of Doug ‐‐ Doug Roe
19 from FERC to get the CRA promised documents, 20 and Doug committed that he'd get those out
21 today. Oh, they're being posted as we speak.
22 Excellent. So that's done.
23 On the ICT update, the Load Pocket
24 Acadiana, Commissioner Field asked that if
25 any of the industrials had volunteered or
0107
1 could volunteer for interruptible options in
2 lieu of firm load, and you committed to go
3 back to your staff and ask if there was some
4 kind of analysis or some kind of other way to
5 do that.
6 Commissioner Presley asked if the
7 ICT had been aware of the potential LAP
8 impact in the Choctaw County area with TVA.
9 And Bruce indicated he would look into that
10 and report back to the Work Group for that
11 action item.
12 For the 2010 construction plan, the
13 question was regarding the Getwell project,
14 if what's being reflected in the current 2010
15 construction plan was representative of what
16 was originally placed into the 2008 base
17 plan. That was originally on hold. Jody
18 Holland is going to review the base plan and 19 get back to Commissioner Presley on that.
20 Regarding the construction plan
21 reconciliation with the base plan, they are
22 now consistent in terms of the projects;
23 however, the in‐service and the need date may
24 not be in alignment. For the in‐service
25 dates that are out of sync, Chairman Suskie
0108
1 asked that the ICT ‐‐ for an explanation for
2 issue of delaying the in‐service. Is it due
3 to eminent domain, siting, court decision or
4 whatever? Entergy indicated their dates
5 are ‐‐ from their view, those are the
6 earliest in‐service dates that are feasible
7 from a construction perspective, and the
8 E‐RSC would like to be briefed on an ongoing
9 basis on any differences going forward on
10 those differences.
11 PRESIDENT SUSKIE:
12 Kristine, could I interrupt on that
13 a little bit?
14 MS. SCHMIDT:
15 Sure.
16 PRESIDENT SUSKIE:
17 So if Entergy couldn't get ‐‐ the 18 need date and the in‐service date are
19 different, if you could explain why. And it
20 may be, hey, our Public Service Commission
21 speed up the CCM document, whatever the case
22 may be. That would be helpful. Thank you.
23 MS. SCHMIDT:
24 And then regarding the TLR reports,
25 previously, at the March 18th meeting, it was
0109
1 requested to include the LAPs and an analysis
2 on a state‐by‐state basis, and Entergy has
3 committed to provide that information going
4 forward with the SPP.
5 In addition to these now proposed
6 reports, 1a has a discrepancy between the
7 graph and the table, and Bruce is going to
8 get that updated. Patrick Clarey will
9 provide, excuse me, Bruce with other RTO ISO
10 reports which appear to be very similar. And
11 Commissioner Presley asked if that 1f include
12 the TLR levels for each of the flowgate that
13 is listed and asked for the cost to run
14 generation re‐dispatch to mitigate the TLR,
15 what solutions have been identified to reduce
16 the congestion and also include some 17 year‐on‐year comparative analysis.
18 Jennifer had a question on slide 1b
19 regarding the NNL levels which were
20 inconsistent with the 5A/5B levels when there
21 is a correlation between the two, and they
22 should me more in alignment, and Gary Newell
23 asked a question if that NNL is
24 representative of just what is on the Entergy
25 system, or is it the broader balancing area?
0110
1 Bruce indicated he would look into the
2 discrepancy and provide additional
3 information and how and what area the NNLs
4 are covering.
5 On the Studies Status Report, John
6 requested to include the SPP and TVA system
7 studies that impact Entergy facilities, and
8 Bruce will look into how this additional
9 information can be added.
10 And then the one formal action I
11 have from the E‐RSC to the E‐RSC Working
12 Group is the request that the ICT provide the
13 re‐dispatch cost of the TLRs, and what will
14 be required is input from the stakeholders
15 and Entergy. And the E‐RSC Working Group 16 will work with all stakeholders on this to
17 develop some type of an ongoing report for
18 the E‐RSC. We'll first look at 2009 data and
19 see the cost impact to retail consumers as
20 well as the cost to merchant transmission,
21 and will also identify what remedies are
22 underway or have ‐‐ or been planned to
23 continue to reduce these events. Entegra,
24 NRG and Entergy all committed to work with
25 the E‐RSC Working Group to provide this
0111
1 information.
2 MR. BOOTH:
3 Jennifer [sic], it's merchant
4 generation.
5 MS. SCHMIDT:
6 I'm sorry. Merchant generation,
7 not transmission. And, again, these are not
8 very articulate, but I think the point of
9 what Sam was asking for is that it give ‐‐
10 just keep people on notice right now this is
11 an oral request. The Working Group will
12 follow up with a formal request after the
13 meeting.
14 PRESIDENT SUSKIE: 15 Okay. Thank you. Did she miss
16 any? I'd be shocked if she did, it was so
17 thorough.
18 (No response.)
19 All right. With that, let's take a
20 ten‐minute break and come back.
21 (Recess.)
22 SECRETARY ANDERSON:
23 I had a request to remind everybody
24 that they need to sign in. There's a sign‐in
25 sheet, apparently, and it's making its way
0112
1 around. You need to sign in that sign‐in
2 sheet in order for the court reporter to make
3 sure that all names are recorded.
4 PRESIDENT SUSKIE:
5 Yes. So just make sure you sign
6 the sign‐in sheet, and that will also help
7 our court reporter with the names.
8 I'd like to actually go back to the
9 first item on the agenda. We forgot to put
10 on there approval of the minutes, and Ben
11 reminded me of that.
12 So do I have a motion?
13 CHAIRMAN PRESLEY: 14 I so move we approve that.
15 PRESIDENT SUSKIE:
16 Second?
17 MR. BOOTH:
18 Second.
19 PRESIDENT SUSKIE:
20 It's been seconded. All those in
21 favor of approval of minutes from our last
22 meeting, say aye.
23 (All ayes.)
24 All those opposed?
25 (No response.)
0113
1 The motion carries.
2 Next on the agenda is a report from
3 Entergy about the proposal they submitted at
4 our last meeting about Section 205 FERC
5 filing rights.
6 MR. LOUDENSLAGER:
7 Excuse me.
8 PRESIDENT SUSKIE:
9 Sorry.
10 Sam? Ben?
11 MR. BRIGHT:
12 Did you want to do the budget? I 13 think it was after Bruce's presentation on
14 ICT. We also have a budget update.
15 PRESIDENT SUSKIE:
16 I apologize.
17 MR. BRIGHT:
18 It will take just a second.
19 PRESIDENT SUSKIE:
20 Okay.
21 MR. BRIGHT:
22 What I've included here was a
23 version of the approved budget. This budget
24 was approved back on December 16th, 2009, in
25 an E‐RSC conference call, I believe. And
0114
1 then what I have here is the budget versus
2 actuals year‐to‐date. This is a ‐‐ so what
3 we're tracking as far as travel expenses,
4 meeting expenses. We haven't accrued any
5 money into our audit yet. That's later ‐‐
6 coming later in the year, but it is budgeted
7 for Patricia Salman. And then SPP
8 administrative, one thing I found out over
9 the last couple of weekst is tha we haven't
10 been real good about getting that part
11 billed, and so we're going to do a catch‐up 12 bill with Entergy on the next one and make
13 sure that stuff gets included, and, also,
14 there's some additional meeting expenses from
15 this year that need to go on there, as well.
16 And then the E‐RSC consultant, which is ESPY,
17 we got that aftere th first of the month, so
18 we'll ‐‐ that will be caught up by the next
19 update, as well.
20 PRESIDENT SUSKIE:
21 Okay. So these are as of ‐‐
22 MR. BRIGHT:
23 As of March 31st.
24 PRESIDENT SUSKIE:
25 ‐‐ March 31st.
0115
1 MR. BRIGHT:
2 Yeah.
3 PRESIDENT SUSKIE:
4 I was hoping ESPY was working for
5 free.
6 MR. BRIGHT:
7 They are so far.
8 PRESIDENT SUSKIE:
9 Okay.
10 MR. BRIGHT: 11 Does anybody have any questions
12 about the budget or that process?
13 PRESIDENT SUSKIE:
14 Any questions about the budget?
15 (No response.)
16 All right. Thank you.
17 Next, we'll go to a report from
18 Entergy about the proposal of ‐‐ from the
19 last meeting.
20 MR. CAMET:
21 Hi. My name is Greg Camet, and
22 I'm ‐‐
23 PRESIDENT SUSKIE:
24 I don't think the mic. is on.
25 MR. CAMET:
0116
1 Hi. My name is Greg Camet. I'm
2 with Entergy, and I'm going to run through
3 right now the amendments to the OATT to
4 address E‐RSC authority over construction and
5 transmission cost allocation. I believe all
6 the red lines to the actual tariff sheets
7 were distributed at the last meeting and by
8 e‐mail after that.
9 Do you want to start with the first 10 slide?
11 There are two categories of
12 amendments. The first addressed cost
13 allocation and provides that the E‐RSC can
14 direct Entergy to make a filing pursuant to
15 Section 205 to change the way transmission
16 upgrade costs are allocated. The second ‐‐
17 the second set of amendments addresses
18 construction plan, and provides the E‐RSC has
19 authority to direct Entergy to add specific
20 projects to the construction plan.
21 Getting into even more detail with
22 respect to the first one, cost allocation.
23 Cost allocation is covered by Attachment T to
24 the Entergy OATT. The high‐level revisions
25 we added there were definitions to address
0117
1 the E‐RSC, the E‐RSC Board and the E‐RSC
2 Members. And the key provision provides that
3 the E‐RSC Board may, after referral to Member
4 state agencies and upon the unanimous vote of
5 all five of the E‐RSC's directors, direct the
6 transmission provider to file, pursuant to
7 Section 205 of the Federal Power Act, changes
8 to the methodology for allocating 9 transmission upgrade costs under this
10 Attachment T.
11 PRESIDENT SUSKIE:
12 Greg, I have a question for you.
13 "After referral to Member state agencies,"
14 I'm just thinking through. You know, what is
15 Entergy's ‐‐ I'd say intent ‐‐ you know, its
16 thoughts on that? For instance, when we do
17 cost allocation voting in SPP, the rep of the
18 of the ‐‐ of each state makes the vote, but
19 it's never a formal proceeding back in the
20 state. For instance, balanced portfolio, I
21 voted in favor of on behalf of the Arkansas
22 Commission with the support of state
23 regulators, but we never had a formal
24 proceeding before the Arkansas Commission.
25 MR. CAMET:
0118
1 I think, in general, that's the
2 idea. I think the referral then comes from
3 the E‐RSC bylaws, which talk about a
4 referring ‐‐ provision that relates to policy
5 statements, how the E‐RSC can develop policy
6 statements after referring the issue to their
7 Member Commissions. And so that's where this 8 language comes from, and, in our mind, at
9 least, it's just a ‐‐ it's just a notice type
10 of requirement. It doesn't ‐‐ it doesn't
11 mean that the individual states would need a
12 formal proceeding in effect. That's
13 something the individual states would decide
14 whether they want anything or not.
15 I think, traditionally, if Entergy
16 is making a change to these provisions, we
17 would have provided notice to the state ‐‐ to
18 the states. And I think the way this is set
19 up is that that notice would now come from ‐‐
20 from the E‐RSC members, but we don't have any
21 notion about what has to happen after that or
22 what preconditions there are ‐‐
23 PRESIDENT SUSKIE:
24 Yeah.
25 MR. CAMET:
0119
1 ‐‐ for you guys to work out with
2 your individual Commissions.
3 PRESIDENT SUSKIE:
4 Commissions, yeah. I think,
5 obviously, each jurisdiction is different as
6 to what they would require. There may be 7 some things that ‐‐ items, you know, Arkansas
8 Commission may want to have a full‐fledged
9 proceeding. There may be some matters, as we
10 have done the entire time we've been a member
11 of the SPP RSC, just represented ‐‐ whether
12 it was myself, Commissioner Honorable or
13 Commissioner Hochstetter or now Byrd, you
14 know, they, with their discretion ‐‐ I think
15 Texas does that, as well, under the SPP RSC.
16 But it, obviously, reports back to the
17 Commission. I was just curious as to what
18 that meant, maybe something could be flushed
19 out.
20 MR. CAMET:
21 Right. And I think the specific
22 provision in the bylaws was Section 9.
23 MR. BOOTH:
24 To avoid confusion, so what we're
25 trying to do is accommodate the SPP bylaws ‐‐
0120
1 (Talking over one another.)
2 UNIDENTIFIED SPEAKER:
3 Microphone, please.
4 PRESIDENT SUSKIE:
5 All right. 6 MR. BOOTH:
7 If what Entergy is proposing to do
8 is to accommodate the E‐RSC bylaws, maybe the
9 simpler way to do that is to eliminate these
10 requirements to just say, E‐RSC Board of
11 Directors may, consistent with its bylaws, do
12 the following. And then to the extent that
13 there were differences between the bylaws and
14 tariff language, you won't have that
15 inconsistency. The conditions would be in
16 the bylaws. You follow what I'm saying?
17 MR. CAMET:
18 Yeah, I do see what you're saying.
19 I think, in general, I mean, that's certainly
20 something we'd be willing to consider. I
21 don't think ‐‐ I think the provision that we
22 pulled this language from relates to policy
23 statements. So the ‐‐ unless the E‐RSC
24 bylaws were changed to add this as it relates
25 to changes in methodology to a filed by
0121
1 requirement, you'd have to add something
2 there if you wanted to pick that up ‐‐ pick
3 that up that way.
4 SECRETARY ANDERSON: 5 I don't ‐‐ and it may be there. I
6 was just looking. I didn't actually see that
7 language in the bylaws. I mean, obviously,
8 it's implied, because we don't ‐‐
9 MR. CAMET:
10 Section ‐‐ I believe it's Section 9
11 on policy statements.
12 UNIDENTIFIED SPEAKER:
13 Section 1.
14 MR. LOUDENSLAGER:
15 In Section 9.
16 SECRETARY ANDERSON:
17 I'm looking at it right now.
18 MR. CAMET:
19 Yeah, this is it. The E‐RSC will
20 get direction in formation of policy
21 statements, which will then be referred to
22 Member state regulatory agencies.
23 SECRETARY ANDERSON:
24 All right.
25 MR. CAMET:
0122
1 Entergy customers. That's where
2 the referral came ‐‐ that referral language
3 came from. 4 MR. BOOTH:
5 I guess the point is, the E‐RSC
6 will do that ‐‐ each E‐RSC member would have
7 that discussion with its state Commission or
8 the City Council before reaching a conclusion
9 at the E‐RSC. So once the E‐RSC votes, there
10 shouldn't be a requirement to go back to the
11 state Commissions to then confirm the vote.
12 MR. CAMET:
13 I think that's ‐‐ I think we're in
14 agreement. I don't think this is a ‐‐ this
15 is a requirement, after the vote, to go back.
16 I think it's before the ‐‐
17 PRESIDENT SUSKIE:
18 See, I read that, the E‐RSC Board
19 of Directors will give direction and
20 formation on policy statements pursuant to
21 that section above, which will then be
22 referred to a state regulatory agency. The
23 way It see tha is, what I do with the E‐RSC
24 within SPP, I go back and notify my
25 Commissioners, you know, notify them, by the
0123
1 way, at last month's or last week's SPP
2 meeting that we voted and approved the cost 3 allocation, and they're, like, thank you for
4 the update. It's just one of the issues I
5 think we've got to resolve. Because it would
6 be odd to me to have a federal tariff tell
7 the Arkansas Commission how to conduct its
8 business.
9 MR. CAMET:
10 Right. And that wasn't our intent.
11 PRESIDENT SUSKIE:
12 Yeah.
13 MR. CAMET:
14 We're not trying to lock you guys
15 into any procedure. I think ‐‐ and maybe one
16 thing that would address our concern is
17 making sure that we're not obligatedt ‐‐ tha
18 notice, that discussion, you guys are going
19 to handle that; that's not ‐‐ that's not on
20 us.
21 PRESIDENT SUSKIE:
22 Maybe that's something we can work
23 on our words.
24 MR. CAMET:
25 Yeah.
0124
1 PRESIDENT SUSKIE: 2 And, clearly, you know, another
3 state Commission may say, I want to have a
4 full‐fledged hearing on it. That's that
5 state's prerogative. Okay.
6 MR. CAMET:
7 And then I guess the ‐‐ one other
8 point, the voting requirement, unanimous
9 voting requirement, that was also picked up
10 from the ‐‐ from the E‐RSC bylaws.
11 Next.
12 Entergy's rights under this
13 proposal. We can file our own cost
14 allocation proposal pursuant to Section 205
15 of the FPA, and this tracks a similar
16 provision in the (inaudible) SPP to file a
17 competed proposal. And then we've also
18 clarified that Entergy can oppose any aspect
19 of a filing, seek rehearing or take whatever
20 action. You know, the idea there being we'll
21 make the filing, but we still want to reserve
22 our right ton explai why we don't necessarily
23 think it's the best idea, and then FERC ‐‐
24 FERC would ultimately resolve it.
25 PRESIDENT SUSKIE:
0125 1 On that, I think that's totally
2 reasonable. Entergy should be able to
3 support or oppose the filing, just like
4 another state Commissioner or whoever can
5 oppose any Entergy filing at FERC. So my
6 opinion of that, it's very reasonable.
7 MR. CAMET:
8 Next.
9 And the second ‐‐ the second set of
10 changes relate to the construction plan, and
11 the relevant set of provisions here are in
12 Attachment K. As with Attachment T, we added
13 definitions for the various entities. One
14 set of provisions ensures thate th E‐RSC
15 Board has added, as part of the normal
16 construction plan development process, and
17 that quotes through a couple of sections,
18 Sections 6.2 and 6.4.
19 The key provision here is Section
20 6.51, which is similar to the provision on
21 transmission cost allocation, and it ‐‐ it
22 has the same "after referral to Member states
23 and upon unanimous vote of all five of the
24 E‐RSC Directors, direct the transmission
25 provider to include facilities or upgrades in 0126
1 the construction plan. And as was discussed
2 at the prior meeting, the idea here is that
3 the facilities would be added to the
4 construction plan rather than starting with
5 the ‐‐ with the ICT's base plan and then
6 coming back to the E‐RSC to get approval to
7 take anything out. And the reason for that
8 were ‐‐ are related to this ‐‐ in our view,
9 make the transmission ‐‐ make the ICT, the
10 transmission provider, and puts us in the
11 position of potentially having ‐‐ having a
12 basen pla that does include all the
13 facilities that we think are necessary to
14 meet whatever NERC standards are in effect at
15 the time.
16 And so the idea ‐‐ the idea here is
17 that the E‐RSC would have the authority to
18 add facilities to the construction plan
19 rather than change the structure between the
20 base plan and the construction plan
21 themselves.
22 PRESIDENT SUSKIE:
23 I have two questions on this one
24 again. Bullet 3 again has the referral to 25 state agencies. I guess that's the issue.
0127
1 We've got to resolve this.
2 MR. CAMET:
3 Right.
4 PRESIDENT SUSKIE:
5 You know, if there's a line in
6 Louisiana that Commissioner Field needs to
7 be ‐‐ put in to help congestion, do I need to
8 have a hearing in Arkansas about whether I
9 need that line? I think that's some of the
10 issues, you know, there ‐‐ that language
11 might need some wordsmithing.
12 Then I go back to the question I
13 asked of Kim last time is, you have the ICT
14 base plan, and then, say, Entergy comes in,
15 in which they have now what the abandonment
16 of note B says, okay, they're the same, but
17 we want to add the following projects. The
18 question then becomes, well, who's vetted
19 whether that's da goo project or not. See my
20 question on that one?
21 MS. DESPEAUX:
22 Can you ask it one more time?
23 PRESIDENT SUSKIE: 24 You need a microphone.
25 So, Kim, I want to clarify my
0128
1 question. My question is: The ICT base ‐‐
2 ICT comes up with a base plan of, say, ten
3 projects, and Entergy then comes up and says,
4 hey, we've abandoned the use ofe not B, and,
5 as a result, we're going to build those ten,
6 plus another ten. Then my question is kind
7 of, how is the process that's independent to
8 ensure those are needed, along those lines?
9 And I've been trying to think, then, at that
10 point, I guess the only authority to say
11 whether there's a need is whether that state
12 has ‐‐ the state it's being built in has
13 jurisdiction over it to even hear it and
14 whether they say there's a need for the
15 facility.
16 MS. DESPEAUX:
17 I think that's right, and if it was
18 not in the ‐‐ if it wasn't in the base plan
19 but it was in the construction plan ‐‐ so if
20 it's not in the base plan, then it would be
21 viewed as a supplemental project. And I
22 think that if there was a debate about 23 whether that was actually needed, certainly
24 FERC would be a venue, but it would also, to
25 the extent there's a licensing ‐‐ like, a
0129
1 certificate needed, we would have to come to
2 the individual retail commissions, as well.
3 PRESIDENT SUSKIE:
4 So then, on the flip side, so that
5 would be a supplemental upgrade. And then on
6 my ‐‐ say, go back to my hometown of North
7 Little Rock, if they needed some upgrades
8 made for their purposes, the cost allocation
9 today, then North Little Rock would pay for
10 it, that upgrade, but it wouldn't appear on
11 your construction plan ‐‐ no, actually, it
12 would.
13 MS. DESPEAUX:
14 It would. Yeah. If, for instance,
15 North Little Rock wanted an upgrade that the
16 ICT had not ‐‐ it wasn't in the ICT's base
17 plan, then it would be a supplemental project
18 that, if North Little Rock committed to, it
19 would go into our construction plan.
20 PRESIDENT SUSKIE:
21 Okay. Okay. So then, ultimately, 22 you could have things in the construction
23 plan not in the base plan, but it's not
24 Entergy wanted to build it; it could be NRG
25 or whoever?
0130
1 MS. DESPEAUX:
2 Yes. Today we have projects, it's
3 my understanding, that are in the
4 construction plan that aren't in the base
5 plan that really are the supplemental type
6 projects, where either the operating
7 companies or another market participant has
8 agreed to fund those.
9 PRESIDENT SUSKIE:
10 Okay. I'm just trying to think
11 through that option, how the process would
12 work.
13 Mr. Newell?
14 And, you know, and I give that as
15 an example of ‐‐ of the challenges. You
16 know, say, you know, Jimmy Field thinks the
17 line between Mississippi and Louisiana needs
18 to be, you know, built or upgraded, you know,
19 that sort of thing, so why would that need to
20 come back to the Arkansas Commission, you 21 know, along those lines, but ‐‐
22 MS. DESPEAUX:
23 And I think one of the reasons,
24 and, certainly, one of the things we were
25 focused is on that because, under the system
0131
1 agreement, 230 kV and above would be
2 equalized and could affect customers in all
3 the operating companies' jurisdictions.
4 PRESIDENT SUSKIE:
5 Clearly, the costs are ‐‐ I'm just
6 trying to think through why we need to have a
7 proceeding back in Arkansas.
8 MS. DESPEAUX:
9 Oh, I'm sorry. No. You mean ‐‐
10 you're back here on the referral language.
11 PRESIDENT SUSKIE:
12 Yeah.
13 MS. DESPEAUX:
14 I think that we definitely need to
15 work on the, ‐‐
16 PRESIDENT SUSKIE:
17 Wordsmithing.
18 MS. DESPEAUX:
19 ‐‐ yeah, wordsmithing the referral 20 language. Yeah.
21 PRESIDENT SUSKIE:
22 Mr. Newell?
23 MR. NEWELL:
24 Greg, two quick questions on this.
25 In the second to last bullet, you say the
0132
1 E‐RSC Board can direct the transmission
2 provider to include facilities in the
3 construction plan, and then in the last one,
4 it says, Entergy may oppose. If the RSC
5 proposed the addition of a facility and
6 Entergy opposed it, presumably, there would
7 be some process to figure that out. I'll get
8 to that in a second. But while whatever that
9 dispute resolution process is moving forward,
10 is the process in the construction plan and
11 being prosecuted, or is it held out of the
12 construction plan while the disagreement is
13 being resolved?
14 MR. CAMET:
15 Gary, I don't know that we really
16 gave that a lot of thought, but I can get
17 back to you on that. I think this provision
18 actually ‐‐ 6.52, I think it relates more of 19 reserving rights to the extent that this
20 issue were to come up in a specific retail
21 proceeding or a FERC proceeding. And so I
22 don't think we really addressed the issue
23 that you raise there. And, obviously, in the
24 205 filing context, you know where it's all
25 going to be resolved. It's going to be
0133
1 resolved at FERC, and the effective dates for
2 205 filings and changes to the OATT would
3 control when it goes into effect. We haven't
4 addressed that, so I'd have to get back to
5 you on that.
6 MR. NEWELL:
7 Yeah. This is ‐‐ there's two ‐‐ I
8 sort of had two discrete questions. One is,
9 where would the dispute be resolved, or,
10 actually, what's the mechanism; the second
11 is, while that process is underway, is the
12 project in the construction plan and being
13 prosecuted, or is it held back?
14 MR. CAMET:
15 Right. Those are fair questions,
16 and we'll get back.
17 MR. NEWELL: 18 Thanks.
19 MR. BOOTH:
20 Are there any circumstances that
21 you're aware of where SPP and Entergy have
22 proposed two different projects to resolve
23 the same issue, same reliability issue?
24 MR. CAMET:
25 Yeah. I'd defer to Charles on that
0134
1 one. I'm not ‐‐ I'm not sure.
2 MR. LONG:
3 There have been some occasions
4 where we proposed two different projects.
5 And, actually, the base plan and construction
6 plan this year, we were looking at a project
7 in lieu of the two different projects that we
8 had in the initial ‐‐ in the initial
9 construction plan, base plan, and after we
10 studied that a little further, we ‐‐ we went
11 back and adopted what the ICT had suggested
12 in lieu of the one we were pursuing.
13 MR. BOOTH:
14 Thank you.
15 Mr. Chairman, do you think there
16 might be circumstances where the E‐RSC would 17 want the authority to remove a project from
18 the construction plan?
19 PRESIDENT SUSKIE:
20 I mean, I guess that could always
21 happen, but if the ICT and Entergy are in
22 agreement, one of them would.
23 MR. BOOTH:
24 What if they're not? If there's
25 two competing projects, then ‐‐
0135
1 PRESIDENT SUSKIE:
2 Oh, I see what you're saying.
3 Something to consider.
4 MS. DESPEAUX:
5 I would have ‐‐ this is Kim ‐‐ and
6 in terms of removing a project from the
7 construction plan, I would have great
8 concerns about that since we are the
9 transmission provider and are the one liable
10 under the NERC standards, the reliability
11 standards in that. I think, if there was a
12 disagreement, certainly, then that would be
13 something, as we talked about earlier, that
14 may not be in the base plan that would be
15 considered a supplemental upgrade. But I 16 would ‐‐ I would have serious concerns about
17 allowing projects to be pulled out that we
18 think are needed for reliability.
19 PRESIDENT SUSKIE:
20 And would that be ironic if this
21 group wanted less transmission. But she
22 makes a good point. And I think, at that
23 point, if something like that happened,
24 that's where I think we'd probably have this
25 forum.
0136
1 MS. DESPEAUX:
2 Yes.
3 PRESIDENT SUSKIE:
4 Have a meeting on it, a lot of
5 input, and then we can have a policy
6 statement vote and say, hey, Entergy, we vote
7 unanimously ‐‐
8 MS. DESPEAUX:
9 You're overbuilding.
10 VICE‐PRESIDENT FIELD:
11 Yeah, we shouldn't build this.
12 We'd all look forward to that day.
13 CHAIRMAN PRESLEY:
14 Great timing. 15 PRESIDENT SUSKIE:
16 Any other questions from the
17 stakeholders?
18 Yes?
19 MS. KING:
20 This is Katherine King on behalf of
21 Louisiana Entergy Users Group. So under this
22 process, if the E‐RSC directs an addition to
23 the construction plan and that upgrade is not
24 included in the base plan, it's a
25 supplemental upgrade. So does there have to
0137
1 be a decision made on who's going to pay for
2 that upgrade before its added to the
3 construction plan, or how do you see that
4 working?
5 PRESIDENT SUSKIE:
6 That's a good question.
7 MR. CAMET:
8 I would think the normal ‐‐ the
9 normal cost allocation provisions under
10 Attachment T would control, but we can think
11 about that more and get back to you.
12 PRESIDENT SUSKIE:
13 That is a good question, though, 14 whether ‐‐ is it economic, or is it
15 reliability? And, of course, a lot of people
16 say there's not much difference between the
17 two, but...
18 SECRETARY ANDERSON:
19 I think that really is an issue
20 that we'll be discussing when we get into
21 cost allocation, I guess, in May.
22 PRESIDENT SUSKIE:
23 Yeah, absolutely.
24 VICE‐PRESIDENT FIELD:
25 At this stage, I think we build it;
0138
1 the electrons will come.
2 PRESIDENT SUSKIE:
3 Any other questions?
4 (No response.)
5 All right. Thank you very much.
6 MR. CAMET:
7 Thanks.
8 PRESIDENT SUSKIE:
9 And I figure this ‐‐ we'll probably
10 get into this with the next section. This
11 will be a type deal that we will address at
12 our May meeting, and one thing I would like 13 to ask Entergy and the Working Group to work
14 on the language issue about the referral back
15 to the state Commission, maybe, whatever that
16 state or jurisdiction considered, New
17 Orleans, their procedure would be. So, you
18 know, obviously, you know, we could vote on a
19 base plan ‐‐ or a conduction plan and say,
20 hey, we agree with it; go forth and do great
21 things. Well, it's still got to go to the
22 Louisiana Commission, where it's being built,
23 or Arkansas Commission, depending on if the
24 state must approve it and chooses to approve
25 it.
0139
1 All right. Thank you.
2 So if you could add that to an
3 action item. Thank you.
4 Sam?
5 MR. LOUDENSLAGER:
6 Sam Loudenslager, Arkansas. Yeah.
7 I just want to make sure that the E‐RSC
8 understands that the Working Group is also
9 working on tariff language, and one of the
10 issues that we're ‐‐ we haven't started
11 really discussing in earnest yet is the issue 12 of exactly how much ‐‐ "authority" may be the
13 right word; I'm not sure ‐‐ that the E‐RSC
14 would like to have. And as we kind of work
15 through that at the Working Group level,
16 we'll certainly be bringing that back to you
17 guys in May,t and tha discussion will also
18 include, not just the Working Group, but
19 stakeholders, as well. And it's my intent,
20 anyway, to bring that to you guys in May.
21 So I don't know if this is a good
22 time or not, Chairman, but if y'all want to
23 start having that conversation this morning,
24 I'd look forward to any input that y'all
25 could provide us with.
0140
1 PRESIDENT SUSKIE:
2 Let's start and ask Entergy, is
3 there any other authority that y'all could
4 foresee that would be reasonable for the
5 E‐RSC to have?
6 MS. DESPEAUX:
7 I will say these are the two items
8 that we heard, you know, early on, and
9 that ‐‐ so these are the two that we focused
10 on, and we haven't identified anything 11 additional to this point. We're willing to,
12 you know, certainly listen, but, at this
13 point, we haven't identified ‐‐ we thought
14 these two covered the fundamental issues that
15 we'd have discussions about.
16 PRESIDENT SUSKIE:
17 But, you know, I go back to some of
18 the conversations where some of the criticism
19 of the ICT was that it was not doing enough
20 in regards to tariff language filing and so
21 forth, and I'm wondering if the E‐RSC could
22 be a good vehicle to address some of those
23 items.
24 Do you have any thoughts on that,
25 Bruce?
0141
1 MR. REW:
2 No. I mean, that's consistent with
3 what we were thinking, you know, your
4 comments.
5 PRESIDENT SUSKIE:
6 Because I know ‐‐ I believe it was
7 SPP's ‐‐ or the ICT's recommendation that
8 y'all did not want 205 filing rights.
9 MR. REW: 10 That's correct. The ICT did not
11 think it's appropriate for us to have 205
12 filing rights.
13 PRESIDENT SUSKIE:
14 And, as a result, y'all thought we
15 should have the 205 filing rights.
16 MR. REW:
17 There's a recommendation for that,
18 and we supported that.
19 PRESIDENT SUSKIE:
20 And then, in y'all's thought, 205
21 filing rights, to what extent do you think
22 those rights should be? Should they just be
23 these two items, or should they be broader?
24 MR. REW:
25 I think we're probably neutral on
0142
1 that.t I can' give a specific answer on
2 that, but it's probably neutral. It's up to
3 the E‐RSC ‐‐
4 PRESIDENT SUSKIE:
5 Sure.
6 MR. REW:
7 ‐‐ to make a decision on that.
8 PRESIDENT SUSKIE: 9 I would ask that, as the ICT, if
10 you could, you know, offer some input to the
11 Working Group to think ‐‐ and even
12 stakeholders, hey, these are issues that we
13 want changed with the tariff that haven't
14 been done or should have ‐‐ need to be done
15 to help remedy some problem with this
16 process. And then, as a result, the
17 stakeholders can even provide and say, these
18 are the type things we look like have a
19 vehicle to the E‐RSC. So there's a concern
20 about the tariff; a stakeholder can raise it.
21 Then, at that point, the level would have to
22 be ‐‐ assuming, you know, that we would have
23 these additional filing rights, you'd have to
24 unanimously have the E‐RSC say, hey, we
25 support this change to the tariff, and then
0143
1 Entergy would file at FERC, and if Entergy
2 disagreed with that, they could obviously
3 oppose it or do other things. And I don't
4 know what that is. I just offer that out.
5 Before we go to this, don't want to limit too
6 much. Because correct my recollection, but
7 there ‐‐ some of the stakeholders have been 8 critical that the ICT has not filed things at
9 FERC; is that correct? I see heads nodding
10 in the room. So I'll offer that.
11 MS. DESPEAUX:
12 Can I just ‐‐ that was ‐‐ we
13 actually said over the longer term that we
14 certainly would be willing to have the ICT
15 become the transmission provider, and that's
16 what happens when they have filing rights,
17 and we're certainly ‐‐ we felt like that the
18 appropriate time to look at that was after we
19 knew whether we were going to the RTO versus
20 the staying with the modified ICT over the
21 longer term. But we certainly indicated we'd
22 be willing to consider having the ICT be the
23 transmission provider, which means they would
24 have the 205 rights and the tariff. I mean,
25 the tariff would be theirs.
0144
1 PRESIDENT SUSKIE:
2 Just a thought. I throw that out
3 there. As we develop what's going to be
4 filed at FERC for an enhanced ICT, that, you
5 know, maybe we should ‐‐ don't limit
6 ourselves if it's needed. 7 Sam, did you have a question?
8 MR. LOUDENSLAGER:
9 No. I was just going to provide
10 you guys with a little more information on
11 what things, at least, have been tossed out
12 in terms of filing rights. Okay? And I
13 don't know if that's helpful for you today or
14 not, so...
15 PRESIDENT SUSKIE:
16 Sure.
17 MR. LOUDENSLAGER:
18 One way to approach it would be
19 filing rights on all matters related to the
20 ICT, everything. One would be similar to the
21 same rights that the SPP RSC has right now on
22 fairly narrow areas that, not insignificant,
23 but certainly not as broad as the previous
24 approach. Filing rights related to all
25 matters tied to the ICT and matters related
0145
1 to cost allocation and participant funding
2 and rights on all Entergy OATT matters.
3 So, I mean, literally, we're
4 running the gamut. That's kind of the stream
5 right now. So a lot of what you'll be 6 hearing me say today is, if you have guidance
7 to provide us with, do so now. I mean, we'll
8 certainly bring something back to you. As
9 much as we can get accomplished between now
10 and May, I think we're all better off, so
11 that's my pitch.
12 PRESIDENT SUSKIE:
13 My advice would be stakeholders
14 present that to y'all and if any individual
15 Commissioner has an idea of additional
16 possible filing rights under this, to submit
17 it to the Working Group, as well.
18 MR. LOUDENSLAGER:
19 Okay.
20 CHAIRMAN PRESLEY:
21 Sam, has there been any ‐‐ when you
22 discussed 205 rights on all matters related
23 to the ICT, is there a push‐back by that
24 or ‐‐
25 MR. LOUDENSLAGER:
0146
1 We hadn't even made the pitch
2 publicly. This is ‐‐ this is breaking news.
3 I mean, this is just kind of ‐‐ the Working
4 Group has just ‐‐ we've gotten it tossed out 5 in front of us, and we're trying to figure
6 out what direction to go. And my desire was
7 to hope that we'd hear some feedback from you
8 folks on what direction you'd like for us to
9 go. You know, if broader is better, we'll
10 start broader. If narrower is better, we'll
11 start narrower. And I think I know the
12 answer to that question, but...
13 PRESIDENT SUSKIE:
14 Okay. Any other questions,
15 comments on the 205 issue?
16 (No response.)
17 All right. Thank you very much for
18 that presentation. Next, we'll go to the
19 Working Group.
20 Sam or Kristine?
21 MR. LOUDENSLAGER:
22 Yeah. I'm going to hand it off to
23 Kristine to talk about state siting issues.
24 MS. SCHMIDT:
25 This is Kristine Schmidt with ESPY
0147
1 Energy Solutions. And one of the issues that
2 came up in the last meeting was the question
3 of what are the different state 4 jurisdictional requirements for siting new
5 transmission or upgrades in the respective
6 states. Everybody had a sense of what was
7 going on in their own state, but they wanted
8 a broader perspective. So working with the
9 Commission Staff members that were
10 identified, this presentation ‐‐
11 Ben, if you can go to the second
12 page.
13 We're going to start with
14 Louisiana, because it's the simplest. There
15 is a regulatory authority and a siting
16 approval process, a certification process;
17 however, Louisiana, to date, has not
18 exercised that authority. Now, there's an
19 open docket in Louisiana right now reviewing
20 merchant transmission, construction and
21 ownership. And this may change going
22 forward, but, to date, again, there has not
23 been a certification process that has been
24 formalized that the Louisiana Service ‐‐
25 Public Service Commission has pursued. So in
0148
1 terms of regulatory barriers, there are very
2 few in Louisiana as a state. 3 Questions?
4 SECRETARY ANDERSON:
5 Who determines, then, where the
6 line goes?
7 VICE‐PRESIDENT FIELD:
8 Entergy, usually, or CLECO, they'll
9 come in and tell us they want to build it,
10 and we're so glad to get it. We're just both
11 ready to go. I don't think we've ever turned
12 down any.
13 SECRETARY ANDERSON:
14 Okay.
15 PRESIDENT SUSKIE:
16 So those delays are not your fault.
17 VICE‐PRESIDENT FIELD:
18 Not our fault.
19 MS. SCHMIDT:
20 The review is actually when they
21 put it in rate base.
22 Going to the next page, the City of
23 New Orleans. And there haven't been a whole
24 lot of transmission upgrades; however, they
25 do have the process in place.
0149
1 And I apologize. I need to give 2 credit to the folks that worked on this.
3 Paul Zimmering was the one who provided us
4 the Louisiana. And Jeff Wilkerson ‐‐
5 Wilkinson, rather, provided us with
6 information on New Orleans and identified
7 that the transmission would be determined 60
8 kV and higher, and it require a Certificate
9 of Public Need and Convenience, and the City
10 Council would actually have to approve it.
11 And, generally, and in broad brushes, the
12 allocation considers load‐serving needs,
13 environmental impact, economic impact and
14 reliability. And there is a requirement that
15 they actually have to rule within one year;
16 however, depending on the size of the
17 project, that they would anticipate that that
18 may take a little longer time, so for good
19 cause, they will extend their deadline.
20 Moving on to Mississippi. And
21 Vernon Jones helped us on this one. And,
22 generally, the transmission lines are defined
23 as 115 kV and higher; however, there have
24 been occasions where 69 kV lines could be
25 deemed transmission, either for upgrades or
0150 1 for new transmission. And Facilities
2 Certificates are required for these projects.
3 And, again, the same type of ‐‐ the
4 application considers load‐serving needs,
5 environmental impact, economic impact and
6 reliability; however, there are no deadlines
7 that are in place; however, Mississippi could
8 impose some deadlines if they wanted to as
9 the Commission tried to move things forward,
10 but it is up to them as to how they want to
11 proceed with it.
12 Moving on to the next page. In
13 Arkansas, Lori Burrows was helpful on this
14 one for us. There are two types of projects.
15 The major project are anything that are 100
16 kV and higher and they are longer than
17 10 miles in distance, or they're 170 kV and
18 more than one mile in distance. And, again,
19 the Certificate of Environmental Capability
20 and Public Need is required for those types
21 of major projects. For smaller projects, a
22 Certificate of Convenience & Necessity is
23 also required. Again, similar types of
24 considerations are made in evaluations that
25 are made for the applications. Again, no 0151
1 deadline here in Arkansas, but, again, the
2 Public Service Commission could actually pose
3 or try to move something in a time frame
4 depending on what kind of flexibility they
5 wanted to put in place and what kind of
6 review they wanted to have in place.
7 And, finally, Texas. And this is a
8 little bit more complicated. There are two
9 parts to the Texas transmission siting
10 process. And Brian Almond was, again, very
11 helpful to us on this one. Transmission
12 projects are major projects that are 60 kV
13 and higher. And what's required is a
14 Certificate of Convenience & Necessity. And
15 they are actually more granular in terms of
16 what they look for in their applications,
17 including some of the renewable objectives in
18 the state, as well as some constraints,
19 costs, et cetera. There are no deadlines for
20 these ‐‐ for the normal types of projects
21 that go through, and the Texas Commission
22 does approve these.
23 And if you'd flip to the next page,
24 the more challenging one ‐‐ transmission 25 siting projects are those that are under the
0152
1 CREZ, and those are the newer ones that are
2 actually the competitive renewable energy
3 zones that the State of Texas has identified
4 and has actually laid out. So transmission
5 projects that are 60kV and higher that are
6 accessing those CREZ zones would have to go
7 through this process, and a Certificate of
8 Convenience & Necessity is required.
9 Considers the same issues that the other new
10 lines would consider; however, the biggest
11 distinction here is that the rulings have to
12 be made within 100 days ‐‐ 180 days, and if
13 there is no decision, then there is an
14 approval that goes into effect by operation
15 of law. So the CREZ zoning ‐‐ I'm sorry ‐‐
16 the CREZ siting is much more stringent than
17 the normal types of siting that's in place.
18 So those ‐‐ that's basically our
19 summary. In the ‐‐ in our packet and also
20 posted on the Web site is a matrix that
21 provides a little bit more description and
22 details. I ‐‐ you know, one of the issues is
23 always, you know, how much is transmission 24 siting a barrier to transmission, and, quite
25 frankly, given the process that's out here
0153
1 and that's been laid out, you don't see
2 anything that's abnormal to transmission
3 siting that you may see in other states and
4 other regions. Back to, you know, like we
5 were saying earlier, Louisiana is probably
6 the easiest place to get your transmission
7 cited.
8 So any questions or follow‐up
9 issues that you'd like us to take on?
10 PRESIDENT SUSKIE:
11 Any questions?
12 (No response.)
13 Very, very helpful. And I notice
14 that you point out how the Arkansas
15 Commission is looking at transmission riders
16 currently.
17 MS. SCHMIDT:
18 Absolutely. And I think all the
19 Commissions are taking some form of looking
20 at some alternatives. I think the
21 interesting one in particular is merchant
22 transmission. To the extent that a 23 transmission line is determined to be needed
24 in some functionality, whether it's through
25 the SPP or some other entity determines or ‐‐
0154
1 you know, the example earlier, North Little
2 Rock. If they want to build their own, the
3 question then becomes could somebody else
4 come in and build it and then turn over the
5 operation and control of it to another
6 entity. So I believe Arkansas, you have
7 something in your statutes that allow for
8 merchant transmission, but it's really
9 narrowly defined and probably not best
10 defined. And then, in Louisiana, of course,
11 they have that open docket looking at
12 merchant transmission. So there could be a
13 opportunity for looking at alternative ways
14 of getting transmission than just the
15 traditional ways.
16 PRESIDENT SUSKIE:
17 Any other questions? Stakeholders?
18 Ms. Burrows?
19 MR. WILSON: Dave Wilson. If a
20 stakeholder or group of stakeholders thought,
21 as an example, the Arkansas methodology ought 22 to be the same as Louisiana, is the E‐RSC
23 Working Group the forum for that sort of
24 discussion, or should we just go the normal
25 political process?
0155
1 PRESIDENT SUSKIE:
2 Say that again. What's the
3 question?
4 MR. WILSON:
5 If a stakeholder, as an example, in
6 Arkansas thought that the Arkansas siting
7 methodology ought to be as simple as the
8 Louisiana siting methodology, would the E‐RSC
9 Working Group be a foreman to talk about
10 that ‐‐ forum to talk about that, or should
11 that stakeholder proceed in the normal
12 political process?
13 PRESIDENT SUSKIE:
14 I mean, at least, from Arkansas, we
15 could certainly discuss it here, but I think,
16 ultimately, that's our legislature's
17 decision, and, you know, the Commission's
18 decision.
19 MR. WILSON:
20 Well, I dagree. An I didn't ‐‐ I'm 21 not so sure I agreed with the
22 characterization of the status of things in
23 Arkansas, but ‐‐ thank you very much.
24 PRESIDENT SUSKIE:
25 Sure. I mean, so when you say,
0156
1 "discussion," what's the thought? To bring
2 something here in the forum that should align
3 them or keep them similar?
4 MR. WILSON:
5 Get rid of that CECPN, to begin
6 with, from 1973.
7 PRESIDENT SUSKIE:
8 I think the Arkansas Supreme Court
9 is reviewing that right now about a Turk
10 plant in southwest Arkansas. It's funny.
11 We've been planning a briefing on CECP and
12 statute which, for those that ‐‐ in the room,
13 the Arkansas Supreme Court is currently
14 hearing the appeal from the Turk plant, and
15 so we decided to put off that briefing until
16 we see what the Supreme Court tells us it
17 says. It's a good point.
18 MS. BURROWS:
19 I just wanted to clarify. This is 20 my mistake, Kristine, for not catching it
21 when I reviewed this. You sent it to me
22 before. For the CECPN, which you were
23 referring to, that law does actually have a
24 timing issue. It used to be 90 days the
25 Commission had to commence a hearing. Now
0157
1 it's 180 days on any application, and then
2 they have to issue a decision 60 days after
3 the hearing concludes; however, unlike Texas
4 and the CREZ regions, if the Commission
5 doesn't follow that, it doesn't automatically
6 grant the CECPN application. And I'd be more
7 than happy to talk to you about the CECPN
8 law, as the attorney arguing that at the
9 Supreme Court, so...
10 MS. SCHMIDT:
11 What I'll do is, I'll update that,
12 and we'll get that re‐posted on the Web site
13 ‐‐ the SPP Web site with that.
14 SECRETARY ANDERSON:
15 One note in your chart about the
16 timing for rate base is that, in Texas, once
17 a line is energized, it's conditional. It's
18 conditionally put into rates. In other 19 words ‐‐ in other words, every year ‐‐ every
20 year, all new additions are added into rates
21 immediately. They don't have to come in for
22 a separate proceeding in order to get ‐‐ you
23 don't have a prudence review on the cost
24 before it goes into rate base.
25 MS. SCHMIDT:
0158
1 Is that because of the formula
2 rates that are in place?
3 SECRETARY ANDERSON:
4 I'm sorry?
5 MS. SCHMIDT:
6 Is that because there's a formula
7 rate in place or ‐‐
8 SECRETARY ANDERSON:
9 Yes.
10 MS. SCHMIDT:
11 Okay. I'll make that correction,
12 too.
13 SECRETARY ANDERSON:
14 And, ultimately, the prudence issue
15 and other issues are ‐‐ it's all reconciled
16 in a rate case when they come in for a rate
17 case. But in the meantime, it goes in. 18 MS. SCHMIDT:
19 Okay. I'll make that correction.
20 Thank you.
21 PRESIDENT SUSKIE:
22 All right. Any other questions,
23 comments?
24 (No response.)
25 All right. Next?
0159
1 MR. LOUDENSLAGER:
2 Ten minutes before lunch.
3 PRESIDENT SUSKIE:
4 So can you bite off onec topi in
5 ten minutes, or do we need to break for
6 lunch?
7 MR. LOUDENSLAGER:
8 I think I can. After our last ‐‐
9 after the last E‐RSC meeting, it occurred to
10 me that the ‐‐ it would probably be a good
11 idea to begin to gather on a very regular
12 basis the E‐RSC Working Group and also gather
13 together with the stakeholders on a very
14 regular basis. So what we've done is, we've
15 established a series of dates on the calendar
16 where we will be meeting, and because of 17 something that happened yesterday, I'm going
18 to ask for input from the stakeholders,
19 not ‐‐ just come up to me later, and we can
20 talk about it, but...
21 So after the March meeting of the
22 E‐RSC, the Working Group met on April the ‐‐
23 I can't read that ‐‐ the 7th and then ‐‐
24 behind closed doors just to kind of gather
25 our thoughts and start going through some of
0160
1 the additional enhancements and talking about
2 the initial set of enhancements. Then, on
3 the 8th, we met with the stakeholders, and I
4 think both days were very productive
5 meetings. They were from my perspective,
6 anyway. And so the way the schedule works
7 is, within a ‐‐ probably about two weeks
8 prior to the next scheduled E‐RSC meeting,
9 the Working Group and the stakeholders will
10 gather to meet. Because we're on such a fast
11 track, we're trying to get a lot of work
12 done. That gives us a couple of weeks to try
13 to finalize work product for you folks and
14 get it to you in a timelye basis befor the
15 next face‐to‐face meeting. And so our next 16 face‐to‐face meeting is next Thursday and
17 Friday in Dallas. After that, we meet again
18 face‐to‐face on May the ‐‐
19 MR. BRIGHT:
20 17th.
21 MR. LOUDENSLAGER:
22 ‐‐ 17th and 18th. I anticipate ‐‐
23 the Arkansas Commission set a hearing for the
24 17th that I am ‐‐ expect that a number of
25 the stakeholders will be in attendance. So
0161
1 if the stakeholders would like to consider
2 moving that face‐to‐face from Dallas to
3 Little Rock, let me know during the lunch
4 hour so we can get that sorted out before
5 close of business today. And then we have
6 another face‐to‐face in ‐‐
7 Ben, do we have another one after
8 the one in May?
9 MR. BRIGHT:
10 No.
11 MR. LOUDENSLAGER:
12 Okay. So you say, okay, so what?
13 Well, every Friday in those weeks where we're
14 not meeting with you folks or meeting 15 together face‐to‐face, we have a conference
16 call just to try to make sure that everybody
17 is on track with whatever tasks they have.
18 And that's closed for the Working Group
19 members only.
20 So my point is, we're trying to get
21 active participation by all the stakeholders
22 in face‐to‐face settings. My experience has
23 been is that always works out a lot better in
24 terms of building relationships. And the
25 other thing, at our first face‐to‐face, we
0162
1 had very good attendance from all the
2 stakeholders. Entergy was there and was very
3 helpful.
4 At our next face‐to‐face, one of
5 the topics that we're going to start trying
6 to get a better handle on is how Entergy
7 defines and how they evaluate the topic of
8 their flexible needs. Another topic that
9 we've got teed up for face‐to‐face is
10 probably going to be the weekly procurement
11 process. I'm ‐‐ personally, I'm still
12 struggling with that process, and it's my
13 understanding that it has been modified a 14 little bit to include automatic generation
15 control as part of it, and I just need to
16 better understand that. But I'm sure the
17 rest of the Working Group would find that
18 helpful, as well.
19 So, administratively, that's kind
20 of the way things are going. At our last
21 face‐to‐face, the Working Group put together
22 a series of data requests to Entergy to
23 specific ‐‐ and to other specific
24 stakeholders and had asked for a responsive
25 and very quick turnaround, and for the most
0163
1 part, that happened. Ourn pla is to ‐‐ to
2 the extent that the responses aren't ‐‐ don't
3 include any confidential information, our
4 intent is to paste those responses on the Web
5 site so that everybody has access to the
6 responses.
7 Let's see. Okay. So that's kind
8 of where the ‐‐ how the Work Group is moving
9 forward with the stakeholders and welcome any
10 suggestions or questions that you might have.
11 You can stop me in the hall, too, today.
12 PRESIDENT SUSKIE: 13 I'd like to ask questions of the
14 stakeholders, your thoughts on how those
15 face‐to‐face discussions are going with the
16 Working Group.
17 Jennifer?
18 I'm shocked. She's got a question
19 or a comment.
20 MS. VOSBURG:
21 The meetings that we had so far
22 have been very good, and, you know, I know
23 the last one probably had a little less
24 participation just because of the very short
25 notice to get over there. I know I've asked
0164
1 before ‐‐ there are times we just can't get
2 there, that if we could have the materials,
3 it would help the discussion, especially with
4 the people on the phone. I agree with Sam.
5 It's always best to be there in person. We
6 do our best, but for those who just can't
7 make it, that would be best. But I think
8 they're going good. We're trying not to have
9 meeting fatigue. The more that we can set
10 them up in kind of conjunction with meetings,
11 like you're doing with the Arkansas hearing 12 and the ITC meetings, the better off we'll
13 be.
14 PRESIDENT SUSKIE:
15 And then about the WebEx, Ben could
16 you check into that?
17 MR. BRIGHT:
18 I will.
19 PRESIDENT SUSKIE:
20 Okay. Thanks.
21 MR. LOUDENSLAGER:
22 As somebody that attends a lot of
23 meetings, as Paul will attest ‐‐ I attend
24 them in person and ‐‐ because when I try to
25 do them over the phone, it is ‐‐ it is
0165
1 impossible. And I appreciate a comment I
2 heard from a wise man named Ricky Bittle
3 once, who said,t if you can' hear, you should
4 have been here, so...
5 PRESIDENT SUSKIE:
6 That sounds like Ricky.
7 MR. LOUDENSLAGER:
8 Comments from other stakeholders?
9 PRESIDENT SUSKIE:
10 Anybody else? 11 Kim?
12 MS. DESPEAUX:
13 I will just say that we actually
14 found the Working Group very helpful in terms
15 of being able to have ‐‐ you know, understand
16 better some of the issues and maybe better
17 articulate some of our issues so that people
18 understood them. And, also, it's helpful in
19 terms of figuring out what's going to be
20 coming up at this Commission so we can be
21 better ‐‐ or at this meeting so that we can
22 be better prepared, so we very much
23 appreciate being included in those
24 discussions.
25 PRESIDENT SUSKIE:
0166
1 Any others?
2 (No response.)
3 Any Commissioners?
4 Jimmy?
5 VICE‐PRESIDENT FIELD:
6 I just wanted to mention, although
7 we passed over the transmission issue, we are
8 really concerned about transmission. We are
9 talking to Entergy and CLECO about the 10 possible transmission rider or some way to
11 ensure them that they get great recovery for
12 any investments in transmission. So I just
13 wanted to let everybody know that.
14 MR. LOUDENSLAGER:
15 Thank you.
16 PRESIDENT SUSKIE:
17 Anything else?
18 (No response.)
19 One thing ‐‐ since we're talking
20 about meeting times, we'll talk about this at
21 the end. A couple of the Commissioners have
22 brought up that, currently, we're planning in
23 July a meeting in Houston when the SPC meets.
24 That's the same week as NARUC, and it would
25 be somewhat problematic going there ‐‐ from
0167
1 Sacramento to Houston. So one thing we're
2 considering ‐‐ we'll probably talk about it
3 at lunch or so forth ‐‐ is not having that
4 meeting in July, considering that, two weeks
5 later, we have the Annual Transmission
6 Summit. We may not meet in July; instead,
7 have the Transmission Summit. Just something
8 to throw out to think about, so... 9 Any other questions for Sam on that
10 topic?
11 (No response.)
12 My stomach is telling me I'm
13 hungry, so let's break for lunch. And, Ben,
14 if I'm correct, lunch is right next door.
15 MR. LOUDENSLAGER:
16 When do we regather?
17 PRESIDENT SUSKIE:
18 .1 o'clock
19 MR. LOUDENSLAGER:
20 Thank you.
21 PRESIDENT SUSKIE:
22 1 o'clock.
23 (Recess.)
24 PRESIDENT SUSKIE:
25 We'll continue with item No. 7 on
0168
1 the agenda, Sam Loudenslager with the E‐RSC
2 Working Group.
3 I see him looking for a microphone.
4 MR. LOUDENSLAGER:
5 Before I go through the
6 presentation ‐‐ and for the folks in the
7 room, you don't have my presentation. It 8 will be posted sometime today or tomorrow.
9 But at the last E‐RSC meeting, there were a
10 couple of questions that the Commissioners
11 asked, and I just wanted to go over the
12 responses that we got.
13 This first one, I think,
14 Commissioner Field asked, and y'all will have
15 to look on the screen. And the question was:
16 Have you ever refunded moneys to someone
17 that's upgraded on the system; and, if so,
18 when and to whom? I got this response last
19 night, so I haven't spent much time with it.
20 I can read it to you.
21 "Entergy's understanding is that
22 this question asks whether Entergy has
23 provided financial compensation under
24 Attachment T to the Entergy OATT to
25 third‐party transmission customers for
0169
1 supplemental upgrades that are later
2 determined to be necessary to grant new
3 transmission service or maintain reliability
4 and existing service. Since the ICT went
5 into effect in November of 2006, three sets
6 of supplemental upgrades have been funded by 7 third parties. Two of the three sets of
8 upgrades are currently being constructed and
9 are not in‐service and, therefore, are not
10 eligible yet for financial rights payments.
11 While a portion of the third set of upgrades
12 is in‐service, no payments of financial
13 rights have been made to this point."
14 So, Commissioner Field, I think
15 that was responsive to your question.
16 VICE‐PRESIDENT FIELD:
17 It is. No payment has been made.
18 MR. LOUDENSLAGER:
19 The reason I'm going over these
20 two, in particular, since y'all asked for it,
21 if y'all have got any follow‐up.
22 PRESIDENT SUSKIE:
23 I've got a follow‐up. So ‐‐ and I
24 know supplemental upgrades fall under
25 Attachment T; am I correct there? There's
0170
1 been a lot of issues where stakeholders ‐‐
2 and I know they did ‐‐ stated it in the
3 Arkansas docket that's going to go to the
4 cost allocation questions ‐‐ but that,
5 essentially, what's been said by some, there 6 have been no upgrades under Attachment T, and
7 I know there's obviously been three based
8 upon the response. Who did those three
9 upgrades? Who paid for those, I guess ‐‐
10 paid those, or whose projects were they?
11 MS. DESPEAUX:
12 Wait. Greg, do you know? Okay.
13 Wait. I'll pass it to Greg.
14 The other thing I wanted to point
15 out is the Entergy operating companies have
16 also done supplemental upgrades, but we
17 understood Commissioner Field to be focused
18 on the third parties who have done it, but
19 I'll pass it to Greg.
20 PRESIDENT SUSKIE:
21 But when you look at supplemental
22 upgrades to about 230, that's really the
23 system.
24 MS. DESPEAUX:
25 Yeah.
0171
1 PRESIDENT SUSKIE:
2 And so it's really still Entergy.
3 MS. DESPEAUX:
4 It's the supplemental upgrades that 5 operating companies fallen above 230, yes.
6 PRESIDENT SUSKIE:
7 Yeah. And then, below that, it's
8 each state.
9 MS. DESPEAUX:
10 It's the individual operating
11 company, yeah. The wholesale customers ‐‐
12 well, the transmission customers, it does not
13 go into the open access transmission tariff,
14 so they don't pick up those costs. But
15 here's Greg.
16 MR. CAMET:
17 And I believe that it was TVA, the
18 second set was OGE Aquila, and Westar was the
19 third. And these were the ones that were
20 identified in the SEARUC presentation. Those
21 were the three third‐party customers as to
22 upgrades. TVA did one set, OGE Aquila did
23 the second set, and then the third was
24 Westar.
25 PRESIDENT SUSKIE:
0172
1 Where were those, out of curiosity?
2 I assume TVA was probably Mississippi or ‐‐
3 MR. LONG: 4 I think it's ‐‐ and this is by
5 memory, but it's noted in the construction
6 plan, but I believe the OGE Aquilas were in
7 Arkansas, the TVA was in Mississippi, and
8 Westar ‐‐ I don't remember where Westar is.
9 But if you look ate th construction plan,
10 there are some projects that have those names
11 in there you can see.
12 PRESIDENT SUSKIE:
13 Thank you.
14 VICE‐PRESIDENT FIELD:
15 I guess my follow‐up question would
16 be, so why haven't payments been made to the
17 one that has completed and is in‐service?
18 MS. DESPEAUX:
19 I think generally, Commissioner,
20 the payments are made when those upgrades are
21 not just needed to serve that customer, but,
22 also, they actually get money when an upgrade
23 is needed to either serve low growth or for
24 reliability purposes. So they haven't yet
25 been determined to be required to serve low
0173
1 growth or reliability yet.
2 VICE‐PRESIDENT FIELD: 3 I see. And whose system is
4 complete?
5 MS. DESPEAUX:
6 Greg, do you remember?
7 VICE‐PRESIDENT FIELD:
8 Which transmission project?
9 MS. DESPEAUX:
10 Is it ‐‐
11 MR. CAMET:
12 Well, none of them are complete.
13 This is Greg Camet for Entergy.e Th third
14 set, a portion of those upgrades have been
15 placed in‐service, but that full set is not
16 complete, my understanding is. And that is
17 TVA.
18 SECRETARY ANDERSON:
19 And who makes that determination of
20 when it's needed for reliability or ICT?
21E VIC ‐PRESIDENT FIELD:
22 What size projects are these? If
23 you could just give us an idea. Are these
24 large projects or just short?
25 MR. LONG:
0174
1 They're a mix. I think the ‐‐ each 2 of the projects had multiple pieces to them.
3 So from that respect, they were not just one
4 line. They were ‐‐ I think the TVA was
5 actually two lines. Westar was two or three,
6 and then the OGE and the Aquila were several,
7 five or six. So they were a pretty good
8 scope, many millions of dollars.
9 PRESIDENT SUSKIE:
10 What size were the lines? That's
11 in capacity.
12 MR. LONG:
13 As far as the capacity in
14 megawatts?
15 PRESIDENT SUSKIE:
16 KV.
17 MR. LONG:
18 eOh, kV. Th ones in Arkansas, I
19 believe, were primarily 161; and the ones in
20 Mississippi were 115 kV; and, again, I can't
21 remember exactly what the Westar grades were
22 to tell you.
23 PRESIDENT SUSKIE:
24 Jody?
25 MR. HOLLAND:
0175 1 Yes. I concur with what Charles
2 says, that they're all 115, 161 upgrades.
3 There are some capacitor banks, switches,
4 pretty sizeable upgrades.
5 CHAIRMAN PRESLEY:
6 Where specifically in Mississippi
7 were the TVA upgrades?
8 MR. LONG:
9 They were on the south Jackson to
10 Florence 115 line, which is south of Jackson,
11 and Morton to Tallahatchie 115 line, which
12 is, again, south of Jackson, kind of heading
13 in towards the southern area.
14 CHAIRMAN PRESLEY:
15 South Jackson to Florence, Morton
16 to Tallahatchie?
17 MR. LONG:
18 Yes, sir.
19 MR. LOUDENSLAGER:
20 Jody, do you remember where the
21 Westar facility was located?
22 MR. HOLLAND:
23 I thought it was in Arkansas. I'm
24 trying to confirm.
25 MR. LOUDENSLAGER: 0176
1 Okay. All right.
2 MR. HOLLAND:
3 I'll get that as an answer.
4 MR. LOUDENSLAGER:
5 So not hearing any follow‐up
6 questions for us to try to ‐‐ okay.
7 PRESIDENT SUSKIE:
8 We've got a question in the back.
9 MR. DODSON:
10 Terry Dodson with Cottonwood. I
11 just have a question for Entergy. Were any
12 or all of these upgrades in Attachment T
13 associated with transmission service
14 requests; and if so, what were the synchs for
15 those requests?
16 MR. LONG:
17 I don't ‐‐ I don't know the sources
18 of the synchs. We typically just get the
19 facility studies as far as what needs to be
20 upgraded, but I don't pay any attention to
21 where the sources of the synchs were. I'm
22 sure there's a facility study out there for
23 them. I think one was an affected system
24 study, as well, so... 25 MS. DESPEAUX:
0177
1 Somebody else. We can find out.
2 PRESIDENT SUSKIE:
3 Is there any way we could make that
4 a ‐‐
5 MR. LOUDENSLAGER:
6 Is that a question for the ICT?
7 This is Sam Loudenslager.
8 MR. LONG:
9 Yeah. I think the ICT would most
10 likely have that data.
11 PRESIDENT SUSKIE:
12 If you could action‐item the answer
13 to that question. Good question.
14 Any others on this topic?
15 MR. LOUDENSLAGER:
16 Okay. The second question that was
17 asked, and I believe President Suskie asked
18 this: That portion of the Entergy load
19 that's served through the WPP. And here's
20 the response that we got. It reflects that
21 beginning in April of '09 and goes up through
22 March of this year, the percent of their net
23 area load that is served by the WPP. 24 PRESIDENT SUSKIE:
25 I have a question about this, and
0178
1 I'll try not to be kind of too negative about
2 this. And the question is for Entergy, and I
3 don't know who the proper person is. I'll
4 begin by saying, I was not at the Commission
5 when the WPP was proposed, and I don't know
6 all of the background necessarily behind the
7 ICT being proposed.
8 I do know that I've read FERC's
9 order. I mean, I was very surprised by these
10 numbers, and maybe John is the person to
11 answer this. But I remember reading the FERC
12 order that was issued approving the WPP, and
13 I read the FERC order to be FERC thought the
14 WPP was the end‐all, be‐all to solve these
15 problems as promised by Entergy. That's ‐‐
16 you know, I'm going by what FERC said. I was
17 not here when the ICT or the WPP was first
18 proposed by Entergy.
19 Looking at those small numbers,
20 then hearing the concerns from stakeholders'
21 last meeting that they ‐‐ for whatever
22 reason, whether it's their fault or whoever's 23 fault it is, are not participating in the WPP
24 process as buyers. I was pretty stunned by
25 this, and I'm just kind of curious as to
0179
1 response, and I won't even get into the delay
2 issue of how long it took to get up. That's
3 pretty small. That's my gut reaction to this
4 when I saw this last week.
5 MR. HURSTELL:
6 I need to give you a couple of
7 pieces of information about it. John
8 Hurstell. What you see there is energy that
9 was purchased. If we'd have purchased all
10 the energy that was offered, it would be ‐‐ I
11 think this accounts for about 18 percent of
12 all the energy that was offered in the WPP.
13 And if the prices would have been more
14 attractive, we would have bought more. So
15 what determines how much we buy in the WPP
16 is ‐‐ are the prices that are offered to us.
17 I mean, I don't think anybody has ‐‐ has an
18 objective for us to pay more for energy than
19 what we can produce for it ourselves.
20 Now, I think the other thing to
21 keep in mind is that these are the WPP 22 purchases. If you were to look at our total
23 purchases, then you'd see numbers close to
24 30 percent, because we still purchase on a
25 seasonal basis, we still purchase monthly, we
0180
1 still purchase daily and hourly. So these
2 aren't ‐‐ these are all of our purchases. If
3 you look at all our purchases, those numbers
4 are closer to 30 percent.
5 PRESIDENT SUSKIE:
6 And so that's what's been confusing
7 to me, is that unless ‐‐ FERC may have
8 misunderstood, but when that FERC order that
9 was eissued at th time the WPP was approved,
10 they were ‐‐ seemed to be critical of the
11 fact that this was supposed to be the
12 end‐all, be‐all. And you're even telling me,
13 you know, with the 30 percent you purchase
14 from people other than Entergy, even it's a
15 small, small percent of the overall what you
16 purchase, so what's the purpose of the WPP,
17 if it's so insignificant?
18 MR. HURSTELL:
19 The purpose was to give merchant
20 generators a chance to compete with our 21 generators to provide the flexible capability
22 that we need, and it was to give them an
23 ability to commit for the whole week. We
24 generally commit our units for a seven‐day
25 period, five to seven days, and the current
0181
1 markets that we had, the next‐day market, the
2 monthly market, really didn't do that.
3 So the WPP was intended to give
4 them an opportunity to compete, and that's
5 what they have. They have an opportunity to
6 compete. Some choose not to compete, and
7 others offer pricing that isn't competitive.
8 So the fact that we don't buy more is because
9 of the pricing and the terms that are offered
10 to us, and, Mr. President, I can't control
11 what they offer.
12 PRESIDENT SUSKIE:
13 Yeah. I understand that. But I'm
14 just ‐‐ I'm surprised, after reading the
15 April order ‐‐ I just need to get a better
16 understanding. After reading FERC's order
17 last year and plus how it's scaled down to
18 just ‐‐ it's not ‐‐ the time for the bids was
19 restricted, reduced from the original filing. 20 I'm just perplexed. I mean, was FERC wrong
21 when they said this was going to be a major
22 solution, when it seems like it's very small?
23 MR. SCHNITZER:
24 Mr. Chairman, I was involved in
25 that part of the process. Let me offer my
0182
1 recollection of that.
2 The first is to state that, to my
3 knowledge and recollection, at the time,
4 Entergy never made a forecast of what the
5 benefits of the WP would be for precisely the
6 reason that Mr. Hurstell said, that it
7 depends on what the bids are. We tried to
8 quantify ‐‐ the whole purpose of the WPP, as
9 he explained, was to provide another
10 opportunity for displacement of the legacy
11 generation. And what the company did provide
12 was some estimates of how much value might be
13 created per percentage point or per certain
14 amount of reduction of legacy generation, but
15 we didn't include a forecast of how much of
16 that would result for the reasons just
17 stated; that that was a function, not just of
18 the pricing that was bid,t bu of the terms of 19 the bids; in particular, the flexible
20 capability.
21 But in answer to what was the
22 purpose of the WPP, and from Entergy's point
23 of view ‐‐ I can't ‐‐ I can't speak for the
24 FERC, but it was ‐‐ it was another
25 opportunity to provide for more displacement
0183
1 of the legacy generation, and it had the
2 potential of additional benefits of first
3 allowing people to bid a different product,
4 the AGC product, which, in fact, has been bid
5 to a limited degree, and, secondly, to
6 provide for this simultaneous optimization of
7 transmission and generation so that
8 additional transmission service might be
9 forthcoming for some of these displacing
10 units. That was the ‐‐ those were the
11 principal rationales. Whether those are, you
12 know, big numbers or small numbers on a
13 percentage‐wise, everyone, I guess, can have
14 their own opinion.
15 I think, just for openers, if you
16 were to ‐‐ more than half of Entergy's
17 kilowatt‐hours are served by nuclear coal and 18 QF, and I don't think anybody ever had an
19 expectation that the WPP was going to have
20 any impact on the percentage of load served
21 by nuclear coal or QF. And so the
22 denominator provided is the one requested. A
23 different denominator would give ‐‐ would
24 give numbers two to three times higher. You
25 might still think that those are small.
0184
1 And, as well, as I think Mr. Lucas
2 from SPP discussed two or three meetings ago,
3 you know, the gas prices during WPP's
4 operations have not hbeen as hig as they had
5 been previously, and I know from an Arkansas
6 perspective, you're not sorry about that.
7 But, again, ‐‐
8 PRESIDENT SUSKIE:
9 We were real sorry about it in
10 2008, ‐‐
11 MR. SCHNITZER:
12 Well, I understand, but that has ‐‐
13 PRESIDENT SUSKIE:
14 ‐‐ which we pay for today.
15 MR. SCHNITZER:
16 But that has an indication, you 17 know, for ‐‐ the dollar savings are, of
18 course, very sensitive to the gas prices,
19 natural gas prices. But, again, it's ‐‐ the
20 potential for the WPP always depended on the
21 nature of the bids, both in terms of the
22 price and the structure. And that's, as ‐‐
23 as John has said on a couple of occasions,
24 and I think is going to do a presentation to
25 the Working Group at the end of next week,
0185
1 that flexible generation piece is critical.
2 The WPP is a place for people to provide that
3 service. Thus far, we've gotten some, and we
4 welcome more. I don't know ‐‐
5 PRESIDENT SUSKIE:
6 Certainly.
7 MR. SCHNITZER:
8 ‐‐ if that's responsive.
9 PRESIDENT SUSKIE:
10 This Working Group will work on
11 that next week. And who sets the parameters
12 of the terms of the bid that will be bid?
13 That's where FERC, in April '09, went through
14 and said that, and there was some discussion
15 where the time ‐‐ the conditions of the bid 16 or the scope of the bid was shrunk by
17 Entergy's filing. Is that accurate?
18 MR. SCHNITZER:
19 In terms of ‐‐
20 PRESIDENT SUSKIE:
21 Sam, help me out on the ‐‐
22 MR. LOUDENSLAGER:
23 They weren't able to get the models
24 to solve for 24 hours a day, so the off‐peak
25 didn't make it. The system would crash
0186
1 whenever they would try to fix it. And I
2 don't think anybody anticipated that when
3 they went into this process of trying to
4 develop the WPP. So ‐‐
5 PRESIDENT SUSKIE:
6 My next question is ‐‐
7 SECRETARY ANDERSON:
8 Can I follow up?
9 PRESIDENT SUSKIE:
10 Sure.
11 SECRETARY ANDERSON:
12 So there was just a technical
13 problem with the software?
14 MR. LOUDENSLAGER: 15 Well, as long as they been on it,
16 Commissioner, it was more than a technical
17 problem. It was something they couldn't ‐‐
18 they could not make the software ‐‐
19 SECRETARY ANDERSON:
20 Who is "they"?
21 MR. LOUDENSLAGER:
22 The consultant that was in on that
23 processT, and the IC I think it was ‐‐
24 SECRETARY ANDERSON:
25 It seems to me one of the ‐‐ I
0187
1 don't mean to cut you off, but one of the
2 biggest problems, I think, with the WPP is
3 that it's ‐‐ its limited time.
4 MR. LOUDENSLAGER:
5 Absolutely.
6 MR. REW:
7 Commissioner Anderson, the ICT and
8 our WPP group was heavily involved in the
9 testing and development, and we supported the
10 scaling back of the time frame from 24 hour/7
11 to essentially on peak so that we could be
12 successful in getting the results, and it was
13 really the limitation of the software, 14 looking at the perplexity of solving for an
15 entire week in advance. It's a very complex
16 process that ‐‐ we were able to scale it back
17 and be comfortable with the results; whereas,
18 we couldn't get good results going 24 by 7.
19 So the ICT was in support of that change that
20 was filed and approved.
21 SECRETARY ANDERSON:
22 Kind of sounds to me like tail
23 wagging the dog a little bit. Well, ‐‐
24 MR. LOUDENSLAGER:
25 Commissioner Anderson ‐‐ Sam
0188
1 Loudenslager ‐‐ that was kind of the source
2 of my questions the last time you guys were
3 meeting about, well, has there been any
4 evaluation of changes ‐‐ low‐cost changes
5 that could be made and incorporated into the
6 procurement process so that ‐‐ because, you
7 know, I mean, looking out a week ahead,
8 that's a tough nut to crack. Okay? I
9 recognize that. And so I was thinking, what
10 about day‐ahead; what about realtime? Are
11 there ‐‐ and I'm not suggesting that there
12 are low‐cost alternatives. I just don't 13 know. I'm just asking the question.
14 PRESIDENT SUSKIE:
15 I have two kind of follow‐ups on
16 that topic. So who ‐‐ on the WPP process,
17 who determines if it's ‐‐ what's the ‐‐ if
18 it's the lowest bid option, the ICT or
19 Entergy?
20 MR. REW:
21 That's a good question.
22 MR. HURSTELL:
23 It's the transmission group.
24 MR. McCULLA:
25 The bids come in, and the algorithm
0189
1 goes through and chooses ‐‐ selects which
2 bids are selected. As long as the production
3 costs go down as a result, then those bids
4 are selected. So the software ‐‐
5 PRESIDENT SUSKIE:
6 Hold on one second.
7 MR. McCULLA:
8 Oh, I'm sorry. Mark McCulla with
9 Entergy.
10 So it's the software that puts out
11 and then selects the bids. 12 PRESIDENT SUSKIE:
13 Okay. Now, ‐‐
14 MR. McCULLA:
15 The ICT reviews it when it's done.
16 They review that, as well, so they're getting
17 the same results that we are in reviewing
18 that each week.
19 PRESIDENT SUSKIE:
20 Okay. Now, my next question is:
21 So that's for this small percent, for
22 whatever reason. Who makes that
23 determination for the other bids that are
24 bought from other generators, what you said
25 30 percent ‐‐
0190
1 MR. HURSTELL:
2 Monthly and ‐‐
3 PRESIDENT SUSKIE:
4 Yeah.
5 MR. HURSTELL:
6 Well, of the 30 percent, about
7 10 percent ‐‐ not 10 percent of the 30, but
8 10 percent of the total come from QFs. So
9 it's the Commissions that set the price. The
10 remaining ‐‐ 11 PRESIDENT SUSKIE:
12 So out of the ‐‐ 10 percent of the
13 30?
14 MR. HURSTELL:
15 No, no. 10 percentage ‐‐ 10
16 percent of our total system needs come from
17 QFs.
18 PRESIDENT SUSKIE:
19 QFs. So, in other words,
20 20 percent, then, goes from non‐QF purchases
21 Entergy makes?
22 MR. HURSTELL:
23 Correct.
24 PRESIDENT SUSKIE:
25 And then who makes those
0191
1 determinations?
2 MR. HURSTELL:
3 We ‐‐ my group does. We get the
4 bids in, and we do an evaluation, and we make
5 a determination as to whether they're
6 economic or not.
7 PRESIDENT SUSKIE:
8 I think a challenge for the Working
9 Group is, can that process or those bids be 10 incorporated in something along the line ‐‐
11 and I'm not offering a solution, just
12 throwing out an idea. Part of the WPP
13 process ‐‐
14 MR. LOUDENSLAGER:
15 I think they ‐‐ and I'm speaking
16 for Entergy, so John, correct me. I think ‐‐
17 MR. HURSTELL:
18 I probably won't.
19 MR. LOUDENSLAGER:
20 I think what they do, they go
21 through a regular procurement process where
22 they issue RFPs and then evaluate the bids
23 that come in in response ‐‐
24 MR. HURSTELL:
25 Well, that's when we get the
0192
1 monthly ‐‐
2 MR. LOUDENSLAGER:
3 Right.
4 MR. HURSTELL:
5 ‐‐ monthly processes, then the
6 long‐term processes. But the hourly
7 purchases or the next‐day purchases, we
8 evaluate what our needs are, and we take bids 9 on the phone, through e‐mails, any way we can
10 get them, and we accept the offers then.
11 That makes sense for us.
12 PRESIDENT SUSKIE:
13 And then I guess, just go back, you
14 know, the transparency concern or issue is,
15 then maybe it should be on the state
16 Commissions, but since it's done centrally,
17 what kind of reviews, if that's ‐‐ you know,
18 if those are the best ‐‐
19 MR. HURSTELL:
20 Well, it's up to the state
21 Commissions. Mississippi just did a very
22 extensive audit on our purchases, and we're
23 going through a field reconciliation in Texas
24 right now, where they're going to come in and
25 evaluate what we've done.
0193
1 PRESIDENT SUSKIE:
2 I think that's where the challenges
3 come in. You've got different states looking
4 at different things, and it's all done
5 centrally.
6 CHAIRMAN PRESLEY:
7 Is there an independent monitor? 8 MR. HURSTELL:
9 There's an independent monitor for
10 the long‐term transactions, locking into
11 long‐term purchases. Yes, there is for that.
12 PRESIDENT SUSKIE:
13 Define "long‐term." Greater than a
14 year?
15 MR. HURSTELL:
16 Greater than a year.
17 CHAIRMAN PRESLEY:
18 There's not for the short‐term?
19 MR. HURSTELL:
20 No, sir.
21 CHAIRMAN PRESLEY:
22 So that decision lies with your
23 group?
24 MR. HURSTELL:
25 Ultimately, it resides with me, and
0194
1 then I have to come before each one of you
2 guys and be willing to stand up and defend
3 us.
4 Now, one thing I want to be clear,
5 as Mr. McCulla made the point, is that the
6 merchants submit their bids and ‐‐ they 7 actually submit their bids to us, and we pass
8 them on to transmission, but our generation
9 goes in at cost. So I think it's important
10 that you guys understand that the more
11 information you make us put out about what
12 our savings are, it's providing information
13 to the merchants as to how much they can
14 raise their bid, because what they're
15 competing against is essentially a fixed
16 number, our cost.
17 So if we come here and report that
18 we saved a million dollars, then they know
19 thaty the can raise their bids and collect
20 more of those savings for themselves and not
21 for our customers. So I think it's just
22 important that you guys understand, the more
23 information we give out, the better
24 information they have to capture the savings
25 of the WPP.
0195
1 CHAIRMAN PRESLEY:
2 Can I ‐‐
3 PRESIDENT SUSKIE:
4 Go ahead, Brandon.
5 CHAIRMAN PRESLEY: 6 Let me follow‐up. Go ahead. Go
7 ahead with your question.
8 PRESIDENT SUSKIE:
9 I'll bet Sam and I are thinking the
10 same thing. Help me understand. The SPP ‐‐
11 and I'm not disagreeing with what you're
12 saying. It's a good, valid point. But like
13 an SPP, doesn't everybody know what the other
14 generators ‐‐ their costs are?
15 MR. LOUDENSLAGER:
16 Well, you know what ‐‐ generally,
17 what bid sets the price. That's what you
18 know. It's a marginal unit that sets the
19 price for everybody, and that price is
20 transparent, and everybody knows what it is.
21 PRESIDENT SUSKIE:
22 And, see, so then my question goes:
23 So then, of that 20 percent, what is that
24 marginal price? What is that price in the
25 market, so to speak?
0196
1 MR. HURSTELL:
2 It's going to be ‐‐
3 PRESIDENT SUSKIE:
4 Go to you, and then we have to ‐‐ 5 the state Commission may choose to come and
6 look at that and say, was that's the best
7 decision in hindsight.
8 MR. HURSTELL:
9 Right. And what we did and what
10 we're prepared to do ‐‐ and we actually did
11 it in Mississippi ‐‐ is for every purchase
12 that we make, we have what our alternative
13 costs would have been, and we can then show
14 that, when we made this purchase, a next‐day
15 purchase, we purchased it ‐‐ purchase power
16 at $45. We can show that we did an analysis
17 that showed, if we hadn't made that purchase
18 and generated it ourselves, our cost might
19 have been $50, so that's why we made the
20 purchase.
21 And if somebody comes in and offers
22 us 52, and our alternative generation cost is
23 50, well, then we won't make the purchase.
24 But what we don't do is, if somebody comes in
25 and offers us 42, we don't tell them, well,
0197
1 our alternative cost is 50, because that
2 price isn't going to be 52 the next day.
3 CHAIRMAN PRESLEY: 4 I had one follow‐up. I want to
5 make sure we're clear about this, what you
6 just said a minute ago when I raised the
7 point of an independent monitor. And you
8 said that if it were a contract or a purchase
9 contract more than a year, then the
10 independent monitor is triggered; if it's
11 less than that, you make the decision.
12 MR. HURSTELL:
13 No. I don't think it triggers it,
14 Commissioner. I think, in essence what it
15 is, though, we use an RFP process that's a
16 little more formal for the long‐term
17 purchases, and to be very candid with you, I
18 don't handle those. For the long‐term
19 process, we do have independent monitors.
20 CHAIRMAN PRESLEY:
21 For those purchases ‐‐ for those
22 purchases that are not required to goh throug
23 the RFP, those or below, you say you are the
24 decision‐maker for that?
25 MR. HURSTELL:
0198
1 My group is ‐‐ are the
2 decision‐makers, yes. 3 CHAIRMAN PRESLEY:
4 So if the report that was submitted
5 to the Mississippi Commission ‐‐ if ‐‐ I
6 don't have it in front of me. But if
7 language in that report says that these
8 purchases were all checked by an independent
9 monitor, in fact, that wouldn't be correct,
10 would it, because you just said that if it's
11 less than a year, you do; you make the
12 decision; there's no independent monitor
13 involved.
14 MR. HURSTELL:
15 And let me ‐‐
16 CHAIRMAN PRESLEY:
17 So if the language in that report
18 said that an independent monitor observed all
19 those, that wouldn't be correct, would it?
20 MR. HURSTELL:
21 If it said they observed them on a
22 realtime basis, that wouldn't be correct, but
23 I don't know whether they mean that there was
24 an independent (inaudible) after the fact,
25 then which is ‐‐
0199
1 CHAIRMAN PRESLEY: 2 Well, I don't have a copy of it in
3 front of me. I was just raising that to try
4 to get an understanding of exactly the
5 process.
6 MR. HURSTELL:
7 I want to be clear. There is no
8 independent monitor looking over our shoulder
9 on hourly purchases or next‐day or monthly
10 purchases.
11 CHAIRMAN PRESLEY:
12 And, in fact, in the audit in
13 Mississippi, the auditors testified, I think
14 under questioning by me, that they didn't
15 check those purchases, that they go through
16 the procedures. And I just want to make sure
17 that's clear. We don't want to leave with
18 the wrong picture here today.
19 MR. HURSTELL:
20 Well, I don't know what they said.
21 I know that I met with the auditors and went
22 through transactions with them, so butI ‐‐ I
23 don't know what they said.
24 CHAIRMAN PRESLEY:
25 Sure. Thank you.
0200 1 MR. LOUDENSLAGER:
2 John ‐‐ Sam ‐‐ is any of that data,
3 the prices for the shorter‐term purchases,
4 are they not provided to FERC or available
5 anywhere?
6 MR. HURSTELL:
7 Well, Sam, I think they're always
8 available to the Commissions.
9 MR. LOUDENSLAGER:
10 No, no, no. Are they reported on a
11 regular basis?
12 MR. HURSTELL:
13 I don't think our purchases are
14 reported on a regular basis. Our sales, our
15 wholesale sales, will be reported to FERC,
16 but not our purchases.
17 MR. LOUDENSLAGER:
18 Okay.
19 MR. HURSTELL:
20 We just don't make many of these
21 wholesale sales.
22 MR. BOOTH:
23 Well, let me put clarification on
24 it. If an independent power producer is
25 selling power through the WPP to Entergy, 0201
1 those are wholesale sales, correct?
2 MR. HURSTELL:
3 Yes.
4 MR. BOOTH:
5 So then those independent power
6 producers have to report those energy prices
7 hour by hour through their electric quarterly
8 reports to FERC, right?
9 MR. HURSTELL:
10 I don't think they have to report
11 it hour by hour. I think they have to ‐‐
12 well, I'll let them speak to what they have
13 to report.
14 PRESIDENT SUSKIE:
15 Any merchant generators care to
16 answer that? I cannot believe the merchant
17 generators are being quiet. Okay. Let that
18 be an action item to find out what has to be
19 reported at FERC by merchant generators.
20 Mr. Cruthirds?
21 MR. CRUTHIRDS:
22 Yes. Dave Cruthirds with The
23 Cruthirds Report.
24 PRESIDENT SUSKIE: 25 By the way, he's got a brochure
0202
1 outside. We're going to start charging you
2 for the use of that table.
3 MR. CRUTHIRDS:
4 That's fair enough. I guess I
5 wanted to clarify. You said there's an
6 independent monitor of all your long‐term
7 procurement processes, and I guess I'm only
8 familiar with the Louisiana PSC. The only
9 RFP process ‐‐ I'm not sure about Texas, but
10 I don't think New Orleans, Arkansas or
11 Mississippi have formal RFP processes that
12 require independent monitors, and I wouldn't
13 want there to be confusion on that point.
14 MR. HURSTELL:
15 I appreciate the clarification.
16 I'm not involved in the long‐term processes.
17 I'm just ‐‐ when somebody mentioned an
18 independent monitor, the only time I know
19 that we use one is in long‐term processes.
20 Whether it's in all long‐term processes, I
21 can't answer.
22 MR. LOUDENSLAGER:
23 This is Sam Loudenslager with 24 Arkansas. Arkansas procurement practices
25 there mirror what takes place in Louisiana,
0203
1 so there is a third‐party monitor that
2 evaluates ‐‐ looks over the shoulder of the
3 bids that come in.
4 VICE‐PRESIDENT FIELD:
5 I had a question for Mr. Hurstell.
6 John, you said if you accept a bid that's
7 short‐term ‐‐ it could be a WPP ‐‐ then you
8 have to send it to Mark or transmission; is
9 that correct? Is that what you said?
10 MR. HURSTELL:
11 It's pretty ‐‐ yes, that's right.
12 It's a pretty perfunctory process. It only
13 is verified at the part that the bidder is on
14 our approved vendor list. We have to have a
15 contract with ‐‐ we have to have a contract
16 with the party; we have to have, you know,
17 good credit relations ewith th party. It's a
18 pretty perfunctory process. We don't scream
19 out and say, "This bid doesn't look good."
20 VICE‐PRESIDENT FIELD:
21 No. I'm just wondering if you
22 know, when you accept the bid, that 23 transmission is available or whether you have
24 to ‐‐ if you accept a good price, then do you
25 have to run it by transmission to see if
0204
1 actually there is interconnection and so
2 forth?
3 MR. HURSTELL:
4 Let me clarify. I'm being told
5 that I'm not clear. In the WPP process, we
6 just take the bid. Whether there's ‐‐ we
7 don't know whether there's transmission
8 available or not, and we pass it over to
9 the ‐‐ what's called the Weekly Operations
10 Group in transmission. They will send back
11 to us the bids that we have accepted, and
12 there will be transmission, and we'll just
13 consummate the deal with the third party.
14 Now, if it's outside of the WPP, so
15 it's a purchase for the next ‐‐ it's an offer
16 for the next day, we'll evaluate the terms,
17 and if we choose to accept it, then we'll
18 have to go and try and secure the
19 transmission. Now, it could be incumbent
20 upon us to secure the transmission, or it
21 could be incumbent upon the seller, depending 22 upon the terms of the arrangement, but we do
23 that through the OASIS, like any other market
24 participant.
25 VICE‐PRESIDENT FIELD:
0205
1 So do you have a record of the
2 number of purchases that have to be rejected
3 because they're not adequate transmissions?
4 MR. HURSTELL:
5 We ‐‐ we keep a report of every one
6 of our rejected offers, and we have a reason
7 why we rejected it. So I'm trying to go
8 through in my mind the reasons for the
9 rejections, and I don't know whether or not
10 that's a specified reason, couldn't get
11 transmission, or whether or not we might have
12 put it in another category. But I guess
13 there are going to be times when we would
14 have wanted to purchase a deal, but we
15 couldn't because there wasn't transmission.
16 VICE‐PRESIDENT FIELD:
17 Right. I'm just ‐‐ that might be
18 helpful to this committee to know ‐‐ and
19 maybe it will turn up in the Mississippi
20 audit or somebody else's audit on what your 21 records show or why you had to turn it down,
22 because we're trying to find out which
23 transmission projects might be economically
24 feasible or benefit ‐‐ beneficial to the
25 ratepayers within a period of time. So I
0206
1 think that would be important, if you have
2 that information, to furnish it.
3 MR. HURSTELL:
4 How about if we take an action item
5 to find out if we have it, and if we have it,
6 we'll give it to you, and if we don't, we'll
7 let you know.
8 VICE‐PRESIDENT FIELD:
9 That's fair. Now, you mentioned
10 that the bids also have to be flexible.
11 Explain that. Does that mean that you have
12 to dispatch it? Entergy has to be able to
13 dispatch it, or ‐‐ or just what?
14 MR. HURSTELL:
15 Are you talking about for the WPP?
16 VICE‐PRESIDENT FIELD:
17 Yes, sir.
18 MR. HURSTELL:
19 All right. First of all, the bids 20 don't have to be flexible. They can bid a
21 block, and we'll evaluate the economics of
22 that. The real value of the WPP is it gives
23 merchants a chance to bid a flexible ‐‐ give
24 us flexible capability. You know, for
25 example, they may bid a minimum of ‐‐ we have
0207
1 to take a minimum of 350 megawatts, and we
2 can take up to 450 megawatts, and that gives
3 us 100 megawatts of flexibility.
4 Now, if you take the exact same
5 pricing on a deal that has a 350 ‐megawatt
6 minimum and a 450‐megawatt maximum, and you
7 change it to where it's a 100‐megawatt
8 minimum and a 450‐megawatt maximum, that will
9 significantly improve the value of that deal.
10 Pricing isn't the key dropper there. It's
11 the amount of flexible capability that we're
12 offering, and in order to provide that
13 flexible capability, a merchant has to have
14 the equipment, the physical equipment, that
15 can be turned down that low and up that high,
16 and they have to have the fuel supply, that
17 they cant ge gas at a low volume and at a
18 high volume. 19 So those are the things that play
20 into the merchant's decision as to what to
21 offer us in terms of flexible capability.
22 The more flexibility that's offered to us,
23 the higher value that's going to be assigned
24 to that generation. So we're not saying they
25 have to offer, but the more flexibility they
0208
1 offer, the higher value the offer is to us.
2 And that's what ‐‐ we're going to go over
3 that at the Working Group meeting, and I
4 would love to have the opportunity to work
5 through some simple examples before this
6 group to help understand how important the
7 flexibility is to our economics.
8 VICE‐PRESIDENT FIELD:
9 Okay. Well, I don't ‐‐ I think
10 maybe we better not get sidetracked on it
11 today, but I think it would be good to show
12 the Working Group how you make that analysis
13 and how you assign economic value to
14 flexibility and so forth.
15 MR. HURSTELL:
16 Sure.
17 PRESIDENT SUSKIE: 18 And I think that's the concept, to
19 let the Working Group work through it and
20 help get us educated on it, as well. Thanks
21 for those clarifications.
22 MR. LOUDENSLAGER:
23 Yes, sir. I am anticipating that
24 y'all's May agenda is going to be incredibly
25 heavy, as it ‐‐ as it stands now. And so
0209
1 would it be acceptable to y'all that, once we
2 get ‐‐ maybe June is a good time to do it,
3 but to give us an opportunity, the Working
4 Group and stakeholders an opportunity ‐‐ or
5e th Working Group an opportunity to kind of
6 review some of that bid information you were
7 asking about and ‐‐ just to see what was
8 going on, what's been going on. I don't know
9 how ‐‐ what I'm ‐‐ I don't know what I'm
10 chewing ‐‐ I'm biting off here when I suggest
11 that, but we can talk about that at the
12 Working Group level next week. And if you'd
13 like, in June, we can ask some folks to pull
14 together a presentation on the WPP process
15 today, and so everybody has a ‐‐ is on a
16 level ‐‐ a level understanding of the 17 process, what does happen, what doesn't
18 happen, what gets submitted, how that doesn't
19 meet Entergy's needs.
20 PRESIDENT SUSKIE:
21 I think it would be something good
22 for ‐‐ I think, obviously, the next meeting,
23 maybe the next two meetings, we've really got
24 to concentrate on enhancements to the ICT,
25 and maybe once we get those done, we'll focus
0210
1 on the market or the WPP issues.
2 MR. LOUDENSLAGER:
3 I have a concern. This is just me
4 speaking for Sam. I have a concern about a
5 lot of realtime activities that are taking
6 place with no kind of oversight. I'm not
7 saying there's anything wrong with what's
8 going on. I just don't know, and would like
9 to get a better handle on that. And when I
10 say that, I'm talking about realtime,
11 day‐ahead, which goes back to the ‐‐ one of
12 the things ‐‐ statements I made earlier
13 today, which is, can the WPP be modified to
14 deal with realtime and day‐ahead. That's
15 another day. 16 PRESIDENT SUSKIE:
17 Yeah. That's a good point. I
18 think, clearly, we all have concerns about,
19 you know, as John pointed out, what's the ‐‐
20 what was costs for ratepayers, and I think we
21 all share that, and whoever can provide that,
22 obviously, it's something thate we'r
23 interested in.
24 MR. SCHNITZER:
25 Not to prolong this, Mr. Chairman,
0211
1 but I ‐‐ you know, a meeting or two ago, when
2 Sam raised that question about whether the
3 WPP could be used for day‐ahead or realtime,
4 and I think eI just ‐‐ th point I made at
5 that point, which is that we're open to that,
6 but we didn't get ‐‐ we didn't get to the
7 weekly procurement by accident. We got to it
8 by virtue of the fact that the Entergy legacy
9 units typically have commitment runs of four
10 to five days and appreciable starting times.
11 And so if you're not going to
12 commit them because you bought something for
13 tomorrow, and then the thing that you bought
14 for tomorrow disappears, you have a bit of a 15 problem. And in organized markets, there are
16 some other ‐‐ so‐called day‐two markets,
17 there are solutions for that, which is that
18 all the generators agree that they're going
19 to bid every day.
20 And so we're open to exploring
21 those kind of options that Sam suggests, but
22 part and parcel would be a set of merchant
23 generator commitments, that if we're going to
24 only buy on a daily basis the WPP instead of
25 committing our units, that people have to be
0212
1 committed to bidding every day, not just one
2 day, et cetera. So it's an idea that's worth
3 considering, but I think it's a little more
4 involved than just focusing on the WPP aspect
5 of it.
6 PRESIDENT SUSKIE:
7 Sure. And I think the question it
8 kind of begs is, is the legacy units the
9 problem, or is it the bids? I mean, I think
10 that's the challenge. And then I just ‐‐ you
11 know how I like to just throw out little
12 things. In light of the Arkansas order
13 yesterday, I will say MISO does have a 14 day‐two market, but I just throw that out.
15 MR. SCHNITZER:
16 Well, they do. And they have
17 exactly the type of requirement that I
18 described, you know, that if you're a network
19 resource in MISO, you will bid or schedule
20 every day, if available, and we don't have
21 that in the Entergy footprints. My point was
22 not that you can't have those things. My
23 point was that you just can't say I'm going
24 to have a day‐ahead market without also
25 looking at some of the other market rules
0213
1 that make that reliable, you know, for
2 customers.
3 PRESIDENT SUSKIE:
4 Ms. Turner? Microphone?
5 MS. TURNER:
6 And I think you were hitting on
7 this, Commissioner Suskie. There are ‐‐
8 there is another reason why bids are not
9 accepted, and that's because there's
10 congestion on the system. So, I mean, if
11 there's congestion and a unit, you know,
12 is ‐‐ costs less, the bid, but it can't be 13 moved into the region where the more
14 expensive generation is running, then that's
15 another reason, which probably warrants some
16 further looking into, as well.
17 PRESIDENT SUSKIE:
18 I think you're right. And I think,
19 ultimately, the concerns state regulators
20 have raised, it really boils down to two
21 solutions, transmission and opening up
22 markets. I'm not a de‐reg guy, but I think
23 they fall into one of those two categories.
24 How do you get ‐‐ build a transmission and
25 when and how do you get the lowest cost of
0214
1 generation to the customer? I think those
2 are the challenges.
3 SECRETARY ANDERSON:
4 At least.
5 PRESIDENT SUSKIE:
6 Sorry. He's got to defend the open
7 markets.
8 SECRETARY ANDERSON:
9 No. In my perspective, the two are
10 connected. Because if you don't have robust
11 transmission, then you really can't have a 12 market.
13 PRESIDENT SUSKIE:
14 Yeah.
15 CHAIRMAN PRESLEY:
16 That's right.
17 PRESIDENT SUSKIE:
18 You noticed I said transmission
19 first, so...
20 SECRETARY ANDERSON:
21 Good point.
22 MR. HURSTELL:
23 Excuse me, but I just want to make
24 sure we address one thing here. I'd like to
25 address one issue.
0215
1 PRESIDENT SUSKIE:
2 Sure.
3 MR. HURSTELL:
4 The legacy units ‐‐ and I'm going
5 to defend them ‐‐ they run because they're
6 valuable units to us, and if we could produce
7 cheaper power by buying more from the
8 merchant generators, we would be doing that.
9 But because of the requirements of our
10 system, we need flexibility. And when you 11 have a legacy ‐‐
12 PRESIDENT SUSKIE:
13 You said the requirements of the
14 system or the requirements caused by the
15 legacy units, the QF issue?
16 MR. HURSTELL:
17 The QF issue, the generator
18 imbalance issue, the volatility in our loads
19 issue, all of those things have nothing to do
20 with the type of generation that we have.
21 Put burdens on us. It is the equivalent of
22 the wind problem, QF, and if you hear about
23 the wind problem, you'll often hear about you
24 need flexible generation that can respond to
25 the change in wind. We have that on our
0216
1 system.
2 When you have our legacy units,
3 some of them can operate 50 megawatts at a
4 minimum and 450 megawatts maximum. There is
5 not a single merchant generator that I'm
6 aware of that has a unit that can swing by
7 400 megawatts. That is a very important
8 service that those resources provide to us.
9 It makes them very valuable. 10 Merchant generators provide a very
11 valuable service when we can block‐load them,
12 and we buy them for 12 hours or 16 hours, and
13 we take them flat. That's why we take so
14 much energy in the market. But I would ‐‐
15 it's going to be my goal in life to convince
16 you that the legacy units are very valuable
17 assets to us, and we need to make sure that
18 that's understood before we just set an
19 objective to just shut them all down.
20 PRESIDENT SUSKIE:
21 Let me ask you to let your goal be
22 to help us get educated with the stakeholders
23 and let us come to that conclusion.
24 MR. HURSTELL:
25 I will work towards that goal.
0217
1 PRESIDENT SUSKIE:
2 Yes, Bill?
3 MR. BOOTH:
4 Two quick follow‐up questions,
5 John. First, with respect to flexibility, I
6 know that you're talking about the swing
7 between min. and max. Is there also a
8 characteristic of the ramp rate? I mean, do 9 you need a specific ability to change power
10 per unit of time at a specific rate?
11 MR. HURSTELL:
12 Yes. The ‐‐
13 MR. BOOTH:
14 Is it a standard fixed rate or does
15 it vary, depending on existing conditions?
16 MR. HURSTELL:
17 It varies based ton ‐‐ no so much
18 on system conditions but on the parameters of
19 many individual units. It depends on where
20 the unit is in its operating range, but it's
21 also the case ‐‐ oh, it's how fast we have to
22 come up. I thought you were talking about
23 the capability of the units. It can be
24 significantly different at different times of
25 the day.
0218
1 For example, in the summer, when
2 our loads are coming up in the morning, we
3 have to have generation that can respond
4 upward, and eat th same time, QFs that may
5 have put energy to us at night, and now
6 they've sold it off to some third party
7 during the day, so their generation is 8 disappearing from our system so that we have
9 to ramp up even more to make up for that
10 energy. So the ramping requirements on our
11 system could be several thousand megawatts in
12 an hour.
13 MR. BOOTH:
14 I guess, just to focus, my question
15 is: Do you have objective criteria, ramp
16 rates and swing rates, that you use to
17 determine whether an IPP's bid should be
18 accepted or not accepted? You said you
19 quantify bids based on ‐‐ the value of a bid
20 based on the flexibility it provides.
21 MR. HURSTELL:
22 No. Let me ‐‐ let me be clear. We
23 have models that ‐‐ just like any production
24 cost model, except ours doesn't look ten
25 years in advance. It looks seven days in
0219
1 advance. And we put all these options in,
2 and they evaluate all our requirements. We
3 need capacity to serve people, we need
4 reserves, we need to be able to turn
5 generation down to a minimum, we need to be
6 able to accept the forecast in QF put. 7 I can't sit here and tell you that
8 we evaluate each option based solely on the
9 flexibility. We let the model find the
10 cheapest solution to our problem by looking
11 at all the parameters at the same time, but I
12 can just tell you from experience, the more
13 flexibility a unit offers, the higher the
14 value.
15 Now, we take offers from merchants
16 and other third parties to buy block energy,
17 because we have room on our system to accept,
18 you know, economically‐priced block energy,
19 and we. take it But if you want to be more
20 valuable, if you want to get a higher value,
21 then you've got to offer us flexibility.
22 MR. BOOTH:
23 I guess I'm just trying to
24 understand whether the assignment of that
25 value is based on objective criteria, or is
0220
1 it a gut feel, or how do you figure out ‐‐ I
2 guess we'll go ‐‐ probably go through this in
3 more detail.
4 MR. LOUDENSLAGER:
5 Yeah. We'll go through that next 6 Friday.
7 MR. BOOTH:
8 One other question is: Have you
9 considered talking to QFs about whether or
10 not they can comply with some type of a
11 schedule? I mean, if a QF can be compensated
12 for the energy that it produces ‐‐ even Pat
13 will tell you, in New York, they have
14 something called bid production cost
15 guarantee. Maybe there's something similar
16 that Entergy can do that would provide
17 motivation for QFs and our IPPs to follow
18 some type of a schedule rather than block ‐‐
19 rather than tjust pu blocks of energy to ‐‐
20 when you don't anticipate it.
21 MR. HURSTELL:
22 What we've done is ‐‐ first of all,
23 we buy some energy from QFs under long‐term
24 contracts. We buy some energy from ‐‐ so
25 that takes them out of the QF put category.
0221
1 We buy energy from them. I believe it's on a
2 monthly basis sometimes. And others, we buy
3 on a day‐ahead basis. We have talked to the
4 QFs, I think it was in Louisiana, which is 5 where most of our QFs are, and we work with
6 the LPSC.
7 As a matter of fact, it was
8 Mr. Zimmering who came up with the idea for
9 what's called the day‐ahead mechanism, where
10 merchants ‐‐ where QFs could bid a certain
11 quantity and get ‐‐ we'd have avoided costs
12 based on the bids we received, and then they
13 would have certainty on what they were going
14 to be paid, and we'd have certainty in what
15 was delivered, and the QFs rejected that.
16 That wasn't an Entergy proposal; it was an
17 LPSC proposal. We supported it, but it was
18 an LPSC proposal.
19 And I think that ‐‐ my experience
20 has been the QFs, they look at what they
21 think they can get in the next‐day market,
22 then they make a determination as to whether
23 they're going to sell to us on a firm basis
24 or reserve the option to maybe sell to
25 somebody else on an hourly or daily basis.
0222
1 So we try, and we're happy to continue to
2 try.
3 PRESIDENT SUSKIE: 4 All right. I think our Working
5 Group is going to work on this, and we
6 appreciate delving into this issue in the
7 future in a little more detail.
8 MR. SCHNITZER:
9 Will you permit me one more minute,
10 Mr. Chairman?
11 PRESIDENT SUSKIE:
12 Sure.
13 MR. SCHNITZER:
14 The question you asked a few
15 moments ago, is it the flexible capability or
16 is it the legacy units that's the problem, I
17 think, was the ‐‐
18 PRESIDENT SUSKIE:
19 Yeah.
20 MR. SCHNITZER:
21 ‐‐ comment that you made. Let me
22 just ‐‐ let me just try and address the
23 interplay between those two. If you start
24 with the load shape that Entergy has to
25 serve, you know, which goes up and down by a
0223
1 factor of two many days, and you take out the
2 nuclear and you take out the coal and you 3 take out the QF, you know, if you've got ‐‐
4 you take out the block purchases that fit,
5 you've got a shape that doesn't look at all
6 like a base load; it doesn't look at all like
7 an on‐peak block; it looks like something
8 that has to be flexible and has to move.
9 John will have the current data,
10 but for these legacy units we've been talking
11 about, on a weekly basis, they'll be
12 committed, and they might run at a 20 to
13 30 percent capacity factor for a week, and
14 they'll sit at minimum all night long, and
15 then they'll be part of that power
16 ascendancy, and then, you know, they'll go
17 back down. So that's what we're trying to
18 displace. You know, we don't have any more
19 blocks to displace. What's left is this
20 particular shape, which is what follows the
21 load and provides the flexible capability.
22 So that's the flexible capability
23 requirement. That's what is left to be
24 displaced.
25 Where the legacy unit operating
0224
1 characteristic comes into play is, when you 2 want to displace that, when you commit that
3 unit, you don't commit it for a day, you then
4 can't de‐commit it and recommit it; you've
5 got to commit it for four or five days at a
6 time. And so when you choose not to commit
7 it, you have to be pretty sure that what is
8 going to be providing that flexibility is
9 going to be with you for more than a day.
10 And so that's ‐‐ the system requirements, net
11 of all the other generating resources, are
12 what determines that what's left over
13 requires flexibility. And then the operating
14 characteristics of the units that are
15 currently the most economic to provide that
16 flexibility, you have to keep them in line
17 when you're designing a system to compete
18 against something else against them.
19 And that's all we were trying to
20 convey, is the interplay of those two
21 concepts which got us to the WPP. I hope
22 that's helpful.
23 PRESIDENT SUSKIE:
24 Sure. Absolutely. I see what the
25 issue is.
0225 1 Sam?
2 MR. LOUDENSLAGER:
3 Yeah. I think ‐‐ I think we've got
4 ‐‐ the reason I've been kind of wandering
5 around from person to person is to help
6 somebody ‐‐ have somebody help me remember if
7 we hadn't asked for the operating guides,
8 because I think that's one of the key items
9 that we're going to have to take a look at
10 and better understand, Entergy's operating
11 guides. And that probably will be in the
12 context of the RMR issue, flexibility issue,
13 which is still wide open ate th Working Group
14 level. So that y'all know, we're just trying
15 to get our arms around what the appropriate
16 scope is in order to start addressing that
17 issue.
18 PRESIDENT SUSKIE:
19 And my thoughts are, absolutely, we
20 want to look at those higher priorities to
21 get ready for the filing at FERC for enhanced
22 ICT.
23 MR. LOUDENSLAGER:
24 Right. And my response, Chairman,
25 is that's not going to be a quick process 0226
1 anyway, so we're starting it now, not
2 deviating from the FERC filing, but aware of.
3 This is an issue I know Louisiana has been
4 trying to struggle with for years, and we're
5 just going to try to help them.
6 PRESIDENT SUSKIE:
7 Great.
8 MR. LOUDENSLAGER:
9 Y'all ready for me?
10 PRESIDENT SUSKIE:
11 Yeah.
12 MR. LOUDENSLAGER:
13 I've got three purposes for making
14 the presentation today. One we've already
15 talked about, our activity since y'all's
16 meeting on March 18th, to update you on the
17 progress we're making on the enhancements and
18 then to seek additional input and direction
19 from you as we go through this. I think I've
20 covered this, what our meeting schedule looks
21 like, and kind of ‐‐ that we've issued data
22 requests to Entergy, the ICT and some of the
23 stakeholders, some of the other stakeholders,
24 and that participation by the stakeholders is 25 significant, and that's a good thing. I
0227
1 would encourage all the stakeholders to be at
2 our face‐to‐face meetings, because we do get
3 down into the details on a lot of these
4 issues, and that's a great way for us to hear
5 your perspective on some of these items.
6 So we look at the initial
7 enhancements that were the focus of y'all's
8 conversation in March, and yesterday I went
9 through and just kind of came up with a list
10 of the nine. And whatm I' trying to do here
11 is to reflect in shorthand what the
12 enhancement was and whether or not that
13 enhancement is going to require a tariff
14 change or not. This is one of the things
15 that was the result of our last Working Group
16 meeting face‐to‐face.
17 So the first one was to change to
18 the planning and the planning arising in a
19 transmission service request process. It was
20 adopted, but, if you remember, we've still
21 got some work to do there. Entergy has been
22 helping us doinge th studies. That was
23 greater than three years but less than ten 24 years. Okay? At the end of the day, once we
25 come back with another recommendation to you
0228
1 on what that should look like, it will
2 require a tariff change.
3 The second item is to identify the
4 list of categories of information that are
5 market‐sensitive or confidential. And one of
6 the stakeholders agreed that ‐‐ or suggested
7 that, you know, that information, that list
8 could be included as part of the tariff, and
9 if that's so in attachment whatever, it would
10 require a tariff change, as well. My concern
11 with that is, I don't know how often that
12 list would change. I just don't know. And
13 so if it changes frequently, then that means
14 you're going to have to make a number of
15 tariff changes or tariff changes on a
16 frequent basis.
17 Increase the ICT's authority over
18 the ATC and AFC calculations. Again, we
19 believe that a tariff change will be required
20 for that enhancement, as well.
21 And, let's see, go on to the next.
22 Thank you. 23 Identify RMR units and potential
24 cost‐effective transmission alternatives. As
25 we've discussed this afternoon, we're still
0229
1 working through that. We believe eventually,
2 once we come up with some ‐‐ I'll use the
3 word solutions to that situation, we believe
4 that there will be a need for tariff changes,
5 but that would not be in the initial filing
6 is the way I'm characterizing it, you know,
7 the June ‐‐ the June filing. That will be
8 something that we would have to do later,
9 simply as a matter of workload. We won't
10 have those studies completed by June.
11 MR. BOOTH:
12 Sam?
13 MR. LOUDENSLAGER:
14 Yes, sir.
15 MR. BOOTH:
16 Do you think we have to revise the
17 tariff to find what reliability must‐run in
18 the dis ‐‐
19 MR. LOUDENSLAGER:
20 I think there's a chance of that,
21 Bill. 22 MR. BOOTH:
23 That might be part of the initial
24 filing?
25 MR. LOUDENSLAGER:
0230
1 It depends on where we're at. I
2 don't want to overcommit us. I don't want to
3 over ‐‐ I don't want to boost your
4 expectations too much, Commissioners. I
5 mean, we're going to do what we're going to
6 do, everything we can, so...
7 On the Seams Agreement, one‐stop
8 shopping, elimination of pancake rates, you
9 know, that's all kind of grouped into that
10 one enhancement, and we believe that,
11 certainly, if there's a Seams Agreement, that
12 would require a tariff change. In fact, I
13 think recently, there was a partial Seams
14 Agreement filed between SPP and Entergy at
15 the FERC, addressing a couple of 890 issues.
16 But there's still more work to be done to
17 complete what I consider a confidential Seams
18 Agreement.
19 You know, if there's elimination of
20 the pancake between Entergy and SPP, I'm 21 assuming that there's going to have to be a
22 tariff change for that, too. If something
23 ultimately is adopted for one‐stop shopping
24 and agreed to between the SPP members and the
25 stakeholders and Entergy, I'm assuming that
0231
1 would need a tariff change, as well.
2 The elimination of the base case
3 overload, yeah, it would require tariff
4 changes, but it's really tied more to that
5 planning issue and the transmission service
6 request issue, which was the first item we
7 talked about.
8 Initial enhancements that do not
9 require tariff changes: The process of
10 analyzing TLRs and identifying potential
11 cost‐effective upgrades to eliminate TLRs, we
12 don't believe that that ‐‐ that's more of a
13 process, trying to get to the ‐‐ a solution
14 to the problems, and off the top, I don't
15 believe that that's going to require a tariff
16 change.
17 Comprehensive reporting of TLR data
18 to address causes, again, we don't think that
19 that would require a tariff change. 20 And the construction tracking
21 report, we don't believe will require a
22 tariff change, which ‐‐ I'm sorry.
23 Go ahead.
24 And so then I shift and I move away
25 from the nine enhancements that were
0232
1 addressed at the March meeting and focus on
2e th additional 15 enhancements; actually, two
3 less than that right off the top. Entergy
4 made two proposed enhancements that are being
5 incorporated elsewhere. So I just ‐‐ I set
6 those aside. But these are the items that we
7 don't believe should be pursued at this time.
8 The first one is the development of
9 new markets for the Entergy region. And the
10 thinking of the Working Group ‐‐ and I would
11 encourage the Working Group members to speak
12 up whenever I misspeak, because it was
13 midnight last night when I was finalizing
14 this thing, so... but the reason we decided
15 that it wasn't timely is because this issue
16 would depend largely on whether or not
17 Entergy joins the SPP RTO. If it doesn't, if
18 the decision is made not to join the RTO, 19 then I think we can go ahead and push forward
20 with the question of how can we develop
21 markets in the Entergy region short of an
22 RTO.
23 The second issue is the utilization
24 of an independent market monitor. And,
25 again, part of the basic question was, where
0233
1 is Entergy going to be? Are they going to be
2 in an RTO or not? If they're in an RTO,
3 they're going to have an independent market
4 monitor or market monitoring unit evaluating
5 their activities. And so, in the short‐term,
6 even two to three years, it could be a costly
7 enhancement and unnecessary. Also, if there
8 were market power‐related issues that
9 stakeholders have concerns about, I see the
10 E‐RSC as being a forum for people to bring
11 those issues to. Okay? And then we're
12 thinking that some of the other proposed
13 enhancements will help alleviate some of the
14 concerns over market power.
15 Turning over to page 8, the ‐‐ this
16 is a group that we're saying we're working
17 on; we're not bringing anything to you today. 18 If you have guidance that you want to provide
19 to us, you're certainly welcome to that. And
20 so these are ‐‐ again, these are things we're
21 working on. To begin to work through the
22 stakeholders ‐‐ the enhancements that were
23 proposed by the stakeholders, and some of
24 these proposals are related to ultimately
25 what happens with the 205 rights issue.
0234
1 We may find out, as we get further
2 down the road, that some of those
3 enhancements should not be pursued at this
4 time, but just so you recall, because it was
5 helpful for me to be reminded, that that
6 initial list of nine proposed enhancements,
7 we used kind of three rough criteria to
8 evaluate whether or not, of all the
9 enhancements, how do we determine what needs
10 to be done first? And so these were the
11 three criteria: They need to be relatively
12 low‐cost, they needed to be achievable in a
13 reasonable time period, and they needed to
14 result in a tangible ratepayer benefit. So
15 that's the ‐‐ kind of the criteria we're
16 starting with,n eve as we review these 17 additional ones. And I think we're still
18 talking through whether or not there are
19 additional criteria or different criteria
20 that we need to use to evaluate them.
21 So one of the proposed enhancements
22 was to determine the economic benefits of
23 upgrades in the planning process, and our
24 take on it, at least right now, is that this
25 is related to the 205 issue and what may be
0235
1 resolved, depending on what rights are agreed
2 to. So, i.e., everything seems ‐‐ well, not
3 everything. Everything either goes back to
4 planning or cost allocation.
5 So the distinction of the economic
6 versus reliability upgrades, again, that's
7 related to the planning and transmission
8 service request process. And I have asked
9 Entergy to complete the study that they were
10 asked to perform by May the 14th, I believe,
11 which would give the Working Group plenty
12 of ‐‐ well, give the Working Group some time
13 to evaluate the results of that study before
14 the June meeting, and that's going to be key,
15 because that ties ‐‐ remember the issue? 16 Three years isn't long enough; ten years may
17 be too long. What's the right study horizon?
18 And ‐‐ because it all ties back to the TSR
19 issue.
20 Evaluating the limitations of the
21 ICT contract. And I've asked ESPY, Energy
22 Solutions, to take a hard look at that
23 contract and report back to us on where there
24 might be some concerns, constraints in the
25 contract, and I imagine that will be reported
0236
1 back to you at the next meeting.
2 The issue of additional resources
3 and staff for the ICT. And this is me
4 speaking for me, not the Working Group. I
5 think that's more a question of compensation
6 under the contract. You know, if there are
7 more resources that are needed and staff
8 needed by the ICT, I think it's just a
9 question of will Entergy pay for those
10 resources or not. So that can be addressed
11 as we move forward.
12 Identification of cost‐effective
13 remedies on congestion ‐‐ to congestion on
14 flowgates. We think that this is one of 15 those items that also could be addressed
16 through proposed planning enhancements, but a
17 caveat is, is that last night, I was thinking
18 it may require additional study. This
19 morning or this afternoon, I'm thinking,
20 yeah, it's going to require additional study.
21 You're going to ‐‐ you're going to want
22 better information than will result from just
23 kind of the planning horizon study.
24 The Attachment K economic studies,
25 we're currently kind of ‐‐ have rolled that
0237
1 into the ‐‐ our work that we're going to be
2 doing on the RMR and planning issues.
3 We talked about this this morning,
4 who should have 205 filing rights and the
5 extent of such rights. Some stakeholders
6 propose that the ICT should have them. The
7 ICT doesn't want them, and nor should they
8 have them, I don't think. The Working Group
9 believes that the rights should reside with
10 the E‐RSC, and as we talked this morning,
11 we're looking for guidance on the extent of
12 such rights and need guidance on how the
13 rights would be acquired. 14 So those are two major issues. And
15 if I understood this morning, you're looking
16 for stakeholders to provide us with input on
17 that question ‐‐
18 PRESIDENT SUSKIE:
19 Yes.
20 MR. LOUDENSLAGER:
21 ‐‐ on both of those questions, I
22 guess.
23 PRESIDENT SUSKIE:
24 Yes. Stakeholders, including
25 the ‐‐ including, you know, the Working
0238
1 Group. One even thought I had was the ICT,
2 if they say, you know, these are changes that
3 need to be made to the tariff, and my thought
4 was they submit something to this ‐‐ the
5 E‐RSC, and then the E‐RSC votes it through
6 this process of all stakeholders and then
7 decide, you know, based upon the
8 recommendation of the ICT, could they accept
9 that recommendation or reject it after
10 stakeholder approval.
11 MR. LOUDENSLAGER:
12 Just to be clear, the ICT, they are 13 part and parcel of our Working Group. I've
14 made certain that they are not excluded.
15 They provide a level of independence that is
16 beneficial to us, so they're there with us.
17 PRESIDENT SUSKIE:
18 Bruce, what are your thoughts on,
19 as the Independent Coordinator Transmission,
20 the ICT, feels, hey, there needs to be some
21 changes to the tariff, that that be
22 recommended to the E‐RSC for consideration?
23 MR. REW:
24 Mr. President, is your question are
25 we willing to submit to his comments or ‐‐ I
0239
1 mean, ‐‐
2 PRESIDENT SUSKIE:
3 Well, if some of the stakeholders
4 think the ICT should have 205 filing rights,
5 since they don't want them, and so then if
6 there's something you think needs to be
7 changed, what about a process ‐‐ of course, I
8 guess we could do this to any stakeholder,
9 but a process that that be submitted to this
10 board ‐‐ committee, assuming we had 205
11 filing rights, and we could review it, 12 consider it, you know, pass something
13 unanimously and give that to Entergy to file?
14 What's your thoughts on that?
15 MR. REW:
16 Maybe I'm not thinking clearly this
17 afternoon, but I'm making sure that what
18 you're saying is that, if there's a proposal
19 for the ICT to have some limited 205 filing
20 rights?
21 PRESIDENT SUSKIE:
22 No, no, no. What do you think of
23 the concept, if you believe something needs
24 to be changed, instead of y'all having it,
25 you propose it to us, and then we determine
0240
1 whether or not to file it?
2 MR. REW:
3 Well, I think that should be part
4 of the process, that we provide our comments
5 and suggestions and changes that should be
6 made.
7 PRESIDENT SUSKIE:
8 Okay.
9 MR. LOUDENSLAGER:
10 Go ahead and go to the next page. 11 The elimination of participant
12 funding. And our feeling is, once the 205
13 issue is addressed, we can address this,
14 along with whatever other cost allocation
15 issues were directed to be tackled by the
16 E‐RSC.
17 Now, having said that, we are in
18 the process, over the next couple of months,
19 of getting ourselves and everybody else much
20 better educated on the way cost allocation is
21 done in both RTO and non‐RTO areas. And when
22 I finish up this afternoon, y'all will get a
23 taste of that at hkind of a hig level. Okay?
24 The ICT should be responsible for
25 exchanging operational and planning data and
0241
1 for coordinating with other regions on behalf
2 of Entergy. And our take on this issue is
3 that it's currently being discussed and will
4 be addressed through the AFC/ATC issue, as
5 well as the Seams issue. It's one of those
6 critical ‐‐ I think it's an issue that's part
7 of the 890 compliance process related to
8 Seams, FERC Order 890.
9 The next item is the QF put related 10 issue. You'll get a taste of that this
11 afternoon. We're going to get a lot bigger
12 drink next Friday. I've asked Entergy ‐‐
13 John is going to come in and talk to us about
14 the QF put item, as well as what's meant by
15 "flexibility." And, hopefully, we'll have a
16 much better understanding at the end of the
17 day next Friday.
18 Go ahead.
19 These are the things that we're
20 currently spending ‐‐ at least last night, it
21 appeared to me that we were spending most of
22 our time on in the Working Group and with the
23 stakeholders; the scope of the reliability
24 must‐run study, the QF put issue and
25 flexibility, the 205 rights issue and then
0242
1 the metrics issue. So those are the things
2 broadly, kind of collected, that we're going
3 to be focused on for the next month. That's
4 it.
5 Do y'all agree that those are the
6 four items that we need to be focusing our
7 attention on? Keep in mind we've got the
8 tariff ‐‐ 9 PRESIDENT SUSKIE:
10 (Talking over one another) ‐‐ of
11 the tariff filing.
12 MR. LOUDENSLAGER:
13 Yeah. And that's kind of the
14 overriding thing, and we've got ESPY working
15 on that for us right now. So...
16 PRESIDENT SUSKIE:
17 Good.
18 Jimmy, you had something about RMR,
19 that study? Because I assume y'all are going
20 to be taking that up.
21 MR. LOUDENSLAGER:
22 Yes, sir.
23 VICE‐PRESIDENT FIELD:
24 I'd like to just make a preliminary
25 statement about the RMR ‐‐ return to that,
0243
1 because I think that and the metrics are
2 critical. And at the last meeting, we
3 approved a metric that requires Entergy to
4 make quarterly reports identifying the legacy
5 units that operate at a capacity factor of
6 15 percent or higher and have a heat rating
7 in excess ofd 10,500. An I don't ‐‐ I don't 8 know whether that filing has been made or
9 not.
10 MR. LOUDENSLAGER:
11 I don't ‐‐ Commissioner Field, I've
12 seen a lot of paper over the last couple of
13 weeks. I don't think it has. But could I
14 offer something? I mean, you folks are going
15 to be meeting monthly, and it might be
16 something that you want to see more
17 frequently than quarterly.
18 VICE‐PRESIDENT FIELD:
19 I think we did quarterly because
20 they reported quarterly now. Is that
21 correct?
22 MR. HURSTELL:
23 I'm not sure we report ‐‐ I'm not
24 sure we report this particular parameter that
25 you just mentioned quarterly. My
0244
1 understanding was the first one was due ‐‐ is
2 it May 15th?
3 MR. LOUDENSLAGER:
4 I can't tell you off the top ‐‐
5 MR. HURSTELL:
6 We have no problem supplying the 7 information. We'll do it monthly, we'll do
8 it quarterly, whichever way you want to have
9 it.
10 VICE‐PRESIDENT FIELD:
11 I think ‐‐ I know I speak for
12 myself, and I think I speak for the other
13 states, but let me just tell you what we'd
14 like to focus on, because I know Mr. Hurstell
15 and Michael have explained how maybe their
16 systems differ in flexibility and so forth.
17 But just let me read out the units that we'd
18 like to focus on initially.
19 Baxter Wilson, Entergy Mississippi,
20 that's running 22 percent of the time; Gerald
21 Andrus, Entergy Mississippi, running
22 22.3 percent capacity; R.S. Nelson,
23 Entergy/Gulf States, 33.8 percent; Little
24 Gypsy, Entergy Louisiana, running
25 25.6 percent of the time. These are
0245
1 January 2008 to December of 2008 percentages.
2 Nine Mile Point, Entergy Louisiana,
3 35 percent; Sabine, Entergy/Gulf States,
4 33.6 percent; Michoud, Entergy New Orleans,
5 36.7 percent; and Lewis Creek, Entergy/Gulf 6 States, which I think that's Texas now,
7 68.6 percent.
8 There's some other ones that run
9 less, but if we could focus on those units, I
10 think that's where the low‐hanging fruit is.
11 That's good for the environment. That's good
12 for the ratepayers. And if the totals are
13 right, it's about $400 million that could
14 possibly be saved, depending on the price of
15 gas.
16 Now, I understand that, since the
17 last meeting, there has been discussions
18 between the ICT, the E‐RSC Working Group and
19 stakeholders regarding the appropriate
20 terminology to be used in identifying these
21 units. I think we need to provide clarity on
22 this issue in order to avoid slowing down the
23 process. Given the publicly available data
24 to demonstrate the historic usage of the old,
25 inefficient units, it strikes me that timely
0246
1 action is needed and justified. While we
2 debate terminology, old units keep running.
3 By definition, when a utility dispatches its
4 units out of economic order, ratepayers pay 5 more than they otherwise would. This issue
6 has troubled us for years. Entergy has
7 identified two reasons for operating these
8 old units; reliability must‐run and load
9 following.
10 Irrespective of which
11 classification an old unit falls in, its
12 characteristics are the same. They're older,
13 they're inefficient and they're costly, and
14 then they put out more emissions. The
15 analysis that needs to be done seems
16 straightforward. Identify how many hours
17 particular old units are running, input it as
18 publicly available from the Energy
19 Information Agency, the EIA, to determine
20 cost‐effective transmission solutions. If an
21 old unit is running only sparingly, it stands
22 to reason a multimillion‐dollar transmission
23 solution may not be necessary.
24 In other words, re‐dispatch may
25 make economic sense, as Mr. Hurstell showed
0247
1 us for that particular unit, given its
2 limited use; however, the historic data
3 indicates a significant number of units are 4 running for significant hours at a real cost
5 to ratepayers.
6 Our neighbors to the west, ERCOT,
7 have been quite successful in executing a
8 strategy at the wholesale energy level that
9 has reduced the use of old units in its
10 jurisdiction. If a unit is identified as an
11 RMR unit, the info ‐‐ unit's info is made
12 public, and ERCOT timely identifies a
13 cost‐effective solution. I see no reason we
14 cannot follow the same path.
15 As for old gas legacy units that
16 ETR relies on for load‐following purposes,
17 ERCOT's robust wholesale market, which is
18 facilitated by a robust transmission system
19 that we're trying to get, has driven the
20 costly, high heat rate units out of the
21 market. In other words, wholesale
22 competition has worked in that setting to
23 lower costs to ratepayers. Given Entergy's
24 2007 FERC testimony that revealed that
25 transmission accounts for only 7 percent of
0248
1 its overall production costs compared to
2 77 percent for generation, whether it's their 3 generation or purchase power, the opportunity
4 to invest dollars in transmission would
5 reduce savings in generation appears
6 significant.
7 My hope is that my fellow E‐RSC
8 Commissioners will direct the ICT and the
9 Working Group to produce a timely work plan
10 that identifies cost‐effective transmission
11 solutions for a legacy gas fleet,
12 irrespective of its particular designation.
13 And I would like to ask my fellow
14 Commission member, Ken, if they have been
15 able to reduce the average heat rate in ERCOT
16 and how it is accomplished, and are the RMR
17 units made public; in other words, do people
18 know which are RMR units and so forth?
19 SECRETARY ANDERSON:
20 The answer to your last question is
21 yes, they are, and ERCOT does have a process.
22 They typically will try tto ge a
23 transmission ‐‐ try to get a transmission
24 solution within a year, you know, of the unit
25 being designated RMR. I think there have
0249
1 been a couple of occasions where it's been a 2 little longer, but I think rarely longer than
3 two years. Over the last ten years, we've
4 retired or mothballed over 15,000 megawatts
5 of all inefficient units because they just
6 can't compete in the ERCOT market. That's
7 really an astounding ‐‐
8 VICE‐PRESIDENT FIELD:
9 That is.
10 SECRETARY ANDERSON:
11 ‐‐ you know, number, and it's
12 continuing. Just this year, I've seen ‐‐ I
13 think there have been four or five units that
14 are filed now with ERCOT to be mothballed,
15 because they're just not ‐‐ they're not being
16 called upon anymore, and the overwhelming ‐‐
17 the overwhelming majority are old gas units.
18 VICE‐PRESIDENT FIELD:
19 And they were identified as
20 reliable must‐run units?
21 SECRETARY ANDERSON:
22 Well, in some cases ‐‐ in some
23 cases, they are; in other cases, what happens
24 is, you file ‐‐ the generator files with
25 ERCOT that they want to retire or mothball,
0250 1 and then ERCOT will do a quick study to
2 determine ‐‐ you know, to determine whether
3 anything remaining, in which case they're
4 designated RMR, and they're paid under a
5 formula. But then ERCOT immediately will
6 work ‐‐ will work to get a transmission
7 solution that will allow it to be retired or
8 mothballed.
9 Generally speaking, the contract is
10 for a year at a time, the RMR contracts.
11 They can be a little shorter, but they
12 usually run about a year, or just as long as
13 it takes, you know, for ERCOT to get a
14 solution.
15 VICE‐PRESIDENT FIELD:
16 Well, I realize, as Mr. Hurstell
17 has pointed out, we may not have as viable a
18 wholesale market as ERCOT does because the
19 way we regulate it, but we do have a
20 wholesale market in Entergy's system. And
21 maybe we can't retire as many megawatts as
22 they've been able to, but when you've got
23 units running, you know, from 22 to 68
24 percent, a lot of them in the 30s, that we
25 ought to, at least, target those and see if 0251
1 there is a transmission solution, when you
2 take the fact that only 7 percent in 2007 was
3 the cost of transmission versus 77 percent.
4 We ought to see if these ‐‐ if there's
5 reasons that they have to keep running them
6 in those capacities, then we'll be
7 reasonable, but we just need to have an
8 explanation, and if there's not one, then
9 they need to see about reducing the capacity
10 that they're running at.
11 MR. LOUDENSLAGER:
12 Commissioner Field ‐‐ this is Sam
13 Loudenslager ‐‐ I want to go through the list
14 and make sure I captured the units that you
15 were focused on. Baxter Wilson, Gerald
16 Anderson ‐‐
17 VICE‐PRESIDENT FIELD:
18 Andrus, A‐N‐D‐R‐U‐S.
19 MR. LOUDENSLAGER:
20 ‐‐ Andrus, R.S. Nelson, Little
21 Gypsy, Nine Mile, Sabine, Michoud and Lewis
22 Creek.
23 VICE‐PRESIDENT FIELD:
24 That's correct. 25 MR. HURSTELL:
0252
1 Can I ask for a clarification?
2 PRESIDENT SUSKIE:
3 Sure, John.
4 MR. HURSTELL:
5 Well, first off, I welcome the
6 chance to come and talk to this group about
7 these units, like I mentioned earlier. But I
8 would like a clarification, Commissioner.
9 The names you gave were not for units. They
10 were for plants and stations. So, for
11 example, Sabine has five units. Baxter
12 Wilson has two. I just want to ‐‐ in terms
13 of the data we give you, do you want us to ‐‐
14 I always thought you were ‐‐ you were asking
15 us to give you unit‐specific information,
16 because I don't think all of the Sabine units
17 run at ‐‐ what did you say ‐‐ a 15 percent
18 capacity factor.
19 VICE‐PRESIDENT FIELD:
20 On Sabine, this chart shows
21 33 percent.
22 MR. HURSTELL:
23 Okay. But what I'm saying is, is 24 that this five units at Sabine, do you want
25 us to report based on the Sabine station, or
0253
1 do you want us ‐‐
2 VICE‐PRESIDENT FIELD:
3 I think it would be better if it
4 was per unit, because you might have some new
5 units at Sabine that I don't know about. I'm
6 just going from what the ‐‐ this percentage
7 is showing.
8 MR. HURSTELL:
9 I agree with you. It makes more
10 sense to do it by unit.
11 VICE‐PRESIDENT FIELD:
12 Right.
13 MR. HURSTELL:
14 I just wanted clarification,
15 because what that means is, when we show you
16 the numbers, if need be ‐‐ I'm not sure where
17 you got ‐‐ where the numbers come from, but
18 if we show you the numbers, we may show
19 Sabine with a different capacity factor that
20 may be higher than what you're seeing if that
21 number is based on the whole station. If we
22 give you numbers based on a smaller number of 23 units, the values are going to be different.
24 But we'll ‐‐ we'll provide you the
25 information on a unit‐by‐unit basis. I think
0254
1 that makes more sense.
2 VICE‐PRESIDENT FIELD:
3 I think that would be helpful.
4 MR. HURSTELL:
5 One clarification. You mentioned
6 the Nelson unit. That includes a coal unit,
7 so I'm assuming you don't want information on
8 the coal unit at Nelson. There are some
9 gas‐fired units at Nelson, as well, but I'll
10 exclude the coal units.
11 VICE‐PRESIDENT FIELD:
12 Well, I put ‐‐ I think we ought to
13 put them all in there. I don't know.
14 This ‐‐ this came from a publication, U.S.
15 EPA ‐‐
16 MR. HURSTELL:
17 What's the capacity factor you have
18 for Nelson?
19 VICE‐PRESIDENT FIELD:
20 For Nelson, the capacity shown here
21 is 33.8 percent. 22 MR. HURSTELL:
23 That ‐‐ that has to exclude the
24 coal.
25 VICE‐PRESIDENT FIELD:
0255
1 Right. It shows a heat rate of
2 11,959, so that doesn't ‐‐ that's not the
3 coal units or gas units.
4 MR. HURSTELL:
5 Well, the coal unit could have that
6 kind of heat rate, but the capacity factor
7 tells me it doesn't include the coal unit.
8 VICE‐PRESIDENT FIELD:
9 Okay.
10 MR. HURSTELL:
11 Okay. We'll get you ‐‐ we'll get
12 you the information.
13 PRESIDENT SUSKIE:
14 And I would say, don'te just giv
15 precise information, you know, just about
16 that. Help the Working Group study and learn
17 all the various factors.
18 MR. HURSTELL:
19 Well, don't worry about that.
20 We'll give them ‐‐ we'll give them ‐‐ 21 PRESIDENT SUSKIE:
22 And I ‐‐ and I throw this challenge
23 out to Entergy. It seems to me that ‐‐ and
24 help me understand this ‐‐ with these old
25 legacy units, they're just good, we have to
0256
1 do it, and that's it. What's y'all's
2 solution to the legacy units? More of the
3 same?
4 MR. HURSTELL:
5 Again, they provide a valuable
6 service, and when you look at the constraints
7 we have on our system ‐‐
8 PRESIDENT SUSKIE:
9 Whoa, whoa. Constraints. Does
10 that mean transmission constraints?
11 MR. HURSTELL:
12 No. All of the constraints. The
13 QF put, that's a big one.
14 PRESIDENT SUSKIE:
15 10 percent.
16 MR. HURSTELL:
17 We have ‐‐ no. That's ‐‐
18 10 percent of our energy comes from QF put.
19 If we ‐‐ if we have a QF put tomorrow, 2,500 20 megawatts, that means we need to have on our
21 system 25 megawatts of unloaded generation
22 that can respond ‐‐ 2,500, I'm sorry ‐‐
23 2,500 megawatts of generation that can
24 respond. In order for me to use the merchant
25 generators to do that, based on the bids that
0257
1 they've given us, I would need 25 merchant
2 generators operating at their minimum in
3 order to provide that flexibility. So if
4 they give me a minimum of 350 megawatts that
5 I have to take, multiply that times 25 ‐‐ and
6 I can't do that math off the top of my head,
7 but it's probably 8,000 ‐‐ I'd be buying
8 8,000 megawatts of merchant generation in
9 order to get 2,500 megawatts of flexible
10 capability, or I can rely on the legacy
11 units, where I can run a 50‐megawatt
12 legacy ‐‐ a legacy unit at 50 megawatts and
13 have 400 megawatts of flexible capability.
14 PRESIDENT SUSKIE:
15 How often do you get
16 2,500 megawatts put on the system?
17 MR. HURSTELL:
18 That's probably the peak, but 19 probably 1,500 to 2,000 is probably a good
20 daily number, 1,500 to 2,000.
21 PRESIDENT SUSKIE:
22 Daily?
23 MR. HURSTELL:
24 Yes. Oh, yes.
25 PRESIDENT SUSKIE:
0258
1 And then the question is: Is there
2 a way to solve the problem with the QFs
3 through state Commissions?
4 MR. HURSTELL:
5 We have ‐‐ we've tried. We've ‐‐
6 PRESIDENT SUSKIE:
7 That's never been before the
8 Arkansas Commission. We don't have the QF
9 that Louisiana has.
10 MR. HURSTELL:
11 We have one QF in Arkansas. We've
12 worked with the LPSC. Mr. Zimmering worked
13 with us. He ‐‐ it was his solution. He came
14 up with a solution that I thought was very
15 effective. We supported it 100 percent. But
16 the QFs weren't interested. They had the
17 option, and they haven't been willing to get 18 that out.
19 PRESIDENT SUSKIE:
20 Anything else, Sam?
21 MR. LOUDENSLAGER:
22 (Shakes head.)
23 PRESIDENT SUSKIE:
24 With that, let's take a ten‐minute
25 break and come back.
0259
1 (Recess.)
2 PRESIDENT SUSKIE:
3 As y'all know, as I think Sam
4 pointed out, it seems a lot of these issues
5 relate to cost allocation and construction
6 plans, other things. So as a result, we have
7 ‐‐ meant to do this last month, but we
8 somewhat ran out of time, and so we're going
9 to have a couple presentations about various
10 cost allocation methodologies. To let you
11 know, as a member of the SPP RSC, this is, by
12 far, one of the most challenging issues that
13 are out there.
14 Sam and the cost allocation Working
15 Group within SPP sent ‐‐ spent months trying
16 to come up with a balanced portfolio to be 17 spread evenly, those costs, because the
18 benefits would have been evenly throughout
19 the system. Recently, SPP ‐‐ and I think
20 they filed earlier this week or last week,
21 their RT ‐‐ this week, a RTO tariff to
22 allocate the costs across the system. 300 kV
23 and above is spread equally based upon load.
24 Below that, it's two‐thirds.
25 Kind of interesting, what I always
0260
1 thought, is that's very similar to how
2 Entergy allocates its costs among its
3 operating companies. It's based upon load.
4 For those 230 and above, it's spread based
5 upon load. It's different below that.
6 And, clearly, this is one of the
7 most challenging things, as the 7th Circuit
8 opinion regarding FERC points out, and this
9 is ‐‐ and I would encourage everybody ‐‐
10 Sam, is that the ‐‐ did twe pu that
11 on the ICT ERC Web site, the cost allocation
12 summary ‐‐ what is it ‐‐ PJM did?
13 MR. LOUDENSLAGER:
14 Yeah. Ben and Jay found that on
15 the PJM Web site on a cost allocation ‐‐ 16 Primer.
17 PRESIDENT SUSKIE:
18 Primer?
19 MR. LOUDENSLAGER:
20 Yeah. And we made it available on
21 the Web site, I believe.
22 MR. BRIGHT:
23 I e‐mailed the link out after the
24 March 18th meeting.
25 PRESIDENT SUSKIE:
0261
1 I would encourage anybody that has
2 a chance ‐‐ I think it is just great. I
3 mean, it analyzes ‐‐ you know, how you track
4 benefits is incredibly hard, because if you
5 build a line, somebody may benefit
6 economically from it, but somebody else may
7 benefit reliability from it. It's a great
8 paper, because there is no precise answer to
9 cost allocation, and, therefore, I look
10 forward to hearing the presentations so we
11 can learn more.
12 MR. BRIGHT:
13 I appreciate you covering my first
14 two slots. 15 PRESIDENT SUSKIE:
16 I'm not going to cover any more.
17 VICE‐PRESIDENT FIELD:
18 I request permission to walk
19 around. I've been standing up for a while.
20 PRESIDENT SUSKIE:
21 Granted.
22 MR. BRIGHT:
23 Okay. Anyway, I appreciate this
24 opportunity. I actually got to learn a lot.
25 I didn't know a whole lot about cost
0262
1 allocation. Over the last couple of months,
2 I've certainly learned a lot.
3 MR. LOUDENSLAGER:
4 You'll learn a lot more.
5 MR. BRIGHT:
6 And I'll learn a lot more, I guess,
7 in the process as we go forward. As Sam
8 talked about earlier ‐‐ I just want to make
9 sure ‐‐ you know, it's just for education,
10 and I hope you guys find it useful. And it
11 is a ‐‐ it is a ‐‐ I used that PJM document
12 that you referenced pretty much as the basis
13 for the presentation, so I got it not long 14 before that March meeting, and I found it
15 pretty useful. It sort of mimicked some of
16 the other research I did. I set it up kind
17 of like that document.
18 Anyway, I'm on this slide. We're
19 on slide 2, for people who are still on the
20 phone. There's really a couple of different
21 major ways that cost allocation ‐‐ the debate
22 around cost allocation. It's really around
23 whether or not the beneficiary pays or
24 there's some socialization on costs. And the
25 beneficiary pays really just refers to those
0263
1 entities that receive the bulk of the benefit
2 pay the bulk of the costs, and socialization
3 really is ‐‐ just goes on the notion that
4 things like reliability are shared by an
5 entire system, so those costs then should be
6 shared by everyone.
7 A couple of different ‐‐ couple of
8 main types of socialization costs, and that's
9 bullet points 2 and 3 on this slide. It's
10 really just either by an amount of megawatt
11 usage across the entire footprint or more on
12 some peak consumption usage. 13 PRESIDENT SUSKIE:
14 Now, I would like to ask Entergy ‐‐
15 now, am I accurate that 235 kV and above
16 transmission across Entergy operating's
17 company is divided based upon load? Is it
18 230 kV and above?
19 We'll come back to that, okay, when
20 they come back.
21 Correct me if I'm wrong. Then,
22 below that, is situs, based on which
23 jurisdiction that it's built in pays for
24 that. That's my understanding. I guess
25 we'll wait for Kim.
0264
1 MR. HURSTELL:
2 Yeah. You have the B team here
3 now.
4 PRESIDENT SUSKIE:
5 Okay. Let's ask the tough
6 questions now.
7 MR. CAMET:
8 Non‐system agreement team.
9 MR. HURSTELL:
10 I believe that's correct, though.
11 PRESIDENT SUSKIE: 12 Okay.
13 MR. BRIGHT:
14 Okay. And then as far as the
15 beneficiary payback, there's a couple of
16 different ways that they talk about it in
17 this document, and they're both calculations,
18 either based on a flow basis and then on a
19 monetary impact, where they go through some
20 studies and define who derives most of the
21 benefit on a given facility or a given
22 upgrade, and then they assign benefits that
23 way. Let me go back.
24 I think another good point is in
25 the U.S., generally, it's always assessed to
0265
1 load, where, internationally, some countries
2 have moved to where they assess costs to
3 generation. So I think, if I'm not mistaken,
4 MISO is working through a injection
5 withdrawal method that I think would sort of
6 get into assessing and allocating costs to
7 the generation. So as far as I know, that
8 would be the first in the U.S.
9 As Chairman Suskie said, no one
10 version of either one of those four methods 11 seems to work anywhere, so it's always ‐‐
12 it's mostly a hybrid method in all of these
13 situations. So what I was going to do is
14 just kind of walk through the different RTOs
15 and ITOs and kind of talk a little bit about
16 their methods.
17 So, first of all, Cal ISO, they
18 have a 200 kV and above breaking point, and
19 so anything ‐‐ and this is ‐‐ for them, it's
20 both on reliability and economic projects.
21 They don't make a real distinction. So
22 anything 200 kV and above are shared across
23 the entire footprint on a megawatt basis. So
24 it's on a use basis. And then anything below
25 200 kV is then assigned to the specific
0266
1 utilities on an access charge basis. Okay?
2 MR. McCULLA:
3 Could I ask a question here?
4 MR. BRIGHT:
5 Sure.
6 MR. McCULLA:
7 Is transmission service request
8 covered in that first bullet over there, or
9 is that a different ‐‐ do they handle it 10 differently; do you know? Like, if a
11 transmission service request comes in and
12 requires an upgrade, is it covered under that
13 first thing?
14 MR. BRIGHT:
15 I believe so, but I'm not exactly
16 sure. I can follow up on that if I need to.
17 And I wasn't sure if anybody was
18 interested in the generation interconnection
19 side, but for CAL ISO, they generally assign
20 it directly to the interconnecting facility,
21 but they do have this location constrained
22 resource interconnection facility for remote
23 areas where they allow some socialization of
24 the upfront costs until that generator comes
25 online. And then they ‐‐ and then it's ‐‐
0267
1 anything after that is then assigned.
2 ISO New England, they have a 115 kV
3 sort of breakpoint, where anything above 115
4 kV is assigned on a peak megawatt usage, and
5 anything below 100 kv ‐‐ or 115 kV is
6 localized to a specific zone. And their
7 economics ‐‐ again, for economic projects,
8 they do it through a cost/benefit or cost ‐‐ 9 yeah, a cost/benefit evaluation, and looking
10 at the net present value of benefits and
11 costs, and then once it passes that test,
12 then they're allocated just like their
13 reliability projects. And then generation
14 interconnect again, as most of them, they are
15 100 percent responsible ‐‐ or 100 percent of
16 the cost to the interconnection facilities.
17 MISO ‐‐ and this is what's
18 currently approved at MISO. I said before,
19 they're in discussions now of doing some
20 changes to their cost allocation, looking at
21 that injection withdrawal method, and I think
22 a couple other things they might be looking
23 at, as well. But they have a 345 and above
24 where it is allocated 100 percent to the
25 load, and then, of that allocation,
0268
1 20 percent of it is allocated based on a
2 monthly peak megawatt usage, and the other
3 80 percent are calculated on a flow base
4 calculation of some line outage distribution
5 factor calculation. And then below 345 kV
6 are all done on a subregional basis, so
7 they're assigned out to their subregions 8 based on ‐‐ based on a flow basis.
9 So that was just for reliability
10 projects, and then economic projects, they go
11 through an analysis where they look at
12 benefits over a ten‐year period, and they
13 weight those ‐‐ they weight the changes to
14 production costs over that ten‐year period
15 and also their LMPs. So, again ‐‐ and then
16 they break it up into the same kind of 80/20,
17 where 20 percent of those costs are then
18 allocated on that ‐‐ on that peak monthly
19 points of megawatt usage, and then other
20 80 percent to the subregions based on a
21 monetary metric of benefits, so ‐‐ of the
22 annual benefits.
23 And then their generation
24 interconnection, some of them are a little
25 bit different. For 345 kV and above, they ‐‐
0269
1 90 percent of those costs are assigned
2 directly to the ‐‐ to the interconnecting
3 facility or the developer, and then
4 10 percent are allocated system‐wide on a ‐‐
5 on a monthly peak basis, and anything below
6 345 is assigned directly to the 7 interconnection facility.
8 And then there's some other rules
9 around. If you're interconnecting with the
10 American Transmission Company, ITC, Michigan
11 Electric or ITC Midwest, then 50 percent of
12 costs are allocated like reliability
13 projects, and the other 50 percent are
14 directly to ethe zon of interconnection.
15 PJM, they actually ‐‐ they have a
16 500 kV and above breaking point, which is the
17 highest one I've seen out there as far as
18 breaking point goes, and they ‐‐ so then they
19 allocate anything above 500 or above, and
20 that includes lower voltage products ‐‐ or
21 projects that are out there in support of a
22 500 kV project or above 500 kV. They will
23 allocate those 100 percent based on the zonal
24 share on a non‐coincident peak, and then
25 below 500 kV, if it's ‐‐ they go through a
0270
1 cost breakdown. If it's more than
2 $5 million, they do it on a flow‐based
3 factor. And then if it's less than
4 $5 million, they allocate it to the load
5 specifically in that zone of the upgraded 6 facility.
7 And then for economic projects,
8 anything over 500 kV or above, they allocate
9 exactly like reliability, and as they go
10 below 500kV, if it's an acceleration project
11 of an approved ‐‐ something that's already on
12 a reliability plan, then they allocate that
13 on a benefit calculation, and anything where
14 it's a modification ‐‐ so it's not the same
15 project, but maybe a different project ‐‐ to
16 an approved reliability project, then they do
17 that on a flow base factor. And, again, for
18 GI studies, it's 100 percent to the
19 interconnecting facility.
20 What I put up here for SPP is
21 actually what is currently in place, but
22 then, as Chairman Suskie pointed out this
23 week, they filed at FERC what's known as the
24 Highway Byway Plan. And the details of that
25 are actuallyP on the SP work Web site, on the
0271
1 main page, of what's been filed, both the
2 filing and kind of description of exactly
3 what's filed.
4 And in the Highway Byway, I'll talk 5 about that one. It's the same for both
6 reliability and economic projects. There's a
7 300 kV breakpoint, where anything 300 kV or
8 above is allocated across the entire
9 footprint on a load ratio share basis, and
10 then anything below 300 kV is actually
11 allocated onto ‐‐ between a regional and a
12 zonal charge. So between 100 kV and 344 kV,
13 I think it's 67 percent regional, 33 percent
14 zonal; and then below 100 is 100 percent
15 zonal. And I might have had those backwards,
16 but I think ‐‐ I think that's right.
17 And then as far as generation
18 interconnection, they have a couple of
19 different breakpoints on a cost per megawatt
20 being interconnected and also wind versus
21 nonwind, and then that hasn't changed there.
22 So anything in excess of $180,000 in megawatt
23 capacity is allocated directly back to the
24 facility, and then less than that, whether
25 it's wind or not, are allocated somewhat
0272
1 differently.
2 New York ISO, so they're a little
3 bit different than the others, in that they 4 directly assign the costs of upgrading for
5 reliability projects to the zone that has a
6 reliability violation. And if it happens to
7 be a New York ISO‐wide violation, then they
8 will go ahead and assign that out to the full
9 footprint.
10 And then as far as economic
11 projects, they do a cost/benefit analysis,
12 and then the costs are allocated to the zones
13 who receive the benefit, but they have one
14 little other mechanism they use, in that they
15 have the LSEs have to vote on economic
16 projects, and it takes 80 percent of the LSEs
17 voting in favor for that to continue ‐‐ for
18 that project to move forward.
19 And as far as GI studies go,
20 generally, the developers are 100 percent
21 responsible, but they do allow, if you build
22 generation interconnection upgrades and that
23 they have additional capacity, once that
24 capacity is used, you can get reimbursement
25 for that capacity.
0273
1 Bill?
2 MR. BOOTH: 3 Yeah. Just to clarify that a
4 little bit more, what happens in New York is
5 if a generation project ‐‐ if an upgrade
6 associated with a generation project will
7 replace the need for a reliability project
8 either that year or in the future, then the
9 generation developer is going to get a
10 credit, because, obviously, the upgrade has
11 also replaced reliability concerns. So, for
12 example, if the generator's interconnection
13 project will cost $20 million and replace it
14 with a $10 million reliability project, then
15 the generator only has to pay the
16 $10 million.
17 MR. BRIGHT:
18 ERCOT, it's pretty easy. Again,
19 all the reliability and economic projects
20 have to be approved by the Commission, and
21 then the costs are allocated based on a peak
22 megawatt usage between the months June and
23 September, peak months. And then for GI
24 studies, it's 100 percent to the
25 interconnection ‐‐ interconnecting facility.
0274
1 That was all. That are all the 2 RTOs and ISOs. So I don't know if you'd like
3 some additional detail on that. Again,
4 there's a lot of detail in that PJM report.
5 PRESIDENT SUSKIE:
6 One question I have: Obviously,
7 there's been a lot of, you know, concerns
8 raised by stakeholders about the Attachment T
9 and the economic investments on the Entergy
10 system, and the argument is that the way the
11 current Attachment T works ‐‐ well, it was
12 said that no economic projects are built.
13 We've learned today, no, there's one built
14 and two being built. The question I have is,
15 how many other areas in the country have that
16 type of cost allocation for economic
17 upgrades?
18 MR. BRIGHT:
19 So where it's, like, 100 percent
20 participant funded? Is that ‐‐
21 PRESIDENT SUSKIE:
22 Yeah.
23 MR. BRIGHT:
24 I could be wrong, but ‐‐
25 PRESIDENT SUSKIE:
0275 1 It's just something I'm curious
2 about. I don't know if Entergy has that
3 answer. I just wonder how many other regions
4 or places in the country use that.
5 MR. CHILES:
6 It's on the next presentation.
7 PRESIDENT SUSKIE:
8 Okay. Great. Stay tuned.
9 Any questions?
10 Yes, sir.
11 MR. DODSON:
12 I've got a question. Thanks for
13 the presentation. I think one point that ‐‐
14 some information that may be ‐‐ I'm sorry;
15 Terry Dodson, Cottonwood Energy ‐‐ is that
16 for the regions that have a bifurcation of
17 how the costs are allocated (inaudible) is go
18 back and determine how that percentage amount
19 was developed. Being a member of the
20 participants of the different parties that
21 did this way back when, it's really good to
22 represent how and why those decisions were
23 made and the issues that were used to make
24 those.
25 PRESIDENT SUSKIE: 0276
1 I will bet Sam will say SPP did it
2 very painfully.
3 MR. LOUDENSLAGER:
4 Well, I was going to actually say
5 that it was a process of negotiation within
6 SPP, and you know how that goes. The
7 position you take ine th negotiation depends
8 on kind of whatever your philosophy might be
9 at the time. And back three years ago, there
10 was a push for ‐‐ by some of the states to
11 endorse beneficiaries' pays as the
12 appropriate approach, and in order to move
13 away from 100 percent of that, you wind up
14 with a 33/67 percent. Okay? What's ‐‐
15 what's significant now is ‐‐ in the SPP is
16 that the philosophy, at least amongst the
17 state regulators, has significantly shifted.
18 And recognizing that transmission ‐‐ it's
19 harder and harder to distinguish reliability
20 versus economic upgrades, and ‐‐ because,
21 over time, it's all reliability, you know, so
22 it's kind of a short‐term versus long‐term
23 view of how you allocate those costs, which
24 is one of the reasons that the RSC decided to 25 go the Highway Byway approach.
0277
1 Now, having said that,
2 traditionally, the one metric that was
3 evaluated in SPP was changes in production
4 costs, savings in production costs, you know.
5 That's your benefit/cost metric. And they've
6 expanded that now to look at other metrics,
7 and all of that is just kind of a
8 philosophical change, Terry. It's ‐‐ so
9 that's SPP. It was a negotiated number, and
10 my understanding, MISO is going through that
11 same process of negotiation right now, and
12 it ‐‐ as Paul said, it is painful.
13 MR. DODSON:
14 That's important.
15 MR. LOUDENSLAGER:
16 When we did try to focus on
17 something other than the traditional approach
18 to economic projects in the SPP is where we
19 came up with the balanced portfolio, and that
20 took about 18 months to do all the analysis
21 and come up with a portfolio of economic
22 projects that would ensure that benefits were
23 spread out across the region. In a lot of 24 cases, that meant shifting revenue
25 requirement around, which is ‐‐ God help the
0278
1 accountants. I mean, so I don't know if
2 that's helpful for you or not, Terry.
3 MR. DODSON:
4 It was.
5 PRESIDENT SUSKIE:
6 Anything else?
7 Do you have anything to add, Bruce?
8 MR. REW:
9 No.
10 PRESIDENT SUSKIE:
11 You're just guilty of holding the
12 microphone.
13 SECRETARY ANDERSON:
14 One clarification with respect to
15 ERCOT ‐‐ and you're correct that the
16 Commission does ‐‐ if the Commission approves
17 it, then it's ‐‐ then it's uplifted. We
18 don't socialize in Texas. We uplift. It's a
19 critical role of ERCOT in the evaluation
20 process, even though it's not ‐‐ it's not
21 formally really baked into our rules. The
22 fact of the matter is that, if ERCOT doesn't 23 recommend a project, you know, either for
24 reliability or economic reason, then it
25 doesn't get built. That really provides, you
0279
1 know, 80 percent of the ‐‐ of the basis for
2 need when the Commission ‐‐ when the
3 Commission evaluates the application.
4 PRESIDENT SUSKIE:
5 Good point.
6 Anything else?
7 (No response.)
8 All right. John?
9 MR. CHILES:
10 Okay. Thank you. Talk a little
11 bit about non‐RTO regions. Going to our
12 first slide, basically, to give you an idea
13 of what I'm talking about is everything that
14 is not colored in, so we're dealing with the
15 west less Cal ISO and then the SERC region,
16 then FRCC are the only places where we're not
17 dealing with the RTO, and we tried to pick
18 some high points of each of those regions to
19 talk about today.
20 Northwest, a lot of utilities out
21 there. What happens in the northwest is the 22 WECC is the coordinator of all the regions.
23 There's actually two planning processes
24 there, and there's another Planning
25 Coordination Committee, the PCC, and there's
0280
1 a Transmission Expansion Planning Policy
2 Committee, and those drive the discussions of
3 reliability on the projects. Within those,
4 there are actually working groups that get
5 together and that make decisions on projects
6 throughout the region.
7 I think one example here is
8 Northern Tier Transmission Group. It's made
9 up of about seven utilities that cover a good
10 portion of the northern part of WECC. And
11 what they do is, in their contract, they do a
12 direct assignment of the cost of the line to
13 the beneficiaries. It's important to note,
14 in the west, because of the topology of the
15 system, that you have very long lines and
16 loads scattered abroad, that out west
17 multiple entities do own the same piece of
18 wire.
19 So, for instance, you could have ‐‐
20 three or four entities all could agree, we're 21 going to fund the line from point A to point
22 B. They will each fund that, and they will
23 each get associated rights to that facility,
24 and they will invoke tariffs to collect
25 revenues for that.
0281
1 So I think it's important to know
2 in all these non‐RTO environments the
3 topology of the system and how the new
4 planning really drives the majority of the
5 cost allocation discussion. And for economic
6 reliability projects, you know, it's the same
7 thing with this Northern Tier Group.
8 There is one interesting thing out
9 west. The State of Wyoming actually formed a
10 quasi‐governmental agency called the Wyoming
11 Infrastructure Authority, and it actually
12 allows the state to fund, own, operate
13 transmission facilities to benefit ‐‐ you
14 know, benefit the state. They've got a
15 billion dollars of bond authority set aside
16 given to them by the legislature, and the
17 State Treasurer is authorized to purchase
18 those bonds back. And they are in the
19 process of proposing ‐‐ I think there's about 20 seven projects that they have proposed that
21 are on the drawing board for them to consider
22 funding. So even out there, you know, the
23 state does have the ability to get into the
24 transmission business, you know, which is not
25 something we usually see.
0282
1 The eastern half, you know, once
2 again, looking at SERC and FRCC, we probably
3 have a couple here. We've been all over this
4 before, so we'll skip on to something else,
5 just as a comparison.
6 On the Southern, it's very simple.
7 Basically, the costs are allocated to all
8 users. It's a very clean process. There's
9 no real distinction on reliability or
10 economic upgrades. There is one wrinkle in
11 the Southern, which is the Georgia ITS.
12 PRESIDENT SUSKIE:
13 Could you further explain how
14 Southern Company does it?
15 MR. CHILES:
16 Well, in Southern ‐‐
17 PRESIDENT SUSKIE:
18 When you say ‐‐ so when it's 19 allocated to all users, that includes, like,
20 companies other than Southern?
21 MR. CHILES:
22 Well, what can happen is, it's
23 going to all ‐‐ basically, it's part of the
24 Revenue requirement. It's rolled into the
25 Revenue requirement. And then those costs
0283
1 are paid by all customers, all users of the
2 grid.
3 PRESIDENT SUSKIE:
4 So if you have, say, a
5 municipality, like, say, the City of
6 Jonesboro that's inside the grid of Southern
7 Company, would they be allocated costs?
8 MR. CHILES:
9 If it's ‐‐ if it's taking delivery,
10 they would be. That's correct.
11 PRESIDENT SUSKIE:
12 And it's not based upon what they
13 actually receive, but just what their load
14 is?
15 MR. CHILES:
16 Based on the load, that's correct.
17 PRESIDENT SUSKIE: 18 That's all upgrades, economic and
19 reliability?
20 MR. CHILES:
21 Yes. That's correct.
22 MR. BOOTH:
23 How does Southern distinguish
24 between reliability and economic?
25 MR. CHILES:
0284
1 Part of this fits into the
2 Southeastern Interregional Process, the new
3 process, and they're now making a distinction
4 in that. But even within that process, they
5 still say that all of these will rely upon
6 their own tariff and their own cost
7 allocation for the region, whether it's a
8 reliability or economic project. So Southern
9 really doesn't make any distinction within
10 the Southeastern Interregional Process, of
11 which Southern is a member and involved. Any
12 projects that come out of that, they would
13 fund, the same way they do the reliability
14 projects.
15 MR. BOOTH:
16 How do they distinguish between 17 reliability and economic?
18 MR. CHILES:
19 That's the Southeastern Process,
20 and that's done through them looking at
21 potential transfer capabilities between, say,
22 Entergy and Southern as a whole, stakeholder
23 process, which picks economic projects to
24 evaluate. They evaluate those projects to
25 the extente that peopl believe that those are
0285
1 feasible. Then there's a discussion about,
2 you know, construction and cost allocation at
3 that point.
4 PRESIDENT SUSKIE:
5 Could you explain again economic
6 upgrades?
7 MR. CHILES:
8 Well, economic in the Southern
9 Company really relates to projects proposed
10 which go across the region that aren't really
11 tied to a line with any purpose. For
12 instance, you know, like I said, the
13 Southeastern Interregional Process is the
14 best example they have of an economic study
15 process, very similar to what you have in ‐‐ 16 with the ICT on the economic studies being
17 done through ISTEP. It's a very similar
18 concept.
19 And what they would look at is,
20 people would say, we want to look at the
21 possibility of doing large bulk transfers
22 from, you know ‐‐ say, you know, TVA to Duke
23 that made up all facilities in Southern.
24 There's not a reliability basis for it, but
25 it's a ‐‐ but it's just a general transfer
0286
1 type study. And if there's any projects that
2 fall out of that that would be in the
3 southern border, then those would be
4 considered an economic project in Southern.
5 PRESIDENT SUSKIE:
6 And so how does the economic
7 upgrades differ than what's in the Entergy
8 system, comparing Southern to Entergy, or am
9 I getting too detailed?
10 MR. CHILES:
11 You're probably getting a little
12 detailed, because, in Entergy, of course, we
13 have the Attachment T and the financial
14 flowgate rights and all that that goes on, 15 and we don't have that. Southern doesn't
16 have that mechanism.
17 PRESIDENT SUSKIE:
18 Okay. Thanks.
19 MR. CHILES:
20 We can certainly get you more
21 detail on that.
22 The ITS is a little different
23 animal within Southern, because back in the
24 '70s, there was a situation where Georgia
25 Power actually sold part of its transmission
0287
1 system to these other entities. Within that,
2 you've got four entities who own pieces of
3 the Georgia Power Transmission System, which
4 would be Georgia Power, Municipal Electric
5 Agency of Georgia, City of Dawson and Georgia
6 Transmission Corporation. And their
7 allocation of costs is based upon their
8 percent load. They're required to maintain a
9 percentage, you know, ownership of the grid.
10 They do a joint reliability planning process,
11 and out of that, companies then allocate
12 those projects based upon maintaining their
13 other economic, you know, ratios that they've 14 maintained in the past and then to the extent
15 that they, you know, move projects up or back
16 when there is either a savings or a shared
17 cost to those upgrade changes.
18 On looking at the big picture,
19 we're looking at Duke and Progress Carolinas.
20 For them ‐‐ their cost is ‐‐ you know,
21 there's no type of sharing in itself ‐‐ you
22 know, Duke's costs get rolled into their
23 rates, and they get shared amongst all
24 their ‐‐ all their users. There's no
25 distinction between economic and
0288
1 reliability‐based projects. You've got a
2 North Carolina Planning Transmission
3 Collaborative Process, and even in that, you
4 know there's joint planning amongst the
5 entities in the State. There's still no ‐‐
6 no distinction on how they do their funding.
7 MR. BOOTH:
8 Does that includer requests fo
9 transmission service?
10 MR. CHILES:
11 That does.
12 MR. BOOTH: 13 So they don't employ work
14 [phonetic] pricing? If a transmission
15 customer wants to interconnect with the
16 system, the transmission customers just
17 charge the embedded cost rate?
18 MR. CHILES:
19 The interconnection, I think, is a
20 different ‐‐ is a different animal.
21 MR. BOOTH:
22 I'm talking about transmission.
23 MR. CHILES:
24 In this forum, there was no
25 distinction. I'd have to ‐‐ we'd have to go
0289
1 back and look a little harder to verify that,
2 but I can get you that information.
3 MR. BOOTH:
4 Thanks.
5 MR. CHILES:
6 In Florida, it's kind of a modified
7 Highway Byway type proposal. Basically, they
8 have a 500 kV back line system in the State.
9 Everything is 230 kV and below. So for
10 reliability projects identified through the
11 Joint Planning Process that FRCC employs, 12 anything that's greater than 230 kV is
13 allocated to all the transmission operators
14 on a ‐‐ on a load ratio share basis.
15 Anything less than that falls under the
16 additional transmission operator's own
17 tariff.
18 So they do have a semblance of a
19 Highway Byway. It has not been applied. I
20 don't think FRCC has built a 500 kV line in a
21 number of years, so it would be a lot, I
22 think, before there was actually inputs of
23 how this is going to work. And that's really
24 about it on non‐RTO regions.
25 PRESIDENT SUSKIE:
0290
1 Thank you.
2 Questions?
3 Yes, sir.
4 MR. DODSON:
5 Terry Dodson, Cottonwood Energy.
6 John, all the ones you just went through, can
7 you give a description of who participates in
8 those processes to determine what the
9 upgrades are and how they're applied?
10 MR. CHILES: 11 Sure. You know, thinking from a
12 stakeholder perspective, probably the western
13 model is the one that has the most customer
14 participation out there. You have
15 transmission customers, you have generators,
16 you have incumbent utilities that participate
17 in the planning processes most times. In ‐‐
18 in FRCC, that's usually the transmission
19 owners themselves are doing the planning
20 through the FRCC planning process, and
21 there's not a lot of, you know, participation
22 from the generators. Usually, that's on just
23 the transmission owners themselves.
24 In Southern, the planning really
25 takes place through the ‐‐ Southern has its
0291
1 own independent planning process for their
2 reliability needs. They're not factoring in
3 the other entities. The Georgia ITS is a
4 joint process with all four companies that do
5 that, that plan for the State of Georgia.
6 PRESIDENT SUSKIE:
7 Any other questions?
8 Commissioners?
9 (No response.) 10 So, Sam, will you answer my
11 question I had before?
12 MR. LOUDENSLAGER:
13 What was it?
14 PRESIDENT SUSKIE:
15 The question is: Does anybody else
16 have a cost allocation methodology for
17 economic upgrades as Entergy does?
18 MR. LOUDENSLAGER:
19 No. I mean, I think there are just
20 nuances to them all.
21 I had a question, though. Do state
22 ‐‐ John, do state regulators participate in
23 any of these planning processes in the
24 non‐RTO areas?
25 MR. CHILES:
0292
1 The only place I'm aware of that
2 does that would be in the west. They have
3 the ability to participate in the western
4 process and being involved in those planning
5 groups.
6 Now, certainly, in ‐‐ you know, in
7 Florida, the Florida Commission does have the
8 ability, through the Transmission Line Siting 9 Act, to be involved after the fact in
10 assessing, you know, the need for
11 reliability.
12 MR. LOUDENSLAGER:
13 So kind of a prudence?
14 MR. CHILES:
15 Yes.
16 MR. LOUDENSLAGER:
17 Okay. And what about the
18 Carolinas?
19 MR. CHILES:
20 The argument they have is this
21 North Carolina Transmission Collaborative,
22 and that's a NCUC.
23 MR. LOUDENSLAGER:
24 Oh, okay.
25 MR. CHILES:
0293
1 (Talking over one another) by its
2 commission‐established process so they have
3 oversight over that process.
4 MR. LOUDENSLAGER:
5 Okay. Thank you.
6 MR. CHILES:
7 Commissioner, to get to your 8 question, the only place really that has
9 anything, you know, remote, as far as direct
10 assignment and then having some type of
11 rights would be out west. The difference
12 there is, is they're actually getting a
13 physical right to the asset that they are
14 purchasing, as opposed to a flowgate
15 financial right in Entergy.
16 MR. LOUDENSLAGER:
17 So just to be clear that I
18 understand what you just said, out in the
19 western regions, the entities that fund an
20 upgrade or pay for a facility are assured
21 ythat the will be able to move power along
22 that facility?
23 MR. CHILES:
24 That's correct. They're
25 actually ‐‐ as part of that dollars they
0294
1 spend, they're actually getting rights to
2 that asset.
3 MR. LOUDENSLAGER:
4 Thank you.
5 PRESIDENT SUSKIE:
6 Any other questions? 7 Sam?
8 MR. LOUDENSLAGER:
9 No. I just wanted to thank both
10 Ben and John, because I had reached out to
11 both of them to do this, so I appreciate
12 that.
13 PRESIDENT SUSKIE:
14 We appreciate y'all helping educate
15 us. As you can see, it's a difficult issue
16 and a lot of options and alternatives.
17 Is there anything else?
18 (No response.)
19 Well, does anybody have any
20 announcements they wish to make?
21 (No response.)
22 Our next meeting is scheduled for
23 May 12th and 13th. Now, refresh my memory or
24 correct me if I'm wrong. The 12th, it will
25 begin in the afternoon after the SPC meets,
0295
1 and we anticipate then we can convene the
2 next morning and go into about noon. So it's
3 a two‐day meeting. We'll have two half‐day
4 sessions, and we'll be in Commissioner
5 Field's jurisdiction, so we expect the best 6 treatment possible.
7 MR. LOUDENSLAGER:
8 Can we take ‐‐ can we take another
9 minute and just kind of go through the list
10 of action items that ‐‐ developed over the
11 course of the rest of the day?
12 PRESIDENT SUSKIE:
13 Yeah, please.
14 MS. SCHMIDT:
15 The first item was a request for
16 Entergy to work with the Working Group to
17 discuss their proposal on the 205 filing
18 rights, and, in particular, the referral
19 language. The Working Group will also work
20 with stakeholders, SPP and Entergy, to
21 provide a proposal for the May meeting to
22 present to the E‐RSC that would include,
23 perhaps, a larger scope than what was
24 presented today, and we are to include some
25 options that would allow the ICT in their own
0296
1 discretion to present issues they identify
2 that they would propose to the E‐RSC to
3 direct a filing going forward.
4 The transmission siting matrix, 5 I'll be making a couple of changes to that
6 for the Arkansas deadlines and the timing of
7 rate base for Texas.
8 The E‐RSC Working Group meetings,
9 we may reschedule the May 18th face‐to‐face
10 meeting. Sam will be sending something out
11 regarding that. SPP will check into the cost
12 of providing the WebEx access for the
13 stakeholder face‐to‐face meetings with E‐RSC
14 Working Group.
15 Three supplemental ‐‐ on the three
16 supplemental upgrades that were identified,
17 Entergy is to provide the source and synch of
18 those upgrades that were referenced in the
19 data response.
20 In regards to the WPP purchases,
21 what data is provided to FERC in the
22 electronic quarterly reports, and the Working
23 Group will take that on. The E‐RSC has asked
24 Entergy for a explanation on the rejections
25 of the short‐term and monthly bids. ESPY
0297
1 will review the original WPP order for what
2 benefits may have been identified and present
3 that back against some of the analysis that's 4 been provided.
5 And if the request has already not
6 gone to Entergy, the E‐RSC Working Group will
7 request the Entergy operating guides required
8 for the Entergy ‐‐ for Entergy's flexibility.
9 We couldn't remember if we included that in
10 that last go‐around, Mark.
11 MR. McCULLA:
12 Okay.
13 MS. SCHMIDT:
14 And then regarding the RMR issue,
15 Commissioner Field asked for Entergy to file
16 with the E‐RSC Working Group a report that
17 identifies the megawatt hours produced by
18 each of Entergy's legacy oil and gas
19 generation units that operate under a lower
20 capacity factor and having a higher heat rate
21 than 10,500. The specific units of interest
22 are the ones that Sam mentioned earlier.
23 Also to be included in the reports is an
24 explanation of why those units were running.
25 Was it due to RMR? And if it wasn't due to
0298
1 RMR, under what must‐run requirement were
2 they running? Was it for load following? 3 Otherwise, provide a reason for those units
4 to be on line. Also to be included, once
5 studied, is a request for what transmission
6 solutions could mitigate the use of those
7 plans, and that's a longer‐term request.
8 And I believe that's all. I had
9 Was there anything that might have been
10 missed?
11 PRESIDENT SUSKIE:
12 I think John has a comment.
13 MR. HURSTELL:
14 Did you say you wanted a reason for
15 every ‐‐ why every unit was operating ‐‐
16 every one of those units was operating?
17. MS SCHMIDT:
18 In the quarter that ‐‐ you were
19 reporting it on a quarterly basis, so on that
20 order.
21 MR. HURSTELL:
22 I don't think we can provide that,
23 because we don't look at why a unit runs for
24 a particular reason. We run our production
25 cost model with all of our constraints in it
0299
1 that it is the best option. So I just don't 2 want to give you the impression that Lewis
3 Creek ran for flexible capabilities, another
4 unit ran for some other reason. So we can
5 get you all the data, but I can't give you
6 specific reasons why any particular unit ran
7 other than it was the, you know, choice,
8 given all the constraints.
9 MS. SCHMIDT:
10 Okay. And when you say you can
11 provide us the data, what data would you
12 provide us?
13 MR. HURSTELL:
14 The generation from the unit. The
15 data request you've already asked for is the
16 drivers of the flexible capability that was
17 in my testimony that you guys received, but
18 you're going to get that data tomorrow.
19 MS. SCHMIDT:
20 Okay.
21 MR. HURSTELL:
22 But we can't give you a reason
23 for ‐‐
24 MS. SCHMIDT:
25 If you can give us the megawatt
0300 1 hours as well as the hours that those units
2 were actually on line.
3 MR. HURSTELL:
4 So you want generation on an hourly
5 basis?
6 MS. SCHMIDT:
7 I'm sorry. When ‐‐ if those units
8 were running on a quarterly ‐‐ each quarter,
9 the megawatt hours that they were running, we
10 would just like to know when those hours
11 were. So if it was between noon and
12 1:00 o'clock on such‐and‐such a date.
13 MR. HURSTELL:
14 I guess, in my mind, it's not like
15 this unit runs between 2:00 and 3:00 on
16 Tuesdays. We have to give you the ‐‐ just
17 the hour ‐‐ the generation by hour for every
18 unit. I mean, we can do that, if that's what
19 you want.
20 MR. LOUDENSLAGER:
21 We'll get back to you.
22 MR. HURSTELL:
23 Okay.
24 MS. SCHMIDT:
25 We'll get back to you. 0301
1 PRESIDENT SUSKIE:
2 I'm sure they can get more
3 specific, and if it's a problem ‐‐
4 MR. HURSTELL:
5 We can give you the ‐‐ I'm not
6 objecting. I just want to make sure I know
7 what you want.
8 MS. SCHMIDT:
9 And we appreciate that.
10 MR. HURSTELL:
11 Okay.
12 PRESIDENT SUSKIE:
13 All right. Anything else?
14 (No response.)
15 And then the next meeting after the
16 meeting in Baton Rouge is SEARUC in Alabama,
17 and we know at this point two FERC
18 commissioners have committed. I would not be
19 surprised if we have more. And, also ‐‐ and
20 then we're probably going to consider moving
21 the July meeting to the ‐‐
22 MR. LOUDENSLAGER:
23 Transmission Summit.
24 PRESIDENT SUSKIE: 25 ‐‐ Transmission Summit here in New
0302
1 Orleans in August, but we'll send out whether
2 or not that move gets made ‐‐ meeting.
3 Anything else from any stakeholders
4 or parties?
5 Sam?
6 MR. LOUDENSLAGER:
7 Yeah. Just a reminder, too. You
8 know,e th Charles Rivers cost/benefit study
9 is supposed to be released, I believe, the
10 end of September, and I would encourage
11 everybody to consider being up there at FERC
12 for the release of that report.
13 PRESIDENT SUSKIE:
14 Yes. And if you're involved in the
15 Eastern Internet ‐‐ Eastern Interconnect
16 Planning Collaborative, the meeting is at the
17 same time, which there's a good chance that
18 meeting will be in Washington, so...
19 MR. LOUDENSLAGER:
20 Okay.
21 MR. BOOTH:
22 We're going to have fun.
23 PRESIDENT SUSKIE: 24 I think we'd have fun over there.
25 It's an interesting DOE issue.
0303
1 Anything else?
2 (No response.)
3 Well, thank y'all for your
4 participation. We're adjourned.
5 (MEETING ADJOURNED AT 3:46 P.M.)
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