5DEC16 - UCPB...4 MS. RAUCH: Oh. Well, first off, thank 5 you for the opportunity to come speak...

1

1 STATE OF MICHIGAN

2 UTILITY CONSUMER PARTICIPATION BOARD

3 - - -

4 MEETING OF MONDAY, DECEMBER 5, 2016

5 12:43 P.M.

6 611 West Ottawa, 4th Floor

Lansing, Michigan

7

8

- - -

9

10

PRESENT: James MacInnes, Chairperson

11 Paul Isely, Board Member

Susan Licata Haroutunian, Board Member

12 Brian Vilmont, Board Member

Sam Passmore, Board Member

13 Christopher Bzdok, Michigan Environmental

Council (MEC)

14 James Clift, MEC

John Liskey, Citizens Against Rate Excess (CARE)

15 Kelly Kitchen, CARE

Don Keskey, Great Lakes Renewable Energy

16 Association (GLREA) and Residential Customer

Group

17 Michael Moody, Assistant Attorney General

Shawn Worden, LARA

18 Jim Wilson, LARA

Jim Ault, Michigan Electric & Gas Association

19 Laura Rauch, MISO

Carmen Clark, MISO

20 Ed Haroutunian, Member of the Public

21

22 - - -

23

24 REPORTED BY: Lori Anne Penn, CSR-1315

33231 Grand River Avenue

25 Farmington, Michigan 48336

Metro Court Reporters, Inc. 248.360.8865

2

1 Lansing, Michigan

2 Monday, December 5, 2016

3 12:43 p.m.

4 - - -

5 MR. MacINNES: Well, welcome, everyone.

6 We have a lot of things to cover here, and everybody

7 wants to be first, and I was late getting started here,

8 so my apologies. But what I'd like to do is call the

9 meeting to order, do a quick introduction, and then we've

10 asked Laura and Carmen here from MISO to give us an

11 update on what MISO's doing, but they've got to catch a

12 plane, so we're just going to move them right up to the

13 front of the agenda.

14 So let's go around the room here. We've

15 got some new board members who we want to spend some time

16 getting to know, but for now we'll just do a quick around

17 the room on who you are and what, who you represent, and

18 then we will turn it over to Laura and Carmen. How's

19 that?

20 MS. RAUCH: Okay.

21 MR. MacINNES: Starting with this

22 gentleman here.

23 MR. ISELY: Paul Isely, I'm from Grand

24 Rapids, and I'm a member of the board.

25 MS. HAROUTUNIAN: Susan Licata


3

1 Haroutunian, I'm from Detroit, and I'm a member.

2 MR. PASSMORE: I'm Sam Passmore, and I'm

3 a new member of the board.

4 MR. LISKEY: John Liskey on behalf of

5 CARE.

6 MR. MOODY: Michael Moody on behalf of

7 the Attorney General.

8 MR. KESKEY: Don Keskey representing the

9 Great Lakes Renewable Energy Association and the

10 Residential Customer Group.

11 MR. WILSON: Jim Wilson, LARA.

12 MR. CLIFT: James Clift, Michigan

13 Environmental Council.

14 MR. AULT: Jim Ault, Michigan Electric &

15 Gas Association, we're an association of public

16 utilities.

17 MS. KITCHEN: Kelly Kitchen, president of

18 CARE.

19 MS. WORDEN: Shawn Worden, LARA.

20 MR. HAROUTUNIAN: Ed Haroutunian, member

21 of the public.

22 MS. CLARK: Carmen Clark, MISO.

23 MS. RAUCH: Laura Rauch, MISO.

24 MR. VILMONT: I'm Brian Vilmont, a new

25 board member.


4

1 MR. MacINNES: And Jim MacInnes, the

2 chair.

3 So take it away.

4 MS. RAUCH: Oh. Well, first off, thank

5 you for the opportunity to come speak today, and thanks

6 for letting us go first on the agenda. We're trying to

7 squeeze in a few last things before the end the year, so

8 it gets a little bit hectic.

9 What we really wanted to do today is just

10 give an overview of some of the things we're seeing both

11 with generation and transmission, so what generation

12 capacity is looking like, also talk about some of the

13 projects from a transmission point of view we just

14 approved, and some of the up and coming studies we're

15 working on.

16 So I would like to introduce my

17 colleague, Carmen, I believe she's spoken here before,

18 but she's on our customer and regulatory support side,

19 very involved in Michigan, I'm on the resource advocacy

20 side. So again, very glad to have this opportunity to

21 come and speak with you all.

22 Can you drive, Carmen. So starting out,

23 we'll just talk a little bit about resource adequacy,

24 which is how much generation do we have compared to both

25 load and/or safety margin that we need to have -- cover:


5

1 What happens when your generation goes out; what happens

2 if you have a hotter summer than expected. So every year

3 for the past three years we've done what we call the OMS

4 MISO Survey, and that's the Organization of MISO States,

5 so we work with our state regulators to make sure that

6 we're getting the states the information they need,

7 because whenever you talk about generation and ability to

8 serve load, that's ultimately a question for the states

9 and for the load serving entity. From MISO, our role is

10 really providing transparency. So the OMS MISO Survey is

11 a way we do that, it works with our other resource

12 advocacy, and the goal is to take a snapshot of the

13 footprint and look at what it looks like.

14 So you'll notice here that we have kind

15 of our projections for next year. Next year looks fairly

16 similar to this in that we have extra capacity; we don't

17 have a lot of extra capacity, so depending on some

18 decisions by generation, mostly independent power

19 producers in the Illinois area, we'll have between,

20 around a gigawatt to slightly less than two gigawatts of

21 spare capacity available across the footprint.

22 MR. MacINNES: And the footprint is how

23 many states now?

24 MS. RAUCH: The footprint is --

25 MS. CLARK: Fifteen.


6

1 MS. RAUCH: -- 15 states and part of

2 Canada, with Manitoba Hydro from a reliability

3 coordination. So it's a fairly large footprint, and this

4 shows that basically we are getting to basically being at

5 margin. We have generation, we don't have the spare that

6 we've had to operate around.

7 Michigan right now, we are showing as

8 Zone 7, it has a slight deficit. That's not a concern

9 because that's the benefit of being in part of a larger

10 footprint is as long as you can import power, which

11 Michigan has the ability to import around three gigawatts

12 of power, and as long as there's power to import, which

13 we are showing that there's power to import, it's very

14 reasonable to go and use power from other states to

15 fulfill your local needs.

16 MR. MacINNES: So I had a quick question.

17 So Michigan has the capacity to import three gigawatts,

18 and how many gigawatts does Michigan use at peak now, do

19 you know offhand?

20 MS. CLARK: It's about I think 21,000 or

21 something like that megawatts, which is about, you know,

22 21 gigawatts, I think that's about the number.

23 MR. MacINNES: Yeah, okay. So it's like

24 10 or 15 percent, something like that.

25 MS. CLARK: Uh-huh, uh-huh.


7

1 MS. RAUCH: I will say, though, that we

2 look at two things; we look at how much does the

3 footprint need at peak, we also look at how much does

4 each state need to hold just to meet their needs within

5 their boundaries. Michigan actually, they do have a

6 number of -- they have about 95 percent of the resource

7 needs you need to hold within your state boundaries; so

8 of that around 21 gigawatts, 95 percent needs to be

9 local.

10 MR. MacINNES: And why is that?

11 MS. RAUCH: What we'll do is we'll do two

12 calculations: One is what is Michigan's share of the

13 system-wide peak, which tends to be a lower number; the

14 second is, what does Michigan need to hold for their own

15 specific peak. So that starts out at a higher value, and

16 then you use specific risk factors for Michigan based on

17 the generation and load, and that gets you to about

18 95 percent once you factor in the risk factors and then

19 how much Michigan can import.

20 MR. KESKEY: Can I ask a question. When

21 you say Michigan, are you -- is that defining the Upper

22 Peninsula and Lower Michigan, or is there a separation of

23 analysis?

24 MS. RAUCH: There is a separation of

25 analysis there just because there's electrical separation


8

1 in general between the Upper and Lower Peninsula. The

2 statistics we were giving were basically Lower Peninsula.

3 When you look at the Upper Peninsula, that's part of Zone

4 2 here, so that's a little bit different of a story, and

5 you start to get into more individual generation analysis

6 there.

7 All right. Let's go to the next slide.

8 So the other piece, though, is we talked about Michigan

9 for next year, once you start getting past next year, you

10 get into more uncertainty, and then you get into more of

11 the question of Michigan can import some of their power,

12 will there be power to import, and that leads us into a

13 larger resource adequacy of are we sending the right

14 signals across the board, especially for retail choice or

15 load that isn't directly regulated by any state, owned by

16 any kind of traditional vertically integrated or

17 regulated utility. So what we've seen there is you

18 really start to depend on other units across the

19 footprint, you really start to depend on how do

20 retirements occur and when do they occur. And that's the

21 shaded here shows that there is that level of

22 uncertainty, where if, depending on what decisions

23 individual generation makes, you might be sufficient out

24 through 2021, or you might start seeing where you're

25 getting short of margin even into the 2018 timeframe. So


9

1 that's why we'll continue to focus on this is just what

2 are the signals and tie this into the larger resource

3 adequacy, but also the larger planning process to make

4 sure that the information is there and transparent for

5 our stakeholders.

6 MR. CLIFT: And this is MISO wide, just

7 to make sure I was --

8 MS. RAUCH: Yes, this is MISO wide.

9 All right. With that we can talk a

10 little bit more about one of the things we've been

11 looking at, which is resource adequacy for competitive

12 retail states and areas.

13 MS. CLARK: So we've just recently,

14 November 1, filed the Competitive Retail Solution. We've

15 been probably looking at this for, I think it's been

16 about a year or so, I can't remember how long it's been,

17 but do different phases, and we started mainly with the

18 solution kind of focusing on Zone 4 just because we start

19 seeing or you start hearing about, you know, retirements

20 and things going on with the Zone 4, and that's an all

21 retail choice state, but then, you know, we do realize

22 that Michigan has 10 percent of retail choice, so it's

23 kind of weird because one was total and was sort of

24 10 percent plus, you know, some industrial things. So we

25 start looking at with the decreasing reserve margins that


10

1 Laura had spoken about, looking at what does this do to

2 the retail load because we're so used to having the

3 27-percent reserve margin, now we're getting down to 15

4 and still barely having enough available resources to

5 meet the entire footprint. One of the main things that

6 came up was that retail choice; well, retail choice, they

7 don't have, typically in Illinois you don't have a

8 mechanism there that says, you know, you shall build X,

9 Y, Z because it's not regulated, so it's really up to the

10 independent power producers in that state to supply the

11 local and if there's any extra needs. So we start

12 looking at that because of the declining of reserve

13 margins.

14 And as part of what we were looking at is

15 that because retail choice in the past have relied on, I

16 mean they have been able to rely on going into the

17 auction excess capacity that MISO has been afforded over,

18 you know, the last, since we've had the resource adequacy

19 construct, which was 2009, so we've seen those decline,

20 and then now we're seeing, well, what's going -- what do

21 we have in place so that we can make sure that in the

22 future we still have some type of reserve margin and

23 extra resources. Also, like I said, we've seen load

24 growing in some pockets of MISO. Like I said, it's a

25 footprint-wide basis that we look at our analysis, but we


11

1 do look at the zonal pieces as well. So when we start

2 talking about reserve margins declining, we're talking

3 about from a footprint-wide basis. You do have

4 individual things going on in the state, but when we say

5 that you have three gigawatts of import and there's not

6 three gigawatts available on the system import, there's

7 an issue there. So we're finding that less and less

8 we're having the actual extra capacity that we needed.

9 And then looking at state, Michigan's

10 different because it's kind of 10 percent/90, so you

11 have, you're state-regulated, some utility, some co-ops

12 are not, but what does the state have to do with that?

13 Well, they're responsible for setting those rules and

14 regulations as far as MISO is concerned, but then there's

15 also the piece of retail choice because all of that sort

16 of bundled in when you think about some of the bigger

17 utilities in Michigan, so you think about most of that's

18 going to be bundled in with their -- and then we were

19 just hearing that, you know, we have enough, we don't

20 know about the retail choice, so that's what we're

21 hearing from the different participants in MISO.

22 MR. MacINNES: So I have a question. So

23 Michigan, we talked earlier about Michigan needing to

24 have about 95 percent of its resources located within the

25 state, and I'm just wondering how that compares to the


12

1 other states.

2 MS. CLARK: Michigan is actually the

3 highest, has one of the highest what we call local

4 requirements in the MISO footprint. I'm not sure of the

5 reasoning why, but like Laura said, just depends on the

6 ratio share of all of that, but they do have one of the

7 highest ones, meaning that they need more inside -- and I

8 think it's just because the electrical connections, they

9 need more inside the state to meet the one day in ten

10 requirement, but it is the highest one, and when I say

11 Michigan, I'm talking about the Lower Peninsula.

12 MR. MacINNES: So when you say electrical

13 connections, are you talking about the electrical

14 connections within the state or the electrical

15 connections to other MISO states?

16 MS. RAUCH: It's the connections to other

17 MISO states. So the three things that really tend to

18 drive how much you need within a given area are how

19 closely tied are you to the rest of the footprint; like

20 we said, Michigan has about three gigawatts, other areas

21 because they just have more connections, tend to be a

22 little bit higher. It's also how much does your load

23 vary, and how much uncertainty do you have on that, and

24 also what's your generation performance. So if you have

25 a tendency to have older units, you'll have more risk


13

1 factors because they're more likely to trip out, and that

2 will mean that you have to hold a little bit more. So

3 because of all of those things, you tend to see Michigan

4 being towards the higher end.

5 MR. MacINNES: Okay.

6 MS. CLARK: So when we talk about the

7 competitive retail solution, one of the elements of it is

8 that it's kind of bifurcated, and we'll still have our

9 annual auction, but we'll have what's called a forward

10 resource auction for those that are retail choice. The

11 one other thing about this is you can also have where

12 other supply throughout the footprint will be able to

13 offer into MISO. There's a condition on that, they have

14 to show that they basically can meet their local or their

15 native load before they can offer their excess supply,

16 but they can offer the excess supply, it's not required;

17 in retail choice zones, it is required. So Zone 7 and

18 Zone 4 will be required to offer their excess, the other

19 ones are not, but they have the -- they have the

20 opportunity to do so.

21 The other part when we look at what we're

22 trying to do with the three-year forward auction is that

23 it does exist today in the PJM market, and part of

24 Michigan, part of Illinois right now participate in the

25 PJM market, so it's nothing new that has not been done


14

1 before; of course, PJM and MISO operate totally

2 different, but it is an existing design that works for

3 retail choice areas within the United States. So it is

4 going off of something existing that does work in PJM

5 just because of you still have the problem with the

6 excess, trying to find excess capacity. So we looked at

7 that as sort of that is something that is working as far

8 as getting that investment going. Right now the current

9 construct, the annual one, if you think about it, we hold

10 that auction in April typically, and we start our

11 planning year in June, so we really only have like two

12 and a half months to, if we are short, we're -- we don't

13 have any time to implement anything or to build anything.

14 And we are always told that it takes about, you can build

15 a plant in three years, and I think a good example of

16 that is the Alpine plant, I mean it got built pretty

17 quickly in Michigan, when you're looking at the amount of

18 megawatts, it was 470 megawatts. So when you look at

19 something going more out, you can probably get more

20 capacity on the system rather than two and a half months.

21 So that was the other part of it, we're seeing more of

22 the retail customers needing that extra time, this gives

23 them that extra time.

24 The other part is that we did look at --

25 we hired Brattle Group -- I know you've, probably most of


15

1 you've heard of them -- to look at sort of what one of

2 the big things we heard was the volatility that going

3 back and forth with our current auction, you know, some

4 of the times the prices are way up here, sometimes

5 they're not, so when they looked at that, they said,

6 well, this construct will actually give them less

7 volatility than our annual one right now. Because if you

8 think about maybe not as much as Illinois, but Illinois

9 is kind of like going up 1.50, 16, $3, and it goes up and

10 down, so they've done analysis and said this is actually

11 less volatile than our current construct, which we want

12 things to sort of be not going up and down all the time

13 because people have to pay for that, pay for that

14 capacity, and so if people can get some kind of rhythm or

15 some kind of bandwidth of price, that will give them some

16 kind of, some certainty that it won't be 1.50 one year

17 and then 10 the next and then 3, I mean you have to plan

18 for people to come in and out of your state economic

19 development. We think about residents, how you plan for

20 somebody facing a 1.50-megawatt-day charge on their bill,

21 I mean you think about we got the calls that said, you

22 know, why did you guys do this, and so this would offer,

23 with the less price volatility, that people need to do

24 their planning as well. And I'll take questions at any

25 time if anybody has questions on this.


16

1 So we filed this forward resource auction

2 competitive resource solution back in November, we're

3 hopeful that we could get an order, a favorable order

4 from FERC by the first quarter of next year. And also,

5 comments to our proposal are due by December 14, I

6 believe, and then we will respond to those comments, I

7 think it's like mid January, something like that. So if

8 there are comments that your organization would like to

9 submit, please just make sure that you're aware of that

10 date because all the comments have to be submitted to

11 FERC by that date. I don't have the exact docket number,

12 I could probably look it up really fast, but if you want

13 that, I can look that up and provide that at end of the

14 meeting.

15 But that's basically the proposal, it's

16 really to try to fix what's going on in our retail choice

17 area, that's how it morphed, and to make sure that we

18 continually have the supply that we need, because when

19 you have some states that don't have a mechanism to

20 enforce the building of plants and to make sure that

21 rate-based stuff is built for the customers, you sort of

22 have a gap in your systems.

23 MS. RAUCH: There was a question.

24 MS. CLARK: Oh, go ahead.

25 MR. LISKEY: Well, I just wanted to


17

1 mention it's Docket No. 17284.

2 MS. CLARK: Okay. Thank you.

3 MR. LISKEY: We have met with the

4 governor's office, and CARE is likely to file comments.

5 MS. CLARK: Okay. Thank you.

6 MR. KESKEY: In support, I might add.

7 MS. CLARK: All right. Thank you.

8 All right. Are there any other questions

9 on the construct or anything else, you guys have any

10 questions on that, how this would affect Michigan and

11 anything?

12 MR. MOODY: I guess maybe to explain a

13 little bit that competitive retail solution part, like

14 the -- you can get, the states can do it I know, explain

15 that piece maybe.

16 MS. CLARK: So with the way that it would

17 work with -- so the forward resource auction is basically

18 for retail choice basically from the load side, so it's

19 all about what load can procure, so only the load that is

20 retail choice would be part of this forward auction, and

21 then the rest of the load, sort of the status quo MISO,

22 would be part of the planning resource auction. The flip

23 side of this is that you have the supply side, so you

24 have the supply that's in Zone 4 or Zone 7 will be able

25 to participate in the auction, provided that they show


18

1 MISO that they've met their local obligations, so

2 whatever their load plus planning reserve margin is, and

3 other states can opt to offer their supply as long as

4 they still show their load, but the retail choice states

5 that have extra supply have to participate, and the

6 non-retail choice states do not have to, but they can.

7 MS. RAUCH: Were you asking about the

8 prevailing state --

9 MR. MOODY: Yeah, that part that goes

10 down to the state, but that's all right.

11 MS. CLARK: I can do that, too, I can do

12 prevailing state. So prevailing state compensation

13 mechanism allows your state, if you're under, we call

14 them RERAs, relevant electric regulated and I think the

15 last word is authority, it's an acronym, but basically

16 who actually is in charge of its ratemaking and there's

17 another piece to it. So if you're basically under the

18 jurisdiction of the Michigan Public Service Commission,

19 you're subject to the prevailing state compensation

20 mechanism. What they would do is open a docket, you

21 know, to decide what that rate should be. MISO would not

22 be part of setting any type of rate. Also, if the state

23 elects that, there is a minimum term of four years to be

24 part of the prevailing state compensation mechanism, and

25 the state yearly could change that, but I don't know if


19

1 they would. They can also pick the term, it's a minimum

2 four years, but your state could pick five or six years,

3 and none of those charges will be facilitated through

4 MISO if they're under prevailing state compensation

5 mechanism, that would be something the state would be

6 handling the billing for.

7 The other side of that is if you have,

8 from a retail choice perspective, so if I'm a retail

9 choice supplier in MISO and I have my own contracts,

10 there's a mechanism called forward FRAP, that you may

11 FRAP out so that you're not subject to -- you're not

12 subject to the prevailing state mechanism that's -- so

13 say if it's I'm going to say $2.00, but don't quote me

14 that $2.00 is the rate -- so if it's $2.00 and you have

15 50 megawatts, but I have a contract with another party

16 for my 50 megawatts and I decide to submit a forward

17 resource -- what is it -- auction, I can't think of it.

18 MS. RAUCH: Resource adequacy plan.

19 MS. CLARK: Resource adequacy plan, which

20 is FRAP, then I would not be subject to the prevailing

21 state compensation mechanism. So if you have your own

22 supply, basically you can submit what's called a forward

23 FRAP and not be subject to the prevailing state

24 compensation mechanism. There is a minimum term of two

25 years, so not only would you be in it for like '18-'19 is


20

1 when we wanted to start, you would be in it for '19-'20,

2 so it's a two-year minimum. When we, but when we start

3 initially, it'll almost be like a four-year because we'll

4 have these catch-up auctions and they will go into steady

5 state, like '20, '22, '23 timeframe. So it's kind of a

6 four-year in the beginning because of the interim, and

7 then steady state is a two-year to four FRAP, and then

8 you could decide that you want to be subject to, you

9 know, the prevailing state compensation, but that's how

10 you could elect to not be subject to it is if you have

11 your own resources or bilaterals with another company,

12 then you can submit the forward FRAP.

13 MS. RAUCH: So it's somewhat in the realm

14 of if it's not broken, don't fix it. We're trying to

15 really target this towards load that isn't covered

16 through states or forward contracts, so the prevailing

17 state compensation mechanic lets states who are taking

18 care of this be recognized; the forward FRAP of fixed

19 resource adequacy plan says if you have a contract,

20 that's great, bring that us to.

21 MS. CLARK: Any other questions? Go

22 ahead.

23 MR. AULT: Will this apply, just to be

24 sure, is it both Zone 7 and Zone 2 in Michigan?

25 MS. CLARK: It would depend, because we


21

1 would calculate what's called a materiality threshold,

2 more than likely it will just be Zone 7, depends on the

3 amount of load in Zone 2. I think it's like, is it 0.5

4 percent or something is the calculation that we'd do the

5 materiality threshold for Zone 2. Our initial

6 calculations kind of indicate that it would, typically it

7 will be Zone 7 that will be part of the auction. But I

8 think if you wanted to opt in, you can. I don't

9 remember, but don't quote me on that one, but it's been

10 going back and forth. But you wouldn't be subject to it

11 probably because you won't meet the minimum requirement

12 megawatt requirement. So say the megawatt requirement is

13 a thousand megawatts and Zone 2 doesn't have a thousand

14 megawatts, then they wouldn't be part of the forward

15 resource auction.

16 Any other questions? Okay.

17 MS. RAUCH: So we talked a lot about

18 generation. The other side is certainly transmission.

19 Every year we do what we call a MISO Transmission

20 Expansion Plan, I'll call it MTEP, if you hear that,

21 M-T-E-P, and really what that's supposed to do is do we

22 have the transmission we need to make sure the system's

23 reliable; do we have anything to really help with

24 economics; are there transmission projects where if we

25 build them, they pay for themselves.


22

1 So if you go to the next slide, MTEP, we

2 just are finishing up what we call MTEP 16, that's out

3 for board approval within the next couple days looking at

4 my, the date on my watch. But we essentially start --

5 really it's an 18-month process, but very intensive in

6 the last 12 months or so. So we've been going through

7 this process of what are the issues we see, how can we

8 best solve them through the stakeholder community,

9 getting ideas from the great people we work with, and

10 just making sure that there's transparency over what

11 we're bringing forward.

12 So if we go to the next slide. What

13 we're approving this year, we have 383 projects, it's

14 about $2.7 billion of investment, and this is very much

15 reliability focused. We have one economic project, but

16 for Michigan point of view, which is about 21 percent of

17 the investment here, it's reliability focused. So

18 mostly, it actually is mostly substation work. You get a

19 lot of circuit breaker upgrades and things that are

20 pretty small in nature, but you have about 28-percent

21 upgrades of transmission line across the footprint and

22 around 20-percent new transmission lines. So every year

23 we'll go through this process, we're just kicking it off

24 for MTEP 2017. So coming up in the next few days we have

25 what we call subregional planning meetings, which is


23

1 going through very detailed what are the issues we see on

2 the system, what are some potential solutions, and

3 walking through that process again from a MTEP 17 point

4 of view.

5 MR. MacINNES: So Laura, could you talk

6 for a minute about the difference between an economic

7 project and a security or reliability project?

8 MS. RAUCH: Most of the projects we see

9 on our footprint are reliability focused, and what I mean

10 by that is you want to have a system where if one line

11 goes out of service, there's no issue; if a couple lines

12 or five or six lines go out of service, you have a storm,

13 you can manage that. So we do a large number of studies

14 to just say, okay, what do we need to do to make sure

15 that our operators have the bandwidth on the transmission

16 side they need, and it's based on a set of NERC standards

17 called the NERC TPO, which is NERC Transmission Planning

18 Standards. That's most of the things we approve are just

19 that very low-level nature, and it can be something as

20 low level as, well, we have a lot of transmission lines

21 near farmers' fields, the farm equipment's gotten larger

22 and higher, our transmission lines stay the same height

23 so we're having people driving combines into transmission

24 lines, that was a transmission project that we approved

25 because that was obviously a safety hazard. It can be


24

1 woodpeckers are attacking our poles, we need to replace

2 those. So there's lots of things we group into the

3 reliability bucket that are kind of maintenance, as well

4 as new load has grown in this area of the state, we need

5 a new transmission line.

6 The other thing we'll spend time looking

7 at is economic projects, and these are projects that we

8 look at and say, okay, we have this energy market, we

9 have a lot of generation that you, options that you can

10 use to serve your load even at margin; are there

11 transmission lines we can build that just let this lower

12 cost power get to load, and we try to do that across a

13 number of different scenarios. So we'll look at what

14 happens if no new energy policies occur, what happens if

15 you have a lot of renewables, and if we can find

16 transmission projects that basically pay for themselves

17 under all of those scenarios, then that's what we'll move

18 forward. Like I said, there was one project out of 383

19 that was economic, so it tends to be the area we don't

20 have as much movement, and that's usually because

21 reliability projects tend to have economic benefits as

22 well, even if they're mostly targeted towards making sure

23 the lights stay on.

24 MR. MacINNES: So we talked earlier about

25 Michigan being -- having a very high in-state required


25

1 generation requirement. Part of that reason I think is

2 because we don't have a lot of transmission connected to

3 the rest of the MISO system. And so but I guess up to

4 this point, we haven't found very many economic projects

5 that would cure that or pay for themselves, and usually

6 the benefit-to-cost ratio on those would be three-to-one

7 type of thing or --

8 MS. RAUCH: 1.25-to-1 is the minimum

9 requirement.

10 MR. MacINNES: Okay. So we haven't seen

11 a lot of those projects; is that right?

12 MS. RAUCH: That's right. We do have

13 options where if there's a transmission limit, anyone can

14 come forward and say here's the benefit I would see in

15 this and fund it, but from a larger perspective, we

16 haven't seen, we've looked at economic benefit increase

17 in transfers into Michigan, we haven't necessarily seen

18 that under our current assumption sets, but that is

19 something, and I think we'll actually get to that of

20 things are changing; whether that changes or not is

21 something we'll have to continue to look at to determine

22 if there are other options.

23 MR. MacINNES: And probably one of the

24 most important considerations in that is natural gas

25 price.


26

1 MS. RAUCH: Yes. Whenever you talk about

2 system economics, it's incredibly dependent on what you

3 think the future is going to be. I've been at MISO for

4 going on 12 years now, and when we first started to do

5 economic planning, we were talking about where is new

6 coal going to be located. If you look at our projections

7 now, with the combination of policies, but especially

8 because of natural gas prices, we don't see that growth

9 in coal, we see natural gas being the new fuel source.

10 So while we have such low natural gas prices, it's going

11 to change your economics substantially, and really a lot

12 of times it's natural gas is driving less need for

13 transmission.

14 MR. ISELY: Just so I make sure I'm

15 reading this graph correctly, though, was MTEP 14 the

16 first time you had the geographic expansion of MISO?

17 MS. RAUCH: Yes. So you'll notice a few

18 peaks. MTEP 11 we had our Multi Value Projects; I know

19 several people in the room are familiar with those. And

20 then we did have an expansion of our footprint where we

21 had some states in the south portion of MISO, Louisiana,

22 Texas, Mississippi, Arkansas, join, so you'll see some

23 upticks based on that.

24 MR. MacINNES: So another thing I think

25 it's important to point out is there's been $25 billion


27

1 approved, according to your graph here, and that really

2 only about half of that has been completed. So I've

3 heard people say, oh, what are these transmission

4 projects, they're not helping us any, and I say to them,

5 they're not done yet; so that's something to keep in

6 mind, we're only partially through this process.

7 MS. RAUCH: And let's go to the -- if we

8 go to the next slide, we do have just a snapshot of

9 what's been proposed and where it is on the, in

10 construction. Now, this is based upon our MTEP reports,

11 so there's a probably clearer version of this graphic in

12 that report. But if you'll notice that based -- when you

13 start out with the things we approved in 2013, they are

14 going into service, but a lot of the projects that have

15 been identified in the last five years or so are working

16 their way through the regulatory process, and we support

17 those both before and after approval because we never

18 want to be out in front of -- put our stakeholders or

19 ourselves in front of the states with something that they

20 can't justify. But it is absolutely something where we

21 track are they going into service; and especially for the

22 reliability projects, if they're delayed, is there

23 something we need to do to make sure the lights stay on.

24 So there certainly is a lot of movement, a lot of new

25 projects that are going into service, and we watch very


28

1 carefully to make sure that they are tracking on

2 schedule.

3 So we kind of alluded to this earlier,

4 but talking about the Michigan, we're going to give a

5 brief update on a study we're working on in Michigan on

6 the more trans -- the ties between transmission and

7 generation.

8 MS. CLARK: So back in August we received

9 a request from the Michigan Public Service Commission and

10 the Michigan Agency for Energy requesting MISO to do a

11 study in particular focused on generation with

12 retirements of some units in Michigan, some nuclear unit

13 assumptions where PPAs will be expiring, and then the

14 second request was based on the transmission in Michigan,

15 in particular, connecting the Upper and Lower Peninsula,

16 but this time looking at Ontario as a connectivity.

17 Before we looked at I think it was the NARA [ph] study

18 looking at about five years ago I think we did that

19 before and determined it wasn't economic. I heard a

20 number about $5 billion was the last amount of the study.

21 But Michigan wants to look at the ties between Ontario

22 and Michigan to I think it's Sault Ste. Marie, and we

23 just decided to partner with the Michigan Commission and

24 Michigan Agency for Energy, and when I say partners,

25 because that -- in that letter that they had several


29

1 assumptions that they wanted us to use for our studies,

2 and we had to work back and forth with them on getting

3 the actual assumptions together from the State of

4 Michigan, and some of those assumptions from them

5 included gas price forecasting and things like that.

6 So the study is under way, and we decided

7 to do the study in two phases because there was a

8 generation piece and a transmission piece. So the

9 generation piece we are actually currently working on and

10 we should have everything finalized by mid January or

11 early December [sic], and those assumptions and those

12 results will be shared publicly. And then we will

13 discuss those with all of the MISO stakeholders, not just

14 the State of Michigan or the Agency, and then those

15 assumptions or those results will be used to start the

16 transmission study with the assumptions from Michigan.

17 And all of the assumptions and the results will be shared

18 publicly as well. But we want to make sure that all of

19 our stakeholders were aware of what we were doing and

20 nothing was sort of being done in a vacuum. Although

21 Michigan has basically alluded to the, you know, the

22 assumptions that they wanted us to make and where they

23 thought would be the best transmission, you know, we have

24 to actually do the modeling to see if those assumptions

25 and everything is viable.


30

1 So all of that information is going to be

2 public, we'll have the generation study done in

3 particular, like I said, mid January, and it's really

4 trying to focus on when Laura talked about the OMS

5 Survey, so that generation survey, that generation study

6 that we're doing is really trying to look at we saw 2018

7 where we start seeing some, definitely more, more of the,

8 what I call the red, more red, more shortages throughout

9 the footprint, but what does that do for Michigan, in

10 particular, you know, the Lower Peninsula. We've seen

11 the retirements of some things just recently this summer

12 as well, but in particular, what happens if the nuclear

13 plants are no longer, they no longer have PPAs, and then

14 if you don't have a PPA with someone, you're not going to

15 produce the power just to produce it, so what happens if

16 those PPAs expire, the licenses don't get renewed, but

17 we're looking at that near term because of we're seeing

18 the reserve margins in '18 actually decline more than

19 '17. In '17 looks like we had a surplus for the

20 footprint, but in '18 it looks, it's actually declining a

21 lot more. So Michigan wants to see -- to support the OMS

22 Survey, what if we made these assumptions, what if our

23 units aren't performing as well as they should, and what

24 happens. Because Laura mentioned that when you have

25 those higher forced outage rates, you tend to have to


31

1 have more locally a higher what we call local

2 requirement, and Michigan is already at 95 percent, so

3 they need a higher, higher local requirement than

4 95 percent because of unit performances. What does that

5 do to Michigan when we have to have more locally, and

6 even though we can import more, we can't, because we have

7 to have more locally. So we're looking at that from a

8 generation perspective.

9 MR. MacINNES: So could you clarify, what

10 do you typically see as the reserve requirements, what

11 percent do you like to see?

12 MS. RAUCH: It's around 15.5 percent on

13 the installed capacity basis. It varies a little bit

14 year to year, but that's a good rule of thumb.

15 MS. CLARK: Yeah.

16 MR. MacINNES: And then you mentioned

17 again that the very -- the reason we have these

18 95-percent local clearing requirements is because of the,

19 did you say the lack of reliability of our existing

20 plants?

21 MS. CLARK: I just said the -- not the

22 reliability, but basically when you're running power

23 plants, it's called forced outage rates, so when you're

24 talking about forced outage rates, you're saying that

25 when I'm running a plant, I operate X, Y, Z, you know,


32

1 and maybe my units, because they're older, I'm

2 actually -- they're more down than up, than running, so

3 we're talking about the operating -- operation of the

4 actual unit.

5 MR. MacINNES: So, again, to me that

6 means that the units are not reliable, I mean that's what

7 it sounds like. Am I saying that right?

8 MS. RAUCH: I mean every unit is going to

9 have some time they're going to go out of service, and it

10 does vary based on the unit type. In general what we see

11 is older units tend to be less, have a higher forced

12 outage rate, so it's -- I don't think we want to imply

13 that our utilities aren't doing their due diligence to

14 keep those units up, it's more just a natural fact of

15 depending on what fuel types you have, depending on the

16 age, you see different fluctuations and forced outage

17 rates.

18 MR. MacINNES: And what types of

19 generation do you see these forced out -- more of these

20 forced outages, what kinds of plants, what kinds of fuel

21 do you see?

22 MS. RAUCH: We do have a table we publish

23 kind of what we call generic forced outage rates for

24 everything, we can certainly send that information on. I

25 think right now you do see slightly higher rates with


33

1 coal, and that's -- but it's very dependent on unit-

2 specific data. So we collect what we call generated

3 availability data system, it's a NERC requirement to get

4 very detailed units of when were you available, when were

5 you not, and we use that to calculate rates for each unit

6 in our footprint. But we do have those generics and we

7 can certainly provide those to the group as well.

8 MR. MacINNES: So but it sounds like a

9 lot of it has to do with the age of the unit?

10 MS. CLARK: It is the age. And I can't

11 remember what the average age of our fleet is as far as

12 when it's -- if you think about it, we have a lot of

13 coal, and I want to say most of our fleet is what, in at

14 it's 40, some of it's even older than that, if you think

15 about some of the plants that were built in the 1950s.

16 MR. MacINNES: I think it may be

17 50 percent, right?

18 MS. CLARK: Yeah, it's a lot. I can't

19 remember the exact age. And it's throughout our

20 footprint, too. So we think about -- and people are

21 trying to change over from coal and to gas just because

22 gas prices are so low as well, but nobody wants to, you

23 know, invest in a big, you know, coal plant, you see

24 people investing more in converting coal to gas or even

25 building gas plants. But we do have a very aging fleet


34

1 in MISO.

2 MS. RAUCH: So just quickly pulled up,

3 the highest forced outage rates we have are on small

4 combustion turbines. Coal, it depends on what type you

5 see, and I think that's just an age. But you have

6 combustion turbines, you have steam gas is around

7 12 percent, combustion turbines can be more in the 25 to

8 30 percent for zero to 20-megawatt units; coal you get

9 into the 5 to 10 percent, depending on rates. So overall

10 on a system, we're in the about seven-percent weighted

11 average forced outage rate.

12 MR. MacINNES: So does that mean that to

13 the extent we add more combustion turbines, that's going

14 to make us more volatile in our, more higher forced

15 outages, is it --

16 MS. RAUCH: Well, note that I said that

17 was small combustion turbines --

18 MR. CLIFT: Age.

19 MS. RAUCH: -- you have age there. If

20 you look at 50-plus megawatt combustion turbines, the

21 rate's around 10 percent, and that would include some old

22 units as well as new ones.

23 MR. MacINNES: So we should see, as we do

24 add more new generation, we should see the variability --

25 MS. CLARK: You should see --


35

1 MR. MacINNES: -- being reduced.

2 MS. RAUCH: Yeah.

3 MS. CLARK: Yeah. Because as the old

4 goes out, the new comes in, you're starting to see

5 probably more refreshed units, units that don't need to

6 be down for, you know, maintenance costs, and as the

7 units get older, the maintenance costs are very

8 expensive. And so that's why people do retire them,

9 because sometimes the maintenance costs just aren't, you

10 know, maybe they're not as far as the cost recovery, but

11 the maintenance costs just don't warrant and they can

12 build another unit that's more efficient. So as I said,

13 it's not really reliable, it's just that, you know, it's

14 like a car, when the car gets older, you've got to spend

15 a little bit more time and money; and it's the same thing

16 with power plants, you know, as they get older, they're

17 like you got to always keep doing something because, you

18 know, if the expectancy is, you know, 40 years or so and

19 you're kind of running up 45-50, you know, you're really

20 trying to keep a plant running, but you have to spend a

21 little bit more time with, you know, updating the parts

22 and things just kind of go awry.

23 MR. MacINNES: So if we -- as we continue

24 to upgrade the generating fleet, are we going to actually

25 see the local clearing requirement percentage drop as a


36

1 result of that, and if so, how much do you think? I know

2 that's probably a tough question.

3 MS. CLARK: Yeah, I can't answer the -- I

4 can't do the estimation because I think Laura mentioned

5 that other things also weigh into the local clearing

6 requirement with the load side as well, so.

7 MR. VILMONT: Or is that more related to

8 transmission?

9 MS. CLARK: It really just depends.

10 MS. RAUCH: It's -- so I'd say in

11 general, yes, we would expect it to go down, it depends

12 on what is installed and where it's installed, because it

13 does get into the transmission piece, and especially for

14 Michigan this year, we actually saw some limitation --

15 the limitation was not based on your typical transfer, it

16 started to get into stability issues, which is more based

17 on what generation do you have to support it. So it gets

18 very specific into where is generation located, as well

19 as what type, but you would see at least one of your risk

20 factors tend to decrease. Now, you could argue whether

21 weather-related uncertainty is going to increase or

22 decrease or stay the constant, so there certainly is a

23 little bit of a mixed bag there, but at least it would

24 help with one factor.

25 MS. CLARK: Any other questions on the


37

1 study? So stay tuned. Like I said, all this information

2 is public information. Go ahead.

3 MR. AULT: In the U.P.'s transmission

4 study, transmission, we're having a debate in the

5 legislature about it, is the link to Ontario just across

6 the river to get to the Brookfield mothballed plant, or

7 is that to go further and link with the major

8 transmission system in Ontario?

9 MS. CLARK: I thought it was to link to

10 the major transmission system in Ontario. I'll have to

11 doublecheck that, but I thought it was, and I think it

12 was just limited. I know they had a 230 kV --

13 MR. AULT: There's one plant that's idle

14 on the --

15 MS. CLARK: Right, one --

16 THE REPORTER: Excuse me. Please, one at

17 a time.

18 MR. AULT: Sorry. There's an idled

19 natural gas plant on the other side of the river from

20 Sault Ste. Marie that they had talked about linking that,

21 but it's more to go past that to link to the --

22 MS. CLARK: Yeah, so --

23 MR. AULT: -- (inaudible) system?

24 MS. CLARK: Yeah, so in MISO we haven't

25 gotten into the -- what we have to do first is, before we


38

1 get into the transmission side of that, we do have to

2 coordinate with Ontario on the modeling and things like

3 that, so we'll have more information on that. I know

4 that their models aren't the same as what we use, I know

5 they use a different system from what I was told, but we

6 would have to coordinate with them on exactly location

7 and things like that, but that will be part of our

8 transmission study. But I thought it was more expansive

9 than just the Brookfield line that you mentioned.

10 MR. MacINNES: So do you have -- you

11 don't have any early indications if that's going to be a

12 positive --

13 MS. CLARK: No, we haven't even started.

14 I mean we're just focused, sort of right now it's just a

15 generation piece and it's kind of the ins and out, what's

16 in, what's out. It probably would be I would think

17 middle of the study before we can start really trying to

18 see some -- the biggest key is, you know, what will we

19 get when we coordinate with Ontario, because like I said,

20 their modeling, they're using a different modeling system

21 than what we use, and how will we transfer that modeling

22 to what we're trying to do in our transmission study.

23 MR. MacINNES: I listen to the Canadian

24 news quite a bit --

25 MS. CLARK: Oh, okay.


39

1 MR. MacINNES: -- and I see a lot of talk

2 about high electricity prices in Ontario, a lot of

3 concern about that, so I don't know how that's all going

4 to enter into it.

5 MS. CLARK: Yeah, because -- yeah, the

6 purpose of the study is not to get higher prices, trying

7 to see how we can still keep, you know, the cost of

8 energy down for the U.P., and I think that's why the

9 state and the Michigan Agency for Energy asked us to do

10 it, just to see was there something viable, is there

11 another viable option that we haven't looked at based on

12 what we looked at five years ago, so is this something

13 viable, and viable meaning economic for the U.P.

14 MR. MacINNES: Has there been -- a little

15 bit different subject, maybe you're going to cover it --

16 interconnection with Manitoba and bringing down hydro

17 from northern Manitoba, is that something that is

18 proceeding, or is there -- I know there were some studies

19 to bring hydro down to, you know, to help balance the

20 wind in western MISO areas.

21 MS. CLARK: The only -- the last thing

22 that I know, I know that we do have a lot of hydro in

23 MISO already, and particularly Zone 1 a couple of our

24 market participants do have contracts with Manitoba

25 Hydro, and I know there was a -- it's a big plant that


40

1 they were building, I don't know about the -- I think

2 you're asking about bringing more from Manitoba Hydro. I

3 think we would have to -- if it's in the queue, it would

4 really determine that piece of it if there's something in

5 the queue for that.

6 MR. CLIFT: I think at the moment it goes

7 as far as, planning wise, to Duluth, it stops there. So

8 probably hasn't come in to either Michigan 2 or 7 yet.

9 MS. CLARK: Yeah, just Zone 1, which our

10 Zone 1.

11 MR. CLIFT: Right.

12 MR. MacINNES: But just getting it into

13 MISO or into the main area is --

14 MR. CLIFT: Will help.

15 MR. MacINNES: -- helps.

16 MS. CLARK: That's usually the main, from

17 what I know, that's usually where most of it is going in,

18 like I said, Zone 1, because it's different market

19 participants in that zone that are -- that have those

20 contracts, but I haven't heard of anything from the Zone

21 7 perspective.

22 MR. MacINNES: What about the nuclear

23 plants in Illinois in terms -- there's been an awful lot

24 of discussion about whether or not they're going to be

25 viable, and do you have any updates on that?


41

1 MS. CLARK: I do. So it looks like the

2 bill, it's called the Future Energy Bill in the State of

3 Illinois, and it looks like it is ready for the governor

4 to sign, so it passed legislation, and they will

5 basically have some type of subsidy for the nuclear

6 plants, so it looks like they're still going to be

7 around, and they get a ten-year I believe subsidy, like

8 it's called a zero emission subsidy for ten years; and

9 there's some, in that bill there's some type of stability

10 factor that says that the rates to the consumers will not

11 go over I think it's two something percent year over

12 year. So again, if you think about if the rate is a

13 dollar, it won't go, you know, like triple or double or

14 anything like that, so there's something in there for

15 consumers. There's also some what we call, I think it's

16 called low-income sort of subsidies built into the bill,

17 so it looks like the governor is supposed to sign off on

18 that bill, because it passed legislation I think just

19 Friday or Thursday, which would be the state, if they

20 wanted to do subsidies, it wouldn't be MISO, it would be

21 something that the state would have to do.

22 MR. MacINNES: How will that affect

23 Michigan's energy crisis and reliability and all of that?

24 MS. CLARK: I don't know. Well, Michigan

25 has a bill, too, so it really depends on -- I would


42

1 imagine that if Exelon has contracts with the people in

2 Michigan, that those would still be honored, because I'm

3 assuming that that would be a contract that they would

4 still honor. I think the issue would be if they were to

5 go away and those contracts, basically if the plant shuts

6 down and those contracts are no longer viable, then

7 Michigan would need to figure where else are we going to

8 get the power from. But it looks like they're staying,

9 and -- well, but the governor still has to sign off on

10 it.

11 MR. CLIFT: All of your power projections

12 you've done to date have those staying on line. Is that

13 right?

14 MS. RAUCH: A lot of those were -- there

15 are some that are committed to PJM where we have

16 transparency, the others, a lot of those were in the

17 questionable category --

18 MR. CLIFT: Right. Okay.

19 MS. RAUCH: -- so they were that, part of

20 that low-certainty resource --

21 MR. CLIFT: Okay, those are the low-

22 certainty ones.

23 MS. RAUCH: Yeah.

24 MS. CLARK: So you saw some of the

25 switches from high to low where the red was turning into


43

1 green, so they were in that mix of red turning into

2 green. So I, you know, as long as the governor signs it,

3 and it looks like the nuclear will have ten more years in

4 Illinois.

5 MR. MacINNES: Okay. Are there anymore

6 questions?

7 Okay. Well, thank you very much --

8 MS. CLARK: Thank you.

9 MR. MacINNES: -- for updating us again,

10 we always appreciate it.

11 MS. RAUCH: And we do apologize that we

12 have to run, but thank you very much for accommodating us

13 today.

14 MS. CLARK: Thank you.

15 MR. MacINNES: Okay. Well, let's move on

16 here. Another item that we need to take care of up front

17 is Shawn has a presentation here on our budget, I

18 believe. Is that right?

19 MS. WORDEN: Yeah, it's just the budget

20 numbers. She didn't print it with the spreadsheet

21 packet, but it should just be a separate item with it.

22 It really hasn't changed much from the last meeting. But

23 really what your bottom number is, how much you have left

24 to grant out for this year is the 280,723.

25 MR. MacINNES: Okay. Actually, before we


44

1 finalize it, we should approve the agenda moving forward

2 here. So we have the agenda. Has everyone received the

3 agenda? Is there any discussion about the agenda?

4 All those in favor, please say aye.

5 BOARD MEMBERS: Aye.

6 MR. MacINNES: Opposed, same sign.

7 Okay. Sorry, I just -- I wanted to get

8 them so they can catch their flight here. So this is

9 the -- this is the current budget?

10 MS. WORDEN: Yes.

11 MR. MacINNES: So we've granted out

12 217 -- or excuse me -- 211,600 for 2017?

13 MS. WORDEN: Yeah.

14 MR. MacINNES: And we have 280,723

15 available?

16 MS. WORDEN: Yes.

17 MR. MacINNES: Okay. Is there any

18 questions about that?

19 MR. ISELY: This has gotten much clearer

20 over time, so thank you very much for your efforts on

21 that.

22 MR. MacINNES: Yes, thank you.

23 MS. WORDEN: It's just how my brain

24 works. I knew what it said, but --

25 MR. MacINNES: Okay. Well, we'll try to


45

1 stay on budget here.

2 MS. WORDEN: Okay.

3 MR. MacINNES: Thank you.

4 MS. WORDEN: Thank you.

5 MR. VILMONT: Sorry to ask that. But

6 that is account year --

7 MR. MacINNES: This is the -- it's a --

8 MR. VILMONT: An accounting year, not

9 calendar year, right?

10 MS. WORDEN: It's a fiscal year, yes.

11 MR. VILMONT: Fiscal year.

12 MR. MacINNES: Fiscal year, yes.

13 Okay. How about if we do an introduction

14 here of board members, since we had a couple new members

15 that have joined us. Maybe we can start with Brian, and

16 he can give you little bit of his background.

17 MR. VILMONT: Well, appreciate it.

18 First, thank you very much for allowing me to be on the

19 board, looking forward to this. I'm a civil engineer by

20 trade, so from the Grand Rapids area, so I've been

21 involved with municipal civil work, so water, sewer,

22 street infrastructure for 25 years now. Heavily into the

23 asset management side of our business. So if you guys,

24 if anybody's familiar with the SAW grant program that's

25 been coming about, that's the storm and sanitary asset


46

1 management programs that has been funded through the DEQ,

2 we've been heavily involved in that. So just a, I think

3 the side of asset management and having sustainable both

4 rates and the physical infrastructure for consumers is

5 really important. So again, thank you very much for

6 letting me be here today and being part of the board,

7 appreciate it.

8 MR. MacINNES: And maybe we could have

9 Paul, I think it would be good if each of the board

10 members gave a little bit of their background, and then

11 we'll go around and have some of the grantees do that as

12 well.

13 MR. ISELY: All right. I'm Paul Isely,

14 I've been here for a few years now. I'm currently the

15 Associate Dean of the Business School at Grand Valley,

16 I'm an economist by trade, I have an undergraduate in

17 physics, so I have that the technical side a little bit.

18 I've specialized in dealing with market values for things

19 that aren't sold, so it can have -- it has brought me

20 into working in energy issues from the environmental

21 side. So that's sort of my background.

22 MS. HAROUTUNIAN: I'm Susan Licata

23 Haroutunian, I'm an attorney in Detroit. And I have no

24 power background at all, but I have a user background,

25 and that gives me ample reason to look at everything that


47

1 comes before us and try to understand what's affecting

2 what I pay and what my neighbors pay.

3 MR. PASSMORE: Good afternoon. I'm Sam

4 Passmore, and also thrilled to be here and thanks for the

5 opportunity to serve on the board. My day job, I'm the

6 director of the environment program at the C.S. Mott

7 Foundation based in Flint, Michigan. Don't have a strong

8 science and engineering background at all. Prior to

9 coming to Mott 15 years ago now, I was working in the

10 environmental advocacy field actually in South Carolina.

11 And I guess one thing I bring to the board is a grant-

12 making experience, and so to the extent that that's the

13 function of the board, hopefully I can contribute there.

14 And then recently in the last couple years, we've

15 developed a grant-making interest in the Foundation

16 around clean energy issues, both internationally and in

17 Michigan, so I've been on a pretty steep learning curve

18 and this will just contribute more to that, so I'm really

19 looking forward to the opportunity.

20 MR. LISKEY: I'm John Liskey, I'm a

21 lawyer in private practice. I represent CARE, which

22 stands for Citizens Against Rate Excess. Prior to my

23 private practice, I was with the Attorney General's

24 office for several years and was counsel to this board.

25 In that capacity, I could see that there was a couple


48

1 areas that were not being -- residential ratepayers were

2 not being represented, that was primarily the Upper

3 Peninsula, and also at the MISO and FERC activities and

4 proceedings, and so I left the Attorney General's office

5 and cofounded CARE with Ms. Kelly Kitchen, sitting over

6 there, and have been a grantee of this board since 2009.

7 MR. MOODY: Michael Moody from the

8 Attorney General's office. I worked with John for a

9 bunch of years, I've been there 21 years now at the AG's

10 office, probably doing the utility stuff maybe 18 or so.

11 And we represent the board, and we're also a separate

12 recipient of the money from the board, the UCRF, Utility

13 Consumer Representation Fund, that we kind of split and

14 share and do the consumer advocacy work. And, you know,

15 we work with all your grantees here, as you know, and I

16 work together in the same cases mostly. You know,

17 sometimes we're in some of them with them, in other ones,

18 you know, they're in, we're not, but a lot of times we're

19 coordinating and trying to make the best of the money we

20 have and, you know, make the greatest impact for

21 consumers.

22 MR. KESKEY: Don Keskey, I am a lawyer,

23 I'm a member of the -- a principal in, one of the

24 principal members of the Public Law Resource Center in

25 East Lansing. Previous to private practice, I was 25


49

1 years with the Attorney General's office when Frank

2 Kelley was the Attorney General, 20 of which I was either

3 5 years as the assistant division head and then 15 years

4 as the division head of the somewhat large division that

5 represented the Public Service Commission and the State

6 of Michigan in energy matters, transportation, gas,

7 electric, communications, even ferry boats -- I didn't

8 get any free tickets -- before state agencies, state

9 courts, federal courts, and the federal agencies,

10 including the Federal Energy Regulatory Commission, the

11 FCC, and we also maintain a lot of vigil on nuclear

12 plants in Michigan and nuclear waste issues. And I also

13 represented 35 states against the federal government,

14 both attorney generals and their state regulatory

15 commissions, in suing the Department of Energy for

16 failing to accept nuclear waste from the various plants

17 in accordance with a statute and the contracts, the

18 binding contracts that they had with the states and the

19 rate -- not the ratepayers, but the states and the

20 utilities.

21 And so we represent at this time Great

22 Lakes Renewable Energy Association, which has been

23 involved in cases and looks at some of the forecasts of

24 the utilities, the big utilities, Edison and Consumers,

25 as to whether their forecasts validly are incorporating


50

1 known increases in renewable energy as it expands and

2 it's contributing to the mix of the power available to

3 Michigan and the impact of that on costs, PSCR costs,

4 which is what this board gets involved in, which is your

5 cost of fuel, purchased power, transmission, and a number

6 of other costs; and also the Residential Customer Group,

7 which has been involved in several MPSC cases, a

8 relatively new nonprofit, both of the organizations are

9 nonprofit, but has been involved in some cases dealing --

10 focusing more on the residential class, which percentage

11 wise the increases in rates to the residential class has

12 expanded greatly as the cost of industrials have gone

13 down, the costs have shifted from industrials to the

14 residential class.

15 MR. MacINNES: Actually, I have a chart,

16 just happen to have a chart that shows how much

17 residential rates have gone up compared to -- residential

18 are here, industrial are at the bottom of the chart,

19 38 percent over, this is since 2008.

20 MR. KESKEY: So there's really, to

21 conclude, there's a real need to focus on the combined

22 impact of what they call general base rate cases, which

23 these two utilities are filing every year, which pile on

24 each other using projected test years going out future 12

25 months, and then the multibillion dollar costs under Act


51

1 304, which this board looks at intensely, and that is the

2 purchased power agreement increases, the gas generation

3 increases, coal, transmission costs, everything that gets

4 wrapped into the, what they call the power supply cost

5 recovery clauses and the five-year forecasts.

6 And one case tends to build on the other,

7 sometimes the Commission doesn't buy your argument the

8 first case, but then it starts buying your argument

9 later; sometimes the sensibilities about the rate impacts

10 becoming increasingly clear, and so sometimes you win

11 something and sometimes you lose something, it's a

12 continual effort, and that's why this board was created

13 is to have some voice in these proceedings other than the

14 utilities own applications and their own positions.

15 Thank you.

16 MR. WILSON: I'm Jim Wilson. Again, I

17 work for LARA, I assist the board in the processing of

18 the grants awarded, payments, amendments, whatever's

19 needed in that case.

20 MR. CLIFT: James Clift, policy director

21 of the Michigan Environmental Council. I've run mainly

22 on the policy side of the game here, I'm not an attorney.

23 I was around the legislature when they did the 2000

24 amendments, the 2008 amendments, and now the pending 2016

25 amendments, and as well we have been in the residential


52

1 ratepayer space for about a decade now.

2 MR. BZDOK: Christopher Bzdok. Welcome

3 to the new board members, and nice to see you again to

4 the long-standing board members. I represent MEC in the

5 Commission proceedings, I have been doing that since 2008

6 or early 2009. I do some of that work as well in Ohio

7 and a little bit of it in Illinois, also. We will have

8 plenty to talk about in terms of MEC's work in those

9 proceedings. MEC attempts to generally find issues that

10 we can work on where we believe there is a synergy

11 between the financial interest of residential customers

12 and larger environmental or clean energy policy goals,

13 and so we always present those to the board and try to

14 highlight, you know, where we believe how this serves

15 both of those objectives.

16 I will say that now or later, a lot of

17 the issues that we are presenting both in our status

18 report and also in the various requests and amendment

19 requests that we make are issues that have resulted from

20 a work that's been going on over a series of cases, so if

21 either or both of you ever want to have a more in-depth

22 briefing on some of what has been going on there with

23 material, supported by materials or not, by phone or in

24 person, you know, we'd be happy to take the time and do

25 that whenever it was convenient for you.


53

1 MR. MacINNES: Jim, you're here a lot.

2 MR. AULT: Okay. I'm not a fund grantee.

3 I'm Jim Ault, I'm a lawyer and lobbyist with the Michigan

4 Electric & Gas Association. We're a trade association of

5 regulated utilities, and our members are sometimes the

6 subject of intervention grants from this board. We're

7 not the big two in our group, they have no say in our

8 policy, although we participate with them on common

9 activities, usually at the regulatory level. Some of the

10 companies in our group would be Indiana Michigan Power,

11 Alpena Power, Michigan Gas Utilities, the Upper

12 Peninsula, electric and gas utilities up there. And my

13 background, I've been an attorney for quite a number of

14 years, I worked with Don Keskey in the AG's office at one

15 time, I was once a grantee attorney for this fund for

16 MCAAA back in the '90s, and I was in private practice for

17 quite a while in energy.

18 MR. MacINNES: Okay. Kelly Jo, would you

19 like to tell us your --

20 MS. KITCHEN: Yeah, sure. Well --

21 MR. MacINNES: Before you start, I might

22 add that Kelly Jo is interested in our administrative

23 position, and we're, you know, we had one conversation,

24 and we're going to talk some more, but I thought it would

25 be appropriate to introduce her as well.


54

1 MS. KITCHEN: Yeah, there's going to be

2 many conversations. As I'm president of CARE, the

3 learning curve, as some of you stated, is almost

4 exponential. I am a retired teacher of mathematics and

5 science, 32-veteran teacher, and I'm an advocate by DNA,

6 and I just love the fact that Michigan has the foresight

7 to invest in a board that oversees and assists the

8 ratepayers in Michigan, and I think it's a vital role

9 that the board plays, and I'm really pleased to be a part

10 of it and in a capacity that I can fit and look forward

11 to working with all of you in some capacity.

12 MR. MacINNES: Okay. Thank you. And I'm

13 Jim MacInnes, I'm a business owner and am a professional

14 electrical engineer, have been involved with -- I was a

15 power engineer in my other life and worked for the

16 company that designed the Ludington Pump Storage plant, I

17 also used to develop and finance power plants, I've done

18 a lot of power plants' cost estimating, and I'm a member

19 of the Electrical Engineers Professional Association, so

20 it's something I spend a lot of time studying.

21 Okay. Let's move on to some more board

22 education here, and that would be a discussion of Senate

23 Bill -- you want to do both of them or Senate Bill 437

24 and/or 438?

25 MR. CLIFT: I can do whatever you want me


55

1 to do, and others in the room can chime in.

2 MR. MacINNES: So maybe I'll preface it

3 here that a number of us have been working on this. The

4 legislature has proposed significant changes to our

5 energy law in Michigan, and they've been working on it

6 for several years now, and many of the people at the

7 table here have been involved and have testified on

8 energy law and energy issues. This Senate Bill 437

9 happens to impact the Utility Consumer Participation

10 Board and our funding and our scope of intervention, and

11 so I know it's being discussed in this lame duck session,

12 and we're just going to go, we don't know at this point,

13 but it's important to this board because it identifies

14 what we can intervene in, what kinds of cases we can

15 intervene in, and then also our budget. So I've asked

16 James Clift here, who has been very involved with that,

17 with the legislators, to maybe provide his summary of

18 where we're at.

19 MR. CLIFT: So I guess I'll just start

20 with the UCPB provision, then I'll do some of the broader

21 pieces, and then again, others can chime in. It's, all

22 together, it's 250 pages of legislation, so we're not

23 getting into the details.

24 Big picture, you know, on the UCPB side,

25 you mentioned funding first. So as you can see from your


56

1 current budget, the current year's assessment of

2 $1,180,000, under the bill, it breaks it up a little

3 different than it's done in the past, so it's not kind of

4 the same formula that's taking it through. You total all

5 of it up and the assessment would go up to $1,750,000,

6 900,000 dedicated to the Attorney General's office, 850

7 dedicated to the board kind of broken up into a couple of

8 different categories there. So more money than you had

9 seen previously, that's good news.

10 The legislation in general kind of raises

11 a couple of new types of dockets. We have had the

12 certificate of necessity in the past, and that's when a

13 utility wants to build either a new power plant or enter

14 into a new purchased power agreement; that has changed a

15 little bit being that's Section 6s, but we have a new

16 section, brand new section, 6t, which is all about

17 integrated resource planning, and two years, if the bill

18 is to become law, two years after that effective date,

19 the Commission and the Michigan Agency for Energy will

20 start working on a process where the utilities would be

21 kind of putting together comprehensive plans for all the

22 investments they plan to make to meet Michigan's energy

23 needs going forward on a 5-, 10-, and 15-year basis. And

24 then the law kind of then dictates -- there's some

25 bouncing back and forth between those two provisions in


57

1 the law, when one does apply and when does the other

2 apply. The current certificate of necessity process

3 actually included a requirement to do an integrated

4 resource plan, so it's there, and it's still there, so

5 now the law would have two different integrated resource

6 planning sections.

7 The bottom line is is that new builds

8 above 225 megawatts would be required to go through the

9 certificate of necessity, so major power plants would go

10 through there. Smaller power plants, module, natural gas

11 units potentially or other investments would be able to

12 go through the new integrated resource planning process

13 only and not have to go back through the certificate of

14 necessity. There is a number of requirements for what

15 has to be included in those plans, there's a role for the

16 Michigan Agency on Energy to kind of do what is is called

17 kind of modeling scenarios, so it would take some

18 information and say, okay, you have to model at least

19 these couple of scenarios maybe, and then let the

20 utilities model what other scenarios they wanted to model

21 as part of that process.

22 Both those dockets under 6s and 6t will

23 be new dockets eligible for grants through the UCPB. So

24 that's kind of the newest thing that gets added to the

25 board as far as the types of dockets, they're explicitly


58

1 mentioned as types of dockets that you would be able to

2 fund. There's some changes to the reporting

3 requirements, both from the grantees and the information

4 that the board would then transmit to the legislature are

5 included, not major changes, I think what you'd expect,

6 you know, as far as the types of activities we're

7 involved in and kind of some of these successes over

8 time.

9 The UCPB -- maybe I'll pause there, see

10 if there's any questions or additional comments that

11 others would like to add.

12 MR. MacINNES: The 850,000, is that, was

13 that number changed recently, or I guess I was under the

14 impression it was 750?

15 MR. MOODY: Yeah, I think it might be a

16 million and then 750 or something like that.

17 MR. CLIFT: It's 900,000, 650, and then

18 100,000, and then 100,000.

19 MR. MOODY: Yeah, it's kind of weird.

20 MR. CLIFT: It's kind of weird. And

21 they're broken up between referencing Subsection (10) and

22 Subsection (16).

23 MR. MOODY: Like smaller utilities and

24 large utilities funded differently.

25 MR. CLIFT: And again, so it's not -- I


59

1 wasn't a hundred-percent clear when I read through it as

2 far as the difference even between (10) and (16) in the

3 legislation itself.

4 MR. MOODY: I think that's what we read

5 it as is, it's like a 1, I think 1.9, I'd have to look at

6 it again, and like a million AG and about, whatever it

7 was.

8 MR. CLIFT: That was my first read was a

9 million 650, so I'm not exactly sure when this --

10 MR. MOODY: There was more to both of us,

11 I know we got a little bit more out of the deal.

12 MR. MacINNES: I thought it was 150.

13 Well, let's see. I thought we got 100 more, you got 150.

14 MR. MOODY: Yeah, something like that.

15 MR. MacINNES: But there've been so many

16 versions, I don't know.

17 MR. MOODY: Yeah. I think of the

18 nightmare and the take it away, put it back in.

19 MR. CLIFT: John, you got an

20 interpretation on this one for us?

21 MR. LISKEY: Well, I think the extra

22 hundred is coming from utilities that serve under a

23 hundred thousand customers, which is new, and that's

24 primarily Upper Peninsula customers, and so that is a

25 separate new section in the bill that brings in that


60

1 extra hundred thousand.

2 MR. MacINNES: To make a total of?

3 MR. MOODY: Yeah, what is the total? I'd

4 have to look at it again.

5 MR. CLIFT: Total of 750. Subsection (a)

6 is the 900, Subsection (b) is the 650 from the larger

7 utilities, and then there's both a Subsection (c) and

8 (d), each of them --

9 MR. MOODY: Each get a hundred --

10 (Multiple speakers.)

11 MR. CLIFT: Each, (c) and (d),

12 referencing a new 100,000 coming to the board for two

13 different purposes, which the difference isn't entirely

14 clear in my mind.

15 MR. MOODY: That makes it about a million

16 and 750, I think.

17 MR. CLIFT: That would make it 1,750,000

18 altogether.

19 MR. MOODY: Yes, I think it's --


21 MR. MacINNES: But we don't, we still

22 don't quite know how that's divvied up?

23 MR. CLIFT: It's very clear in the bill

24 how all of the money is divvied up.

25 MR. MacINNES: So say what it is again.


61

1 MR. CLIFT: Well, my read, and again,

2 this was a little different from my earlier

3 understanding, is that the board would get 850. Now,

4 these two provisions on 100,000 I don't think were both

5 include in the earlier versions, so that's where a little

6 bit of my confusion came, so we'll wait and see if they

7 provide anymore clarity on that point. And then they

8 always reference some other paragraph within the enabling

9 legislation; one of the $100,000 provisions referenced

10 paragraph 10, which is a very general section, and one of

11 them references paragraph 16, which is specifically which

12 dockets you're allowed to enter. So the other ones you

13 could argue might be FERC proceedings or other

14 proceedings outside of referenced proceedings in the Act.

15 MR. MOODY: I'd have to reread it again,

16 but our understanding, because that darn language changes

17 all the time, but our understanding was it was, you know,

18 the two big chunks of money, whatever it was, 900 for us

19 or somewhere around there, and then 750 or so, or 650

20 maybe for the board, and then there's another two

21 provisions that just dump another hundred in each that

22 just depends on who pays that money between the utilities

23 and then we get our million and, the AG gets a million, I

24 think you guys get like around 750.

25 MR. CLIFT: Oh, okay, that's it. I'm


62

1 sorry. Yeah, now I got it all. So you get a million

2 total.

3 MR. MOODY: Yeah, that's right.

4 MR. CLIFT: So you get, out of the small

5 ones, you get 100,000 plus the 900,000, the board gets

6 the 650 plus the 100, so you're at 750.

7 MR. MacINNES: Right, that's where I

8 thought --

9 MR. CLIFT: That's where it is. I'm

10 sorry.

11 MR. MOODY: And it's confusing, because

12 if you look at the, even the legislature called us on

13 this, that if you look at the Senate fiscal analysis,

14 they flipped it, so the actual filed Senate fiscal

15 analysis is completely wrong, it's not what's in the

16 language in the statute.

17 MR. CLIFT: That's what it is, million

18 and 750.

19 MR. MacINNES: I was hoping that --

20 MR. CLIFT: I was right. But I'm not --

21 MR. MacINNES: You were right.

22 MR. CLIFT: Sorry. I reread it this

23 morning thinking, well, that's not what I remember, but I

24 just clarified it.

25 MR. MacINNES: And the other change in


63

1 terms of the scope --

2 MR. CLIFT: Is the dockets, which is now

3 rate cases, PSCR cases gas, PSCR electric, the new

4 certificate of, the older certificate of necessity, the

5 new integrated resource planning process, those are the

6 five designated dockets.

7 MR. MacINNES: So that's just about

8 everything, isn't it?

9 MR. MOODY: Yeah.

10 MR. CLIFT: The one that's not in there,

11 which wasn't in the last one, is of course would be

12 renewable energy plans, energy optimization plans, which,

13 according to an Attorney General, you had been funding,

14 they are not mentioned in the legislation.

15 MR. MOODY: I think the way they had that

16 language now, it's kind of anything that affects rates of

17 ratepayers, you know -- I mean they got this broad

18 language that's going to pretty much cover I think

19 anything.

20 MR. CLIFT: I think it would be

21 consistent with prior interpretation.

22 MR. MacINNES: Okay. So that's good,

23 because before we were not supposed to be intervening in

24 rate cases unless there were Act 304 issues --

25 MR. MOODY: That's correct.


64

1 MR. MacINNES: -- in the rate case. So

2 that's a good thing.

3 MR. ISELY: This extra hundred thousand

4 is something that we would be having to account for

5 separately, because it sounded that way to me?

6 MR. CLIFT: It comes from a different

7 source. I don't think, as far as your spending it, I

8 think you would just be putting one report on how all of

9 the money was spent, I don't see a separate reporting

10 requirement for that separate money.

11 MR. ISELY: Okay.

12 MR. MOODY: Yeah, that's my

13 understanding. I think it's just you used to only get

14 money from like the big four or whatever, you know, big

15 four gas and big two electric, and now it's even smaller

16 utilities have to pay into the fund.

17 MR. MacINNES: How about co-ops?

18 MR. MOODY: No, I don't think anything on

19 co-ops.


21 MR. CLIFT: Only regulated entities.

22 MR. MacINNES: Okay. Co-ops self-

23 regulate.

24 MR. CLIFT: For the most part.

25 MR. MacINNES: Okay. Anything else on


65

1 that that you'd like to tell us about?

2 MR. CLIFT: You know, again, willing to

3 answer any questions. There's, of course, a number of

4 changes in the waste reduction plan, the renewable energy

5 portions, the largest changes have to do with the choice

6 market and the requirement to show capacity and how this

7 new capacity charge. You know, you heard about the MISO

8 process, there's a whole provision in here on how the

9 State of Michigan opts out of that whole process and sets

10 its own capacity charges, that takes a lot of the pages.

11 But again, available to answer any questions, again, I

12 can go into a little bit more detail on any provision.

13 MS. KITCHEN: Is there a timeline for

14 these, this bill, like when it might get --

15 MR. CLIFT: This is all guessing. I'd

16 say that there is a -- they are going to take a run at it

17 this week in the House, and then they'll have next week,

18 they're scheduled in session through next week, so

19 they've got six session days left, they'll caucus

20 tomorrow, they'll probably start working on Wednesday,

21 and we will we see what happens.

22 MS. KITCHEN: Okay.

23 MR. MacINNES: That's what I'm hearing,

24 too. Any other questions, comments? Good. Well,

25 thanks, James.


66

1 Okay. Let's move on to -- we've already

2 covered the one business update, which was the budget,

3 for Shawn, and she wanted to scoot out early. So now

4 into the MEC grants. Chris.

5 MR. BZDOK: Thank you, Mr. Chairman,

6 members of the board. Christopher Bzdok on behalf of the

7 Michigan Environmental Council. These, we have I guess I

8 would call them two categories of business items in front

9 of you today; the first is a request to transfer minor

10 amounts of unused expert funds from the DTE and Consumers

11 Energy 2016 PSCR plan cases, 17918 and 17920, over to the

12 legal budget in the pending DTE Electric rate case,

13 18014, to support the final rounds of briefing in that

14 case. So that is not an increase in grant amount, it's a

15 transfer of existing funds that will be unspent in the

16 cases where they remain to the electric rate case. And

17 we have talked about issues in the DTE Electric rate case

18 on a number of occasions, and I did send you relatively

19 recently a memo with an update on the proposal for

20 decision in the Electric rate case, which hopefully you

21 all received. That PFD came out relatively recently,

22 since the time we submitted our main materials for this

23 meeting, and so there is a rundown of issues and

24 recommendations in that proposal for decision, which are

25 largely favorable; most of our effort will be


67

1 concentrated on defending recommendations in the PFD as

2 opposed to taking exception to recommendations in the

3 PFD. It's a very solid piece of work with a number of

4 ratepayer-favorable recommendations, and so that's the

5 main effort, focus of our efforts in that.

6 We also -- the other category of requests

7 that we have are sort of the continuation of our fiscal

8 year '17 grant requests related to the Consumers and DTE

9 Electric 2017 PSCR plan cases. So we submitted those

10 requests in July for your August 29th annual grant

11 meeting, and the board granted us partial funding on

12 those cases with an instruction to come back in December

13 and seek the rest once we had a little bit more

14 information on some of the issues in those cases. So we

15 are doing that now, less $10,100 in each case, or less

16 $20,200 overall in the case budget for those cases

17 because we were able to get some outside contribution

18 towards our work in those two cases, and so that lowers

19 the amount that we are requesting from the board.

20 MR. MacINNES: So the case numbers are?

21 MR. BZDOK: 18142 is Consumers, 18143 is

22 DTE.


24 MR. BZDOK: Very briefly, I could just

25 touch on the issues --


68

1 MR. MacINNES: That would be good.

2 MR. BZDOK: -- or the updates. So again,

3 all of the issues that we have identified are essentially

4 continuations of work from prior cases. In the Consumers

5 case, we really have two issues, two main things that

6 we're working on at this time, which one has to do with

7 wind energy proposals from private wind energy developers

8 in the PSCR, and the second issue has to do with the

9 impact of pollution control sorbents and other

10 environmental requirements on the overall cost to operate

11 Consumers Energy's what we call the Medium Four coal

12 units. So the Campbell plants has three coal units, one

13 of them is relatively recent and relatively efficient to

14 run, the other two are older, and then the Karn plant has

15 two units, so the two Karn units and the two older

16 Campbell units we call the Medium Four units; and we are

17 in possession from the rate case of economic analyses of

18 those four units which indicate that they are not

19 economic to continue investing in and operating past the

20 year 2021 or so, and there may be some uneconomics, you

21 know, sooner than that, or there may not be. In addition

22 to that we have prior Commission orders indicating an

23 interest in how the costs of new pollution chemicals that

24 will be added to those plants are impacting the PSCR

25 costs of those plants. So that's a second set of issues.


69

1 We don't have from the filing information on the

2 pollution control sorbent costs broken down in a way that

3 I can provide you with really meaningful information on

4 how those look, we have requested that information in

5 discovery. We are also requesting whether there are any

6 updates to the economic analyses from the rate case.

7 On the wind energy issue, in the last

8 PSCR plan case we introduced evidence concerning some

9 unsolicited proposals for power purchase agreements for

10 wind energy from two private wind developers concerning

11 three potential wind projects, one of which Consumers

12 accepted and the other two of which Consumers declined,

13 and what was interesting was that the indication from the

14 renewable energy filing and then subsequently from

15 discovery in the PSCR case was the cost of those wind

16 power contracts was lower on a levelized basis than

17 Consumers Energy's PSCR costs, and that's -- that doesn't

18 say everything, but that certainly raises a flag about

19 are there opportunities to enter into wind contracts to

20 get some of these other projects built outside of the

21 formal renewable energy program that will nonetheless

22 save customers PSCR costs down the road, and according to

23 Consumers Energy's economic analyses, that was possible

24 at the time.

25 Consumers indicated through the course of


70

1 the proofs and the hearing in that case that, well, they

2 were going for other reasons to be going out for a

3 request for proposals on wind contracts, and mainly that

4 was being driven by certain large primary or industrial

5 customers that Consumers had who were approaching the

6 Company with that request, they want to tell their

7 customers, their shareholders, that they're moving in

8 more of a renewable energy direction, and so it's

9 customer-driven in that sense.

10 Consumers did the RFP, they -- this is

11 new information now -- they received 12 responses to the

12 RFP, which we don't have yet but we've requested in

13 discovery, and then they decided instead to expand one of

14 their own Company-owned projects in the Thumb called the

15 Cross Winds Project, and the argument that they made in

16 the request to the Commission to do that was that they

17 could expand out this existing project at a lower overall

18 incremental additional cost than the RFPs to build these

19 other projects would be. And that may well be true, but

20 what we're interested in still is how much other wind by

21 a private developer is out there on the table being

22 offered; what kind of cost implications does it have for

23 the PSCR; what kind of customer savings implications does

24 it have, and so that's another main area or category of

25 issues that we're trying to explore in that case.


71

1 MR. PASSMORE: Can I ask you a question?

2 MR. BZDOK: Yeah, please.

3 MR. PASSMORE: So if I'm following

4 correctly, the main question you're pursuing isn't

5 whether the decisions they've made were economical

6 decisions, it's whether there are additional sources of

7 wind that would also be economical?

8 MR. BZDOK: I would generally agree with

9 that. I do not anticipate at this time based on the

10 information we have that we would challenge Consumers'

11 decision to expand its Cross Winds Energy Park, and I

12 would accept, you know, subject to check, their

13 representation that that existing park can be expanded at

14 a lower incremental overall cost, although we will of

15 course verify that. The goal based on these prior

16 solicitations and these prior proposals from the fall of

17 2015 is a belief that there may be other PSCR cost-saving

18 opportunities out there via these other potential

19 contracts.

20 MR. VILMONT: I have a question about

21 that. So the availability in these potential outside

22 industry sources, then, is that, the availability, we're

23 only learning about that through the discovery process,

24 or is there another process by which we can -- that that

25 information is available?


72

1 MR. BZDOK: The 12 -- so the new

2 information that we're presenting today, that there were

3 12 responses to the RFP, that came via a filing that

4 Consumers made relatively recently, maybe even last --

5 maybe about a month ago, in a renewable energy docket in

6 which they were seeking the Commission's approval to

7 enter into basically a purchase order with GE, I want to

8 say it was, to order equipment for the expansion of Cross

9 Winds. So they gave us some very basic facts about we

10 got the 12 responses, we had this other opportunity, and

11 so that's a reason -- you know, we tend to watch these

12 other dockets for public information to be useful.

13 I think you were maybe going to jump in.

14 MR. CLIFT: Well, I think this is

15 interesting from the new members' standpoint is that you

16 are so constrained by which docket you're in, so in a

17 power supply cost recovery case, everything is supposed

18 to relate back to whether they should be spending this

19 money on the fuel and other things. The new integrated

20 resource planning process would be in theory a place

21 where all of this stuff would get set on the table at the

22 same time.

23 MR. BZDOK: And I agree with that. In

24 the PSCR case, there are additional issues concerning

25 PPAs that are going to expire and what are they going to


73

1 do about that and concerning future plants to build and,

2 yeah, so it all -- it's going to come up in this PSCR

3 case and there are reasons to push it in the PSCR case,

4 but it may end up being relevant for some of these other

5 things coming down the pipe --

6 MR. CLIFT: Down the road.


8 MR. BZDOK: -- legislation as well. What

9 in my mind is interesting is even though Michigan's

10 existing renewable energy standard has just about been

11 attained via a combination of 50-percent utility build

12 and 50-percent private contracts, that even at that point

13 there are still 12 projects out there, you know, looking

14 for a customer, so that certainly has our attention, and

15 that's -- because we're relying as to these other three

16 projects on not our analyses, but Consumers Energy's own

17 analyses that those were going to be cost saving for

18 customers, you know, this is a hot issue for us.

19 I'm happy to talk about the DTE case in a

20 similar sort of outline. In DTE's PSCR plan case for

21 2017, there are two main categories of issues we're

22 pursuing; the first is a contract that's been proposed

23 for the firm transport of natural gas for the NEXUS

24 Pipeline, which is a yet-to-be approved or built

25 greenfield pipeline that will run from the Marcellas/


74

1 Utica shale gas production region through Ohio and up to

2 the MichCon City Gate, which is a liquid trading hub for

3 natural gas in southeast Michigan, and the proposal is to

4 enter into a contract for the firm transport through this

5 pipeline of natural gas from Utica/Marcellas to MichCon

6 City, and it will be 30,000 decatherms a day for a

7 certain period of time, and then at some point in the

8 early 2020s it will ramp up to 75,000 decatherms a day of

9 natural gas. The buyer under the contract is DTE

10 Electric Company, the seller under the contract is the

11 NEXUS Project, which is a 50/50 partnership of Spectra

12 Gas and DTE Pipeline Company, which is an unregulated

13 affiliate of DTE Energy and, therefore, of DTE Electric

14 Company, which raises issues under standards in the PSCR

15 statute about obtaining fuel from affiliate suppliers,

16 which raises issues under the MPSC's Code of Conduct for

17 affiliate transactions between regulated and unregulated

18 affiliates of the same utility, which raises general

19 economic issues about is this the most reasonable and

20 prudent thing to do at this time.

21 The board supported work on this issue in

22 the 2016 PSCR plan case, and we had indicated to the

23 board at the time we made this proposal that we were

24 expecting a PFD and the PFD was going to rule on two

25 issues, one was the legal issue of whether costs which


75

1 would not begin to be incurred until 2017 could be

2 "preapproved" in a 2016 PSCR plan case, and we were --

3 our position was they could not; and then there were a

4 series of factual and economic arguments as to the nature

5 of the transaction and whether this was a good deal or a

6 bad deal. The proposal for decision, which is out, rules

7 in our favor on the legal issue and recommends against

8 our position on the factual issues. Ruling in our favor

9 on the legal issue largely takes care of this for us as

10 to 2016 because if you can't preapprove the costs in 2016

11 and you really have to make a final decision in 2017,

12 it's still important that this ALJ made recommendations

13 that we disagree with as to whether this is a good deal

14 or bad deal, and so we have taken exception to those, but

15 we are going to have a chance to battle those out in the

16 2017 case with a different ALJ than we had in the 2016

17 case. So -- and this will be additional permutations,

18 but basically that's where we sit right now is we have a

19 PFD out that's favorable on the legal, unfavorable on the

20 factual, we have a new case that's ramping up, and so we

21 are seeking the remainder of the funds requested less the

22 amount I indicated before to continue to pursue that

23 issue.

24 MR. MacINNES: So, Chris, so is there a

25 certain percentage of gas that the regulated company can


76

1 buy from its unregulated subsidiary project, a project

2 that's half owned by its unregulated subsidiary that

3 would not create a Code of Conduct issue?

4 MR. BZDOK: Not that I'm aware of. I'm

5 not aware of any threshold either in the PSCR statute on

6 buying fuel from an affiliated company or from the Code

7 of Conduct, you know, some threshold below which those

8 standards don't apply.

9 MR. MacINNES: So this Code of Conduct,

10 it's -- you know, you've got a regulated utility buying

11 gas from a project that's half owned, a $2 billion

12 project that's half owned by a nonregulated entity of

13 that utility, and part of the financial backing of the

14 pipeline project, correct me if I'm wrong, has to do with

15 the commitment by the regulated utility to buy some of

16 that gas?

17 MR. BZDOK: Yes.

18 MR. MacINNES: Is that right?

19 MR. BZDOK: Yes.

20 MR. MacINNES: So that seems like it

21 would be a Code of Conduct issue.

22 MR. CLIFT: And just for other board

23 members, Code of Conduct, if it was found to fall under

24 that, would then just be a heightened scrutiny of all of

25 the contracts by the Commission.


77

1 MR. BZDOK: Right. They can't pay --

2 they can't pay more than market price, and so figuring

3 out, well, what's market price and what is market price

4 going to be is one of the set of issues in determining

5 whether this is reasonable. There are other additional

6 questions. This is like one of these things where if I

7 really start talking about it, it would be hard to get me

8 to stop talking about because I'm somewhat obsessed with

9 this contract and project. But there are questions

10 about, well, we don't really need this level of gas until

11 the early 2020s, but we're going to lock in now so that

12 it's available when we do need it, but the supplier

13 actually has an out in the contract so that if they don't

14 have the gas available for us in 2022, they actually

15 don't have to provide it. So we're buying gas we don't

16 need so that we have a chance of getting gas we do need,

17 you know, several years from now. There are questions

18 about how are we determining this is economic. Obviously

19 I have, you know, I have a dog in this fight and I have a

20 perspective on it, but this is the, some of the things

21 we're advocating on. We have information via Company

22 presentations that the increase in the initial term

23 commitment of gas from the original amount, which I think

24 was 8,500 decatherms a day to 30,000, one of the two

25 reasons given for doing that was that the project needed


78

1 to show more market support to get built. So how that's

2 not a subsidy of an unregulated affiliate is

3 inconceivable to me.

4 MR. MacINNES: I might add, also, that my

5 concern about it is if you look at the present value of

6 the savings versus the cost, you know, if you just do an

7 arrow diagram for that, it shows a negative benefit for

8 the first -- it was eight or nine years, is it down to

9 six now or is it --

10 MR. BZDOK: Depending on the forecast.

11 MR. MacINNES: So here's what they're

12 doing; they're doing a 20-year forecast on natural gas

13 prices, which if anybody's followed natural gas prices

14 you know they're very hard to forecast, they're very

15 volatile, and that all the benefit of this project is

16 backloaded from years 10 through 20, and you present

17 value that all back and it wipes out the cost, the

18 negative benefit, for the first 10 years, and then you

19 present value it out against the 2 billion, and it's

20 like, hey, it makes money. That's the kind of -- as a

21 financial person, that's what troubles me when I see

22 that. If I ever brought that to my bank, they would not

23 be happy, they wouldn't approve it.

24 MR. BZDOK: If I knew what natural gas

25 would cost at the MichCon City Gate in 2025, you could


79

1 just reach me on my private Caribbean island.

2 So there's a whole set of issues there,

3 and we have provided the board with some fairly detailed

4 presentations and PowerPoints and such on this, which

5 we're happy to provide --

6 MR. MacINNES: Provided by the project

7 proponent.

8 MR. BZDOK: Some of them, yes.

9 MR. MacINNES: What I was just talking

10 about was from the project proponent, that wasn't your

11 numbers.

12 MR. BZDOK: Yeah. The graph that shows

13 that underneath, you know, a negative contractual value

14 in the early years and then a positive is a, yes, that is

15 from the Company.

16 The other set of issues, category of

17 issues in DTE again has to do with pollution control

18 sorbent costs and with the sort of continued viability of

19 the oldest, least economic, most marginable coal units.

20 We are particularly interested in, at this time -- and

21 honestly, there are fewer of them now than there were a

22 year ago, so the Trenton Channel power plant has had two

23 units retire and there is one left, the River Rouge power

24 plant has one unit that had, that's broken and will not

25 be fixed and has one unit remaining, the St. Clair power


80

1 plant has a number of units, the largest, or one of the

2 largest of which had an explosion last fall and is,

3 there's some questions remaining about the future

4 operation of that. There are other power plants like

5 Monroe and Belle River that were not --

6 MR. MacINNES: So these are the, would

7 you say these are the types of power plants that Laura

8 was talking about that are older, unreliable, and because

9 they're not as reliable, they cause us to have to have a

10 higher reserve at any one time, which costs money for

11 capacity?

12 MR. BZDOK: They have higher forced --

13 they are on a plan for retirement in let's call it the

14 early 2020s. The shareholder -- the investor

15 presentations, which is another source of information

16 that we are able to mine just for publicly available

17 information, has slipped some of those dates back a

18 little bit, but, you know, let's call it 2020 to 2025,

19 they are on a path for retirement, they are getting less

20 investment, they have higher forced outage rates, which

21 is probably what Laura was talking about, they are seeing

22 less capital, they also operate either -- they also are

23 at or sometimes over, you know, the margin for economic

24 operation in the PSCR as well, and so that raises a whole

25 set of issues, too.


81

1 What we're interested in is, we've had a

2 series of cases the board has supported concerning

3 pollution control sorbent costs and investments in these

4 plants to operate in compliance with the MATS rule, the

5 Mercury and Air Toxics rule. We had some PSCR cases

6 where the Commission said that they felt our evidence was

7 compelling, that those costs were going to be higher than

8 DTE was saying, but we needed to deal with that in the

9 rate case. We had a rate case where the Commission said

10 that the evidence on that was compelling, but we needed

11 to really deal with it back in the PSCR. We got to the

12 latest PSCR case, and the filing says those costs are

13 going to be lower than we had projected and they give

14 some reasons for why that is, which are plausible. They

15 also indicate that they've done new economic analyses

16 using the new costs and that the continued operation, at

17 least until their retirement dates, is viable, and so we

18 have discovery out on those economic analyses. The

19 things that we are curious about are were they done

20 assuming there was a whole River Rouge plant, or just

21 that there was one unit; were they done assuming, you

22 know, that there was a whole -- that St. Clair 6 was in

23 operation or not, and some other conditions that have

24 changed and circumstances that have changed relative to

25 energy prices, natural gas prices, et cetera, et cetera.


82

1 So that is really the other category of issues. We're at

2 the front end of that, we've issued discovery on those

3 things, we don't have the discovery back.

4 So we're seeking essentially a

5 continuation of the board's initial funding in August on

6 these two cases to basically work those two categories of

7 issues in the PSCR plan cases.

8 MR. MacINNES: So Chris, you raise the

9 issue of running uneconomic plants. I wonder if you

10 could talk, for the benefit of the new board members,

11 talk a little bit about that, what you found and through

12 the PROMOD process and all of that, through your analysis

13 and discovery about running uneconomic plants from the

14 two major utilities.

15 MR. BZDOK: So Michigan ratepayers

16 provide for the fixed costs of generating units that are

17 owned by utilities via guaranteed rate recovery in the

18 regulated system, and then the generating units then have

19 variable costs, things like fuel, pollution control,

20 related costs. To the extent they have variable costs of

21 operation, capacity revenues, things like that, they

22 operate kind of -- that portion of their costs operates

23 kind of on a market, on the MISO market, and they make

24 bids into the MISO market as well to what their variable

25 operating costs are going to be, and as the load goes up,


83

1 the market price of energy goes up and additional plants,

2 at least in theory, are turned on or ramped up, and the

3 price is set at, you know, whatever the last operating

4 cost of the last plant to come on line is, and there's a

5 curve and this happened -- you know, there's a curve over

6 the course of 24 hours and then there are patterns

7 seasonally as well. I learned here or maybe somewhere

8 else that the low hour every year is always the same,

9 it's like 3:00 a.m. Christmas morning, which was

10 interesting to me, and then the high obviously is, you

11 know, the day that it goes above 95 in metro Detroit.

12 MR. PASSMORE: That's why no one sees

13 Santa.

14 MR. BZDOK: Yeah, all the lights are off

15 and the factories that can be off are off.

16 So that's kind of how the system works in

17 theory. Now, add into that theory that there are some

18 plants that are just not really capable of being turned

19 on and off, like a nuclear plant, and that there are some

20 plants that are less capable of being turned on and off,

21 like a coal plant, and that there are some plants that

22 are really good at being turned on and off, like a

23 peaking gas plant; and so some of these -- and really

24 where this kind of comes to a head is in terms of

25 marginal coal units, which are generally that are at


84

1 times not in the money, so to speak, that are operating

2 at a higher variable cost than the cost of energy on the

3 market, and yet they also, they turn on slow, they turn

4 off slow, there are costs, variable costs associated with

5 doing that, and there are long-term wear and tear costs.

6 And so we have this, kind of this ongoing issue with the

7 utilities about when are they committed for must-run

8 operation, in other words, whether they're economic or

9 not, they have to be on at least at minimum load. So

10 even if they're costing more to operate on a variable

11 basis than the revenue they're receiving, they're going

12 to operate anyway, and the PSCR customer is the one who

13 pays that difference ultimately as a net, part of the net

14 sales and revenue cost.

15 So we have in a series of cases with both

16 utilities been arguing with them about, first, how do

17 they model that, because usually they model it as must

18 run for all the coal units all the time, and could you

19 create a plan that is more economic for ratepayers if you

20 didn't do that, if you looked at the times when they were

21 going to be sustained times when units were going to

22 operate uneconomically, if you just turn them off. You

23 can't turn them off every ten minutes, you can't turn

24 them off every day, but if you have a long period of

25 time, turn them off then, and subject to reliability


85

1 issues, is that something you could do. And the

2 Commission has said more or less, you know, you have a

3 point, but really you need to be looking at this probably

4 with the benefit of hindsight and sort of in actual

5 operation, and so we have two reconciliation cases, PSCR

6 reconciliation cases for both utilities where we're kind

7 of in that process right now, looking at what were the

8 times when units were committed as must run even though

9 they were operating at a loss, so to speak, and was it

10 justified, was it not justified, how often was it

11 justified, at times when it wasn't justified, should the

12 PSCR customer be on the hook for those net costs.

13 MR. MacINNES: And there were times when

14 there were other alternatives, like natural gas-fired

15 units --

16 MR. BZDOK: Yes.

17 MR. MacINNES: -- that could have

18 supplied the power cheaper?

19 MR. BZDOK: Yes.

20 MR. MacINNES: And that they didn't use?

21 MR. BZDOK: We go around and around about

22 this plant versus this plant, or this plant versus the

23 market, this plant versus the market, yeah. But more or

24 less, yes.

25 MR. MacINNES: Okay. Well, I guess just


86

1 to finish that topic up for a minute, through discovery

2 you were able to really get into the data?

3 MR. BZDOK: Yes.

4 MR. MacINNES: And it was lot of red?

5 MR. BZDOK: Yes. We presented -- we

6 presented results like that from a PSCR reconciliation to

7 the board in executive session a couple of years ago in

8 the Consumers reconciliation case, and that is the work

9 that we are doing now in the current Consumers

10 reconciliation case as well, same spreadsheets.

11 MR. MacINNES: Okay. Thank you.

12 MR. VILMONT: Just as a point of

13 curiosity, just for an education, I appreciate just a

14 moment, is in that industry, then, are we seeing that we

15 have -- I know we have power plants that are slow up and

16 slow down, coal slower than gas, is that, aside from the

17 fact of whether they're running at capacity or not,

18 generally speaking, on a per megawatt basis, are any one

19 of those technologies much more, significantly more

20 efficient or less efficient than the other, and so does

21 it make more sense to invest in faster response

22 technology as opposed to older slow up/slow down plants?

23 MR. BZDOK: So I think the utilities

24 would say that you need a balance, and you -- we fight

25 about this in cost of service cases, which is another


87

1 whole topic, in terms of -- I mean generally, generally

2 your lower variable cost generation is your higher

3 capital cost or fixed cost generation, and your higher

4 variable cost generation is your lower capital fixed cost

5 generation, and so there is some right balance there that

6 says, you know, we know we're going to have this much

7 load all the time, and so we want to provide that much,

8 that slice of the load, we want to invest in a higher

9 fixed cost to keep the variable cost of that load as low

10 as possible; and then we know we're going to have, you

11 know, large load spikes for small amounts of time despite

12 the scary commercials and billboards, you know. Douglas

13 Jester, John Liskey's witness who's done some work for us

14 as well, has these really neat kind of analyses of just

15 how many hours are we talking about that last, you know,

16 slice of the generation is actually needed, and it's not

17 very many, and it's to meet, you know, peak summer late

18 afternoon and early demand, you know, early afternoon

19 demand spikes on a few days during a heatwave usually, so

20 you want to do that with cheap, you know, cheap fixed

21 costs, recognize you're going to have higher variable

22 costs, and then you get into issues about, you know,

23 solar is excellent for that, too.

24 MR. CLIFT: Well, the other challenge is

25 that when you ask them how much does it cost you to run


88

1 this plant, we don't know is a very common response to

2 trying to get numbers that look more like apples and

3 apples.

4 MR. BZDOK: Yes, I would agree. There's

5 an artifice to this idea that we put one set of costs in

6 this set of cases and one set of costs in this set of

7 cases, and we have attempted, we have hired people, MEC

8 has, to try to come up with some all-in, you know. In

9 Ohio where generation is all unregulated, it all competes

10 on the market, they know those numbers, right. They

11 know, they say, here's what it's going to cost to operate

12 the plant all costs included versus what it's going to

13 get on the energy and capacity market. So it's not as if

14 those numbers can't be created, it's just in Michigan, by

15 having these two separate boxes, they're set up so that

16 they don't know.

17 MR. CLIFT: Challenging.

18 MR. BZDOK: But that's where IRP and --

19 you know, IRP, it all has to come in and it all has to be

20 dealt with together prospectively on theoretical new

21 sources of meeting demand and load.

22 MR. MacINNES: And then there's the

23 factor that I spoke with one person about that they want

24 to run this plant for as many hours as they possibly can,

25 and they set a new record on it. I asked, well, was it


89

1 economic? Well, you know, it was the number of hours

2 that they ran it. You know, try to like, hey, this old

3 coal unit, we got the hours out. Well, was it economic,

4 you know, that was the question. It wasn't answered,

5 some of unknown the factors.

6 Okay. So we have awarded what, is it

7 $96,100 toward these -- this was the last --

8 MR. ISELY: That includes the general

9 rate case, at least if the, at least the back side is

10 correct here, it's 40,000 for the Consumers and 46 for

11 the DTE; is that correct?

12 MR. BZDOK: Correct.

13 MR. ISELY: So you're asking for 70,700

14 for each case?

15 MR. BZDOK: Yes, total.

16 MR. MacINNES: And how much, so what are

17 you are you saying, how much have we granted on those two

18 cases?

19 MR. ISELY: 40,000 for the Consumers and

20 46,000 for the DTE.

21 MR. MacINNES: So 86,000?

22 MR. ISELY: Yes. And there's 10,100 for

23 the general rate case.

24 MR. MacINNES: Okay. So it's -- you're

25 asking for the 141 less 86?


90

1 MR. BZDOK: Yes. 30,700 in Consumers,

2 24,700 in DTE.

3 MR. ISELY: So how does this effort this

4 year look like it's comparing to last year? I know that

5 there wasn't much that happened in the Consumers, so it's

6 let's talk the DTE side. You were running about 75,000

7 last year on that case. Are we looking at about the same

8 level of output this year?

9 MR. BZDOK: Output in terms of the

10 investment?

11 MR. ISELY: As far as your investment.

12 MR. BZDOK: In terms of expenditure of

13 resources, we think that there is a somewhat lower -- so

14 last year in DTE we went all in on NEXUS and that's all

15 we did, and this year we're doing NEXUS and we're also

16 doing these coal issues that I mentioned, and so our

17 assessment which shaped that budget was that we were

18 going to be -- we were going to have some areas on NEXUS

19 in which we were going to be able to walk in the prior

20 footsteps, or at least we weren't going to have to

21 reinvent the wheel, and then we were going to have this

22 other set -- but we're going to have this other set of

23 additional issues as well, and that's how we came out

24 originally with the 80,800, and now that's down because

25 of a contribution to the 70,700. So that's why less new


91

1 work on NEXUS, but an additional set of work as well, if

2 that answers the question.

3 MR. ISELY: That helps. Thank you.

4 MR. MacINNES: And there's some more,

5 well, cost of service issues in there also, right?

6 MR. BZDOK: Cost of service is in the

7 rate cases, and so we did apprise you on cost of service

8 in connection with the Consumers Energy general rate case

9 request that you've provided funding for in August.

10 MR. MacINNES: Okay. Are there any other

11 questions from the board?

12 MR. PASSMORE: Just I guess I'm not

13 following what the request amount today is.

14 MR. BZDOK: $55,400 divided, 30,700 for

15 Consumers and 24,700 for DTE.

16 MR. PASSMORE: Okay. Now I understand.

17 Thanks.

18 MR. MacINNES: And that was in this memo.

19 MR. PASSMORE: Yeah, I know, I was just

20 trying to make all the numbers work, and now I

21 understand.

22 MR. MacINNES: It's a little confusing.

23 MR. BZDOK: Yes, and I apologize for

24 that.

25 MR. PASSMORE: And then I guess the next


92

1 question is really for you, Jim. Is it customary to sort

2 of partially fund a request and then say, come back

3 later, or is that -- or was this a unique situation or

4 why did the board do that?

5 MR. MacINNES: Because -- that's a good

6 question. Because we try to be very careful in our

7 spending, and we want -- we want the grantees to come and

8 tell us why they need more money. Sometimes in order to

9 get into the case, it's like, well, we're not sure what

10 we're going to have to do in this case because there's

11 not enough information, for example; so we'll get people

12 into the case in some situations, and then they'll say,

13 oh, look at these issues and then will come back and tell

14 us that, what they want to do and -- we want to fund the

15 most important work, the work that has the most low-

16 hanging fruit, and sometimes it takes time to figure that

17 out, and rather than just say, oh, well, here's all the

18 money, go, you know, take care of it, we want to be

19 partners all the way along in this process, at least

20 that's my view. I, you know, as a business owner, I'm

21 pretty careful in putting out money, and I think the

22 public wants us to be very careful in putting out money.

23 We're not afraid to put out money, but we want to talk

24 about it, you know, why do you need it, what are you

25 going to do, what have you found out since you've been,


93

1 you know, partially into the case, you know more. I

2 don't know if, Paul, if you have another take on it.

3 MR. ISELY: Yeah, I mean to me it is

4 about will we know more information, will we know more

5 information in a timely manner, and will dividing it

6 adversely hamper their ability to get experts and feet on

7 the ground to move forward, so that has to be weighed.

8 When you're willing to do this, however, there may be

9 times where we have people go down a path and there won't

10 be money at the end, so we're still looking for the best,

11 the biggest bang for the buck.

12 MS. HAROUTUNIAN: Part of it, too, is it

13 prevents us from overextending ourselves, and that has

14 happened inadvertently, based on our knowledge or lack of

15 knowledge of where things were at with the AG, and we're

16 paying that back. We are not in as bad a position as we

17 would have been had we been putting the money all out

18 there, up front in effect, and all of the grantees have

19 worked with us mightily in order to help adjust their

20 requests and everything else, because they understand the

21 position we're in and the money didn't all go out the

22 door at the beginning.

23 MR. MacINNES: Well, and also we could

24 have, and we have had, surprise issues.

25 MS. HAROUTUNIAN: Yes.


94

1 MR. MacINNES: You know, we're sitting

2 here saying, hey, we've got enough money, and then all of

3 a sudden three or six months later, where did this come

4 from --

5 MR. PASSMORE: Right, right.

6 MR. MacINNES: -- and then if we've spent

7 all the money and this new issue, like the

8 cost-of-service case, for example, very costly for

9 residential ratepayers, you know, that moves to the head

10 of the queue in terms of importance, and we may not have

11 even seen it initially. So it gives us, you know, the

12 benefit of hindsight as we're going through the process.

13 MR. PASSMORE: Right. So I guess the

14 only sort of, not to complicate things, I'm just curious

15 really, is in your case, whether during this sort of

16 discovery phase you've learned some things that actually

17 if you had additional resources you could do even more

18 important work on, right, it goes both ways, right? We

19 learn that there's not an opportunity here or we learn

20 there's an amazing opportunity here we weren't

21 anticipating?

22 MR. CLIFT: Yeah. And some of that is

23 based on discovery you do, and some might be based on,

24 oh, a Commission decision in last year's case might tell

25 us, oh, you're supposed to be over here asking for this,


95

1 or they may decide an issue that we decide, well, we can

2 drop that one going into the future due to their past

3 precedent.

4 MR. BZDOK: So my answer to that direct

5 question is, to these two cases, is not at this time.

6 The original scope of our request at 80,8 for each,

7 80,800 for each case is an aggressive request, and

8 generally considering, you know, the board's way of doing

9 things, we felt it was justified because of the

10 significance of the issues in both and because there's

11 sort of two sets of large issues in each case. But I

12 don't have anything -- there are other things that are

13 popping up, there's a -- and we can talk about those more

14 at any point -- but there's nothing that seems like it's

15 going to require us to reel in a whole nother third major

16 set of issues at this time.

17 MR. PASSMORE: I appreciate your candor.

18 MR. MacINNES: John, you've been doing

19 this for a long time, do you have anything you want to

20 add to this discussion?

21 MR. LISKEY: No, I think you've covered

22 it. I mean one big case that came out as a surprise was

23 the UPPCo rate case, and that was a $90,000 effort, so.

24 MR. MacINNES: Right. And it's also

25 important to point out that sometimes the grantees, you


96

1 know, they do pro bono work sometimes and, you know, we

2 don't want them to have to do that necessarily, but they

3 do if they feel -- I mean, you know, they're pretty

4 committed in what they're doing, and so if they see

5 something that needs to be done, quite often they'll take

6 it on even if the funding is not there, and that's

7 happened in I think everybody's case, or there will be

8 other funders that could help fund. See, once you're in

9 the case, like let's say a rate case, you know, we can

10 only deal with PSCR, with Act 304 issues in a rate case,

11 until this new legislation passes, if that's what

12 happens, but once they're in the case, if they have other

13 funding, they can pursue other issues, because once

14 they're in that case, like okay, we're in, CARE is in,

15 and we've got some other funding, either pro bono or

16 we've got some other outside funders, you know,

17 foundations or something like that who will help to fund,

18 here's a really important issue we think is really

19 important, while we're in, we're going to do that, too,

20 then they'll do that, which I think is pretty neat.

21 So any other questions?

22 MR. ISELY: Can I ask a broader question,

23 because I'm pretty happy with the explanation here. So

24 can we explore total funding that's still to happen?

25 MR. MacINNES: That's a good question.


97

1 We can.

2 MR. ISELY: Thank you. So there's two

3 things that are here, one is the underfunded cases for

4 the other grantees that we started, and the other issue

5 is the recon cases that are yet to be brought to our

6 attention. So does anybody have anything they want to

7 say about either of those sides?

8 MR. LISKEY: Well, I can say that in the

9 February meeting we will request funding for the WEPCo

10 and UPPCo reconciliation cases in the amount of $20,000

11 each, and we will also ask for the, an additional 17,500

12 for the MISO/FERC activities.

13 MR. MacINNES: So what does that total?

14 MR. LISKEY: 57.5.

15 MR. MacINNES: And Don, do you have --

16 MR. KESKEY: Yes. With respect to GLREA

17 and then the RCG, there are the renewable energy plan

18 cases that are supposed to be filed by the utilities in

19 the early, probably mid -- well, before July of 2017.

20 And then of course we don't know what's going to happen

21 to the legislation, whether it's going to pass next week

22 or whether it's in the next session, if there may be --

23 that may change things. The board had granted us

24 one-half of our request for RCG in the CECo 2017 plan

25 case, U-18142, which also incorporates a five-year


98

1 forecast, and to come back to the board with more

2 information, and we just were granted intervention a

3 couple of business days ago, so the discovery process is

4 what's necessary to develop this work plan more, and so

5 February may be the opportunity -- the testimony in this

6 case is due, let's see, I think it's around April 6.

7 MR. MacINNES: So this raises another

8 good issue. So we've already got MEC in this, too, so

9 we've got two grantees in this case.

10 MR. KESKEY: On separate issues.

11 MR. MacINNES: On separate issues. And

12 how do we divvy that up, you know, and trying to

13 understand which issues are the most important.

14 MR. KESKEY: So there are unknowns,

15 because the cycle, you know, it depends on the case

16 cycles, and then some of the surprise events are not only

17 discovery and things like that, but sometimes a utility

18 will file a surprise application which has major import

19 that was not expected by anyone which you don't know

20 about yet, it may still happen, and then sometimes even

21 the legislature will pass an act that you don't foresee,

22 and so a little bit of flexibility here helps to at least

23 be prepared for some of that.

24 MR. MacINNES: And, you know, here's

25 really what we, getting back to the funds available, at


99

1 the beginning we had 400 -- in essence, $489,832

2 available for grants, so less than 500,000. By the time

3 we, you know, we need to pay for administrative work here

4 from LARA, which is 5 percent, something like 50,000,

5 thereabouts, and then we also had to borrow 280,000 from

6 the AG's office for cost of service, this is particularly

7 for the benefit of the new board members, for cost of

8 service cases; we thought we had enough money and we

9 found out that LARA, the financial people had not

10 calculated the right amount, and we had granted the money

11 and then found out we were 280,000 in the hole and -- or

12 well, we were in the hole and then these two, these cost

13 of service cases came up.

14 MR. ISELY: There was some question as to

15 how the, how the leftover funds were divvied between the

16 AG's office and us --

17 MR. MacINNES: Yes, right.

18 MR. ISELY: -- and so it wasn't that we

19 just overspent, there was some question to that that was

20 clarified during the year.

21 MR. MacINNES: That's why now we have, as

22 part of every meeting, we have LARA tell us what the

23 budget is, where are we at with the budget, and we're

24 going to keep doing that as a business item going

25 forward. So we owe, we paid the AG's office 70,905 out


100

1 of the 280,000 we owe them, and we're hoping to do

2 another 70,905 this year, but we owe them, that's money

3 we can't spend, and if we do -- we told them we'd pay it

4 back over four years, so that's 70,000 a year we can't

5 spend, which is why we're down to 489,000, which is why

6 we're, we've been talking to the legislators about

7 providing more money to this board, so that we can get

8 involved in more cases and help residential ratepayers.

9 Because when you think about it, $500,000 a year is not

10 very much money to intervene against companies that

11 together represent nearly 20 billion in sales. That's

12 the problem. And they can afford a lot of lawyers, and

13 they make their case, they advocate their case well.

14 So with all that said, we have 280,723,

15 is that what you're seeing, Paul?

16 MR. ISELY: Yep.

17 MR. MacINNES: Available yet this year

18 for grants. So MEC's asking for 55,400, CARE is talking

19 about another 57,500. Don, maybe you can refresh our

20 memory what you see.

21 MR. KESKEY: The other 50 percent of the

22 case for RCG in Consumers Energy, and it was granted

23 18,000, so that would be 18,000 upon bringing it back to

24 the board. And then there will be the two renewable

25 energy plan cases that will be filed in the March to June


101

1 timeframe roughly of next year by Edison and Consumers.

2 And last year, in the 2015 cases, they're filed every two

3 years, but in the 2015 cases we actually got into it and

4 did quite a bit of work pro bono because the board

5 meetings were not being held on new grants, and we were

6 granted I think 12,500 for each of those REP cases, but a

7 realistic grant would be somewhere around 18,000 each I

8 would think, because these budgets cover both the legal

9 costs but the experts costs.

10 MR. ISELY: Okay.

11 MR. MacINNES: And then what about MEC

12 future cases?

13 MR. BZDOK: PSCR reconciliations,

14 Consumers Energy and DTE, which will be filed end of

15 March 2017. The board sponsored those last, the current

16 ones, so last year's cases, at 55 in DTE at 45 in

17 Consumers. We would anticipate asking for a similar

18 amount of money.

19 MR. MacINNES: Have you got your

20 calculator out?

21 MR. ISELY: I'm doing it by hand.

22 MR. MacINNES: So it's 57.5, 18, 36,

23 additional is what I'm coming up with.

24 (Multiple inaudible speakers.)

25 MR. VILMONT: 211,500.


102

1 MR. ISELY: Did that include the request

2 for the grant today of 55.4?

3 MR. MacINNES: No.

4 MR. VILMONT: No.

5 MR. ISELY: So we're looking at 266 and

6 some change.

7 MR. MacINNES: Which does fall within the

8 remaining balance. That's good. But it doesn't leave us

9 any leeway if something else comes before us.

10 MR. PASSMORE: Is there any reason to

11 think that if the legislature acts during the lame duck,

12 that there is likely to be something in, or is it going

13 to sort of need to percolate for six months before?

14 MR. MacINNES: I think there's a good

15 chance it's going to be passed in some similar form, but

16 when that -- I mean, if it is passed, I don't know when

17 we would have, actually have access to the funds.

18 MR. CLIFT: Yeah. In my head I was

19 assuming it was going to be next year's assessment, that

20 they wouldn't make a, kind of a mid-year adjustment. So

21 I'll doublecheck that, but that's the way I had it in my

22 head.

23 MR. PASSMORE: But would an issue be

24 raised that would logic -- you know, someone might come

25 forward and say we need some money to do something in the


103

1 short term if it gets passed?

2 MR. CLIFT: Yeah, so the unknowns are

3 always rates cases, you never know when rate cases are

4 going to be filed because they're whenever the utility

5 wants one, and the certificate of necessity are the other

6 ones that are under control of the utility, they don't

7 happen on a regular basis, it's just whenever the

8 utilities decide to file them, so those are always kind

9 of always the unknowns out there.

10 MR. PASSMORE: But the integrated

11 resource planning, I mean that's not going to be an

12 issue that --

13 MR. CLIFT: That's two years down the

14 road.

15 MR. PASSMORE: That's two years down the

16 road.

17 MR. MacINNES: Well, and we could perhaps

18 go back to the AG's office and see if they would give us

19 some relief on the loan if the new legis -- new law

20 passes, and that might be possible, I don't know how it

21 would turn out.

22 MR. ISELY: Do we need a motion?

23 MR. MacINNES: We probably do, unless

24 there's anymore -- well, we can use a motion and then we

25 can have some more discussion.


104

1 MR. ISELY: Let's do the easier one

2 first. So I move that we allow the transfer of funds

3 between the 2016 Consumers Energy PSCR plan, U-17918, and

4 DTE general rate case, U-18014, to support exceptions and

5 replies in the pending DTE general rate case, U-18014, in

6 the amount specified in MEC's request.

7 MR. MacINNES: Which would be a $10,000

8 savings? No.

9 MR. ISELY: No. I'm doing the transfer.

10 MR. MacINNES: Okay. Is there support

11 for that?

12 MS. HAROUTUNIAN: Support.

13 MR. MacINNES: Is there anymore

14 discussion? Is there anything you want to add to that,

15 Chris?

16 MR. BZDOK: No, no-cost transfer, no new

17 money transfer.

18 MR. MacINNES: Okay. All those in favor,

19 please say aye.


21 MR. MacINNES: Opposed, same sign. Okay.

22 I like those no-cost motions.

23 MR. ISELY: All right. Then my second

24 motion would be to approve $30,700 for the Consumers,

25 what is it, PSCR plan, and 24,700 for the DTE PSCR plan


105

1 as proposed by MEC.

2 MR. MacINNES: Do we have a second?

3 MS. HAROUTUNIAN: Second.

4 MR. MacINNES: Any discussion?

5 All those in favor, please say aye.


7 MR. MacINNES: Opposed, same sign.

8 MR. BZDOK: Thank you very much.

9 MR. MacINNES: Okay. Let's move on to

10 reports from grantees. Maybe start with John.

11 MR. LISKEY: I was hoping to get some

12 information from Douglas, he's not going to be here, so

13 I'm wondering if you could start with Don.

14 MR. MacINNES: Oh, sure, we can. Don.

15 MR. KESKEY: Okay. Right now we have

16 been involved in four PSCR cases that are currently on

17 the table. U-17918 is the 2016 PSCR case for Consumers

18 Energy, which again includes a five-year forecast, and

19 U-17920 involves the 2016 PSCR plan and forecast for DTE

20 Energy. The Commission issued an order in the Consumers

21 Energy case, 17918, on October 11, 2016, and the ALJ in

22 U-17920 issued a proposal for decision in the DTE case on

23 October 28, 2016. We have filed exceptions to that PFD

24 on November 18, 2016, and there will be replies due at

25 the end of this week.


106

1 Now, with respect to the PSC order, in

2 past cases the Commission has indicated we had good

3 issues, they indicated we had a statutory right to

4 intervene, and this is on behalf of the Great Lakes

5 Renewable Energy Association, and that we had issues that

6 are deserving to be brought up in continuing cases, but

7 the Commission indicated concerns about making, adopting

8 some of our recommendations because of the pendency of

9 the energy legislation, which has been in different forms

10 around for two or three years, and that is the

11 legislation that's now possibly going to be passed by the

12 House next week, and as to when it gets to the governor,

13 probably soon after. So there are some, there's some

14 hesitancy for the Commission to deal with the substance

15 of some of these issues until that legislation is clear.

16 What we have proposed on behalf of the

17 GLREA in these PSCR cases for Consumers and DTE is that

18 we had pointed out through analysis and expert testimony

19 that their five-year forecasts were not accurate as you

20 go out the five years because they assume essentially a

21 flat level of solar energy, even though nationally and in

22 many states like Minnesota and other areas the amount of

23 solar resources is increasing considerably. And there's

24 basically three kinds of solar: There's community-owned

25 solar where other co-ops and some municipal utilities and


107

1 some cities are getting involved in collaboratively

2 developing solar energy resources, and that contributes

3 to the energy available and the capacity available; also,

4 then there's customer-owned solar in which individual

5 customers, whether they be industrial, commercial, or

6 residential, have invested in solar facilities and

7 they've reduced their consumption; and then there's

8 utility-owned solar in which some of the utilities have

9 recently developed some solar facilities, which those

10 facilities are the only ones that they're really

11 forecasting in their forecasts. And that's a problem,

12 because not only does solar, including in Michigan, align

13 very well with the peak summer costs of electric energy

14 and can offset those costs in a number of areas, whether

15 it be fuel, purchased power, transmission, congestion

16 charges, there's other benefits, but the forecasts, in

17 our view, and we demonstrated in our testimony, are

18 deficient because the utilities are only looking at

19 company-owned solar and to the exclusion of forecasting

20 in these other two major kinds of solar energy which

21 directly can reduce Act 304 costs, besides providing

22 additional diversity in the source of your capacity and

23 energy.

24 And so we discussed it as an organization

25 with the client about whether to appeal the latest


108

1 Consumers Energy case and decided not to because we

2 believe it's sort of a neutral decision, it's not really

3 coming to grips with our case, and we will -- we believe

4 in the next case for DTE Energy we can demonstrate that,

5 and we believe the state statute may well be passed, so

6 we know what we're dealing with.

7 The new PSCR and forecast cases for

8 Consumers Energy and Detroit Edison were filed at the end

9 of September.

10 MR. MacINNES: Excuse me, Don. I

11 wondered, before we get into that, if I could just ask a

12 question about the solar. With the new Senate Bill 438,

13 rooftop solar on someone's house may not be very

14 favorable, right?

15 MR. KESKEY: That's where the House and

16 the Senate bill differ, for example, with respect to the

17 proposal for a surcharge on solar, some would call it a

18 tax, for customers who install solar as far as under the

19 theory that it contributes to the grid cost, however, the

20 House bill does not have that, the House bill and the

21 Senate bill are going to have to be reconciled. We

22 believe that there's really no economic basis for the

23 solar grid tax because the customers are already paying

24 in full in their rates for all the grid costs, whether it

25 be through the MISO tariffs or through any cost impacts


109

1 the utilities have. Secondly, the customers also pay a

2 monthly service charge regardless if they use anything.

3 And so the real purpose of this solar tax on customers

4 enhancing and empowering themselves to do something about

5 reducing their consumption we believe is an effort to

6 stifle the growing market, the independent market of

7 solar facilities in Michigan, and really stifle

8 residential Customer Choice, and quite frankly, the

9 ability of commercial industrials to reduce their energy,

10 especially during the peak times.

11 MR. MacINNES: So with that said, I mean

12 it's hard to know how that's going to turn out because

13 there's several sides of that argument. The utilities

14 are building some solar, or at least the large corporates

15 are, like General Motors, so that could have an effect of

16 increasing, I mean some large projects versus rooftop, so

17 that could perhaps help with the increased curve you're

18 talking about.

19 MR. KESKEY: That's actually -- we have

20 supported the proper use of expansion of solar

21 facilities, whether it be by the utility, industrial

22 class, the commercial class, or residentials, but we

23 don't want the residentials to be excluded from this

24 process because there's a lot of public interest by

25 residential customers in this. Now, rooftop solar can be


110

1 utilized by schools, governments, industrial plants,

2 utility plants, commercial stores and malls, in other

3 words, there's a lot of rooftops out there --

4 MR. MacINNES: Yes.

5 MR. KESKEY: -- and that can take

6 advantage of a natural clean power source, which is the

7 sun, and which really matches the peaks, and in fact,

8 contributes even in other months, even in the wintertime.

9 So that issue would not mitigate the viability of the

10 participation on these issues, but the issue is going to

11 be decided between the House and the Senate, and that's

12 one of the issues I think the House bill, and there are

13 certain people in the -- certain representatives in the

14 House that want to see that not approved, that 15-percent

15 tax, or whatever the amount is. Does that answer your

16 question a little bit?

17 MR. MacINNES: Uh-huh.

18 MR. KESKEY: In the new PSCR case for

19 Consumers Energy, U-18142, we were granted intervention

20 on behalf of the Residential Customer Group a couple

21 business days ago, on November 30, and the schedule was

22 worked out on that case, and then we would start the

23 discovery. The issues that we presented in our work plan

24 in that case was, number one, with the recent and planned

25 closings of a number of coal plants by Consumers Energy


111

1 Company, how have they adjusted their coal purchases and

2 their coal inventories and their renegotiation of coal

3 contracts to reduce the purchase of coal. Traditionally

4 the utilities have had a lot of long-term coal contracts,

5 sometime 20 and 30 years, and what we're concerned is

6 that Consumers is going to get, is and will be,

7 particularly in the five-year forecast period, stranded

8 with a lot of excess coal unless they renegotiate

9 contracts, unless they sell it to third parties, or

10 unless they force burn coal, which we've had cases before

11 where we've determined there's been a forced burning of

12 fuel and of other instances and other I think coal. And

13 one way you can force burn coal is, when you just

14 mentioned moments ago the reference to a record number of

15 hours of operation, you know, was that a coal plant, did

16 they bid into the MISO system a lowball bid so that they,

17 MISO would take it, and then they would then force burn

18 the coal plants to burn coal on an uneconomic basis and

19 then charge the ratepayers. If you flow it through Act

20 304, you're going to charge the ratepayers. If you

21 underbid your actual cost of generation into MISO, when

22 it comes to reconciliation, you're going to end up with

23 buying, paying MISO for a lot of money, which again, the

24 utilities have flowed through Act 304. So there are a

25 number of steps that should be examined as to whether


112

1 they're selling coal to third parties, whether they're

2 renegotiating contracts, are they doing everything they

3 can to the greatest degree that's reasonable and prudent

4 to reduce their coal expenses and to save ratepayers

5 money.

6 The second issue that we've looked at in

7 this case for our work plan was that Consumers Energy

8 almost ten years ago entered into a purchased power

9 agreement which the Commission approved to purchase all

10 of the power from the Palisades nuclear plant, which they

11 used to own but they sold at that time to Entergy

12 Palisades, and one of our expert witnesses for purposes

13 of this case, 33 years out at the utility audit

14 experience at the Attorney General's office as an expert

15 witness was one of our witnesses that looked into -- we

16 opposed the sale of the plant, first of all; and second

17 of all, we had put in on a case indicating why the

18 purchased power agreement was not reasonable and prudent.

19 Well, now the question is, what's reasonable and prudent

20 to adjust for the fact that this PPA is too expensive,

21 and there were provisions in the contract that would

22 provide for renegotiation. Also the Palisades plant is

23 really an old plant, they have an embrittlement problems,

24 they have, every so often they have the licensing issues

25 with NRC investigations and so forth, and amidst the


113

1 alternative opportunities for lower cost capacity and

2 energy, what is the Company doing to plan for the next

3 five years when the contract, the PPA ends: Should they

4 renegotiate the contract now; are there out clauses that

5 would allow them to not pay as much as they're paying; is

6 this plant going to last for five years; and what are you

7 going to do after that. So there are a number of issues.

8 I don't have all the very specific issues, and I don't

9 have all the answers, but that's what the discovery

10 process is for, then the expert will put together

11 testimony on the subject.

12 With respect to the other case, PSCR

13 forecast case for DTE, which is U-18143, we were granted

14 a budget to intervene on behalf of GLREA, and in that

15 case we would pursue issues we raised in DTE's last

16 renewable energy plan case and also in the recent cases

17 for DTE on again the solar issue, and we believe the

18 legislation probably will get passed, but there are a lot

19 of good angles to build on our previous cases to try to

20 convince the Commission that they should at least require

21 DTE in its upcoming cases and it's upcoming REP,

22 renewable energy plan case, to make their forecasts more

23 accurate and show that what they're planning is on

24 specifically solar with community solar, Company

25 utility-owned solar, and customer-owned solar, and that's


114

1 the purpose of that, and it's building on a lot of

2 experience we've obtained in the recent cases.

3 There's also two other cases which the

4 board has approved grants for GLREA, they are for the DTE

5 what's called a PURPA case, that's under the federal

6 Public Utility Regulatory Policies Act and FERC

7 regulations under that, and for DTE it's Case U-18091,

8 and for Consumers Energy it's Case 18090. In both cases,

9 GLREA was granted intervention, and the intervention work

10 was done again on a pro bono basis because it was before

11 the grant cycle which started October 1. And in the

12 Consumers Energy case, U-18090, we filed our expert

13 testimony in October 27, and the hearings are going to

14 start this week, starting on December 8. In DTE Energy's

15 PURPA case, U-18091, we filed our testimony a couple

16 business days ago, on December 1, and the hearings are

17 scheduled for January, I think it's 12 and 13.

18 Now, just very briefly, under PURPA and

19 federal regulations, utilities are supposed to be able to

20 hold open the opportunity to independent renewable and

21 other projects the opportunity to provide capacity and

22 energy at a, sort of a neutral cost, in other words, the

23 cost that the utility itself would have to incur if it

24 was going to build the facility, this was to diversify

25 energy sources, and the standards provide for what's


115

1 called an avoided energy cost and then an avoided

2 capacity cost. The testimony and proposals, tariff

3 proposals that both utilities have filed in these cases,

4 what the utilities want is only a commitment of contract

5 obligations for two to five years, and less obligation if

6 they don't need the capacity, that is, because you go

7 forward years, they do need capacity. So the problem and

8 our expert testimony focuses on this quite heavily, you

9 can't have the kind of PURPA requirements if the contract

10 periods for them are two to five years when the utility

11 itself builds plants for a 30- to 40-year, and when it's

12 put in the rate base, they're essentially guaranteed

13 total return of their investment, return on the

14 investment, operation, maintenance expense, taxes,

15 everything for their own plants, but how can PURPA make

16 any sense if you have that standard for utility-owned

17 plants and you want to restrict independent power plants

18 to two- to five-year contracts only, and if you want to

19 have, make them subject, but not you, if you don't need

20 the capacity.

21 MR. MacINNES: And that would, those

22 would be essentially unfinanceable projects.

23 MR. KESKEY: Yes. And the interesting

24 point there is that Michigan law under Act 304, which is

25 what this board operates under, has a specific provision


116

1 that was passed by the legislature when the last round of

2 PURPA fights occurred about 20 years ago that requires

3 the Commission to look at contracts, and if they're

4 approved, that contract is supposed to be viable for

5 17 1/2 years, and this was put in expressly to make them

6 financeable. And so the big elephant in the room on the

7 state law aspect is how can these utility proposals be

8 liable or credible if they don't address the 17 1/2-year

9 requirement.

10 And so one of the advantages of having

11 some PURPA projects by independent owners using different

12 technologies, could be solar, it could be wind, it could

13 be biomass, it could be any number of things, is that

14 they come on line in small increments, less risk,

15 diversity of supply, whereas a utility when it builds a

16 500- or 700-megawatt plant, it comes on line all of a

17 sudden and then they've got excess capacity, but you're

18 planning in your base rates for the whole thing whether

19 you need it or not, and so there isn't an equal playing

20 field here being set forth by the utilities under PURPA

21 requirements or under state law requirements as we would

22 advocate.

23 As far as customer impact, we would say

24 that the residential ratepayer, the, all the ratepayers

25 in Michigan are better off with a well-diversified energy


117

1 resources, a variety of resources, and that this all

2 contributes to a better system. And --

3 MR. MacINNES: So Don, I've got a

4 question on that. So a utility is going to propose a

5 300-megawatt plant, and because of the benefits of

6 economies of scale, the price, and they can bulk purchase

7 their fuel, they can buy a lot of stuff and get a good

8 low price, and then they set their rate based on that,

9 right?

10 MR. KESKEY: Sometimes no.

11 MR. MacINNES: So I guess my question

12 is --

13 MR. KESKEY: The Zeeland plant is an

14 example of that.

15 MR. MacINNES: -- how can the little guy,

16 you know, the little biomass plant in McBain that's

17 18 megawatts, how can they compete, or how can they make

18 it work, let's say they want to build a new little plant,

19 on that economics?

20 MR. KESKEY: Well, first of all, unlike a

21 utility, the independent developer of a project is

22 financing it himself, and so if his avoided cost and his

23 energy cost is the same as the utility's, in other words,

24 he can do the same, he has his own sources of financing

25 or the economics of his own project is something he


118

1 knows, then he can do it.

2 MR. MacINNES: But to the same point, the

3 utilities are -- have better access to capital and lower

4 cost capital.

5 MR. KESKEY: Not necessarily.

6 MR. MacINNES: Generally I would say they

7 do.

8 MR. KESKEY: But there's some other

9 project developers that have good access.

10 MR. MacINNES: Because a lot of the

11 developers are doing project financing, which means the

12 contracts to the project are the credit support mainly

13 for the project, where the utilities have the -- use the

14 corporate financing approach, which they can put their

15 whole balance sheet behind the financing and get lower

16 cost of debt and their equity costs are ten percent and

17 change, that's pretty attractive.

18 MR. KESKEY: Well, on a general theory,

19 you may be correct, but I'm saying a specific instance,

20 you may not be correct. But in any sense, the cost

21 neutrality of PURPA and the 17 1/2-year financing

22 provision of state law means that it does not impact

23 ratepayers; in other words, if a private company, could

24 be Ford Motor Company, I don't know who it would be, it

25 could be a large farmer that can do it because he is


119

1 economically strong enough to do it, if he can do it,

2 that's his business, you need not get into each of these

3 matters as long. As they've got a contract with the

4 utility that he's going to get this X, Y, Z for a longer

5 term than two to five years, it becomes financeable. One

6 thing that's not going to be very financeable is if he's

7 saddled with an offer of only two to five years, no

8 guarantees after that, that's not going to be

9 financeable, which discourages the very purpose of the

10 federal law.

11 So we don't know how many people are

12 additional PURPA projects, we have some in Michigan, we

13 don't know how many more will come on line, but you

14 shouldn't go out of your way to discourage it; again,

15 that is anticompetitive. And if you broaden out your

16 opportunities for power generation and diversify from

17 different kinds of sources and you're ramping them up

18 slowly, that has a lot of advantages as well. And we've

19 seen instances where the utility has not bargained for

20 the best and the lowest cost, and we can provide

21 examples. But the arrangement that they had on the

22 Zeeland plant where instead of buying the pipe, the 7.5

23 mile-pipeline between the ANR, the supplier, and the

24 plant, they kept leasing it, it was a capital lease, they

25 kept doing it, but we had testimony showing that it was


120

1 costing the ratepayer more.

2 MR. MacINNES: Right.

3 MR. KESKEY: And then they are also using

4 a gas agent to buy their gas and not necessarily bidding

5 it out for the best, the gas source, best and most

6 efficient gas sources. So you can't just assume that the

7 utilities, because of these, the scope, scale, and all of

8 the rest of it, are necessarily bargaining hard for some

9 of these cost elements, and that's in fact why this board

10 exists in part.

11 So that's where we're at. Like on the

12 four recent cases, the discovery process, and the two

13 PURPA cases that's been going on, the testimony has been

14 filed on the two PURPA cases, the hearings are going to

15 be held pretty soon; the two 2017 PSCR cases, they're

16 just starting in the discovery, we just got into the

17 cases, and the discovery process will start now on those

18 issues.

19 MR. MacINNES: Okay. Any questions for

20 Don?

21 John.

22 MR. LISKEY: Okay. I'll try and be brief

23 given the hour. For the new board members, one term that

24 you're going to hear a lot from me is this SSR acronym,

25 and essentially what that is, when a utility wants to


121

1 shut down a plant, they have to request permission from

2 MISO. MISO's the regional organization which gave their

3 presentation. So in the Upper Peninsula, this has been a

4 big issue. There's one big plant in Presque Isle, or in

5 Marquette called the Presque Isle plant, and I'm not

6 going to talk about that one because that's a long

7 discussion, but there's been one in White Pine, Michigan,

8 which was to support the manufacturer there, it was never

9 a plant designed to supply the rest of the region. So

10 the owner of the plant wanting to shut it down, and MISO

11 said, well, you know, hold on, we're going to -- we're

12 going to need you to keep that plant operational for some

13 backup for some planned outage activity, and that's

14 permitted, that cost; and then when that happens, the

15 cost of keeping that plant going for the whole year is

16 spread across the entire Upper Peninsula, residential

17 ratepayers, commercial ratepayers. So that particular

18 plant called the White Pine plant costs about $6 million

19 a year to keep operating, and so that cost was then

20 spread to, you know, mostly residential ratepayers.

21 MR. MacINNES: And John, can you explain

22 to everyone what the cost of electricity is for

23 residential ratepayers in the U.P., about?

24 MR. LISKEY: Well, the largest utility in

25 the U.P. is Upper Peninsula Power Company, otherwise


122

1 known as UPPCo, and they're currently at about 27 cents a

2 kilowatt hour. I actually prepared a couple of binders

3 for each of the new board members with --

4 MR. PASSMORE: Terrific, thanks.

5 MR. LISKEY: -- some background on all

6 that because I didn't want to have to do it orally.

7 So back to the White Pine SSR case. If

8 another alternative exists, then MISO has -- can go that

9 route, something less expensive, but still keeps up the

10 reliability. And the transmission company up there, ATC,

11 put forth through really this governor's efforts to come

12 up with an alternative, a reconfiguration of the ATC

13 transmission system, and MISO took that proposal through

14 its what they call stakeholder process; through a grant

15 from this board, we participated and supported it, and

16 then MISO files the paperwork with FERC to get permission

17 to shut that plant down. White Pine objected to that.

18 CARE, our organization, filed comments at FERC supporting

19 the alternative, and we were -- this is one of these

20 great cases where we're not fighting everybody, UPPCo and

21 CARE and the MPSC and the Governor's office, we're all on

22 the same page. Now, White Pine opposed it, but I'm happy

23 to report that on November 23, FERC supported and allowed

24 MISO to close that plant down. Now, we'll see, I don't

25 know if the plant will be closed down, because I think


123

1 it's still going to be used for that manufacturer's

2 purposes, but we won't be paying for it any longer

3 effective November 26, so that's a $7 million savings --

4 MR. PASSMORE: That's great.

5 MR. LISKEY: -- to the -- now, we don't

6 get all the credit, we don't get -- we get a little

7 credit because FERC mentioned us in their decision and

8 said that they took note of -- because we're the, really

9 the only exclusive residential ratepayer group in the

10 Upper Peninsula.

11 MR. MacINNES: So do we know the impact

12 on the cost of electricity that will have for the average

13 ratepayer.

14 MR. LISKEY: You know, I have not

15 calculated that, but I will. I'm trying to think, I

16 can't do it in my head. I should mention, our expert,

17 who I've been e-mailing back and forth here, is Douglas

18 Jester, and he's usually here and can answer questions

19 like that off the top of he his head, but he's in a

20 meeting with legislators today on this very important

21 legislation. So that's the good news I have.

22 The other, we have two PSCR plan cases

23 for the Upper Peninsula Power Company, the 2017 plan

24 case, and also for WEPCo, the Wisconsin Electric Power

25 Company. The main issues in those cases -- by the way,


124

1 they've just begun, last month we just had our first

2 prehearing conference, so discovery hasn't even been

3 issued yet, so those are at the very preliminary stage.

4 But the main issue in the UPPCo case is they are

5 transitioning off a power supply agreement that was very

6 expensive to something new, and so we're going to take a

7 look at that. And then with the WEPCo case, it's very

8 convoluted right now because WEPCo is -- has a different

9 case that we're not part of to spin off to a Michigan-

10 only utility, just the Michigan U.P., and so the issues

11 that we will be looking for to see if there's, you know,

12 unjust or unreasonable costs being pushed on to Michigan

13 customers instead of Wisconsin customers in the PSCR. So

14 those are the two cases we have going.

15 The other issue I wanted to mention, back

16 to MISO for a second, when Laura was talking about our

17 limitations on capacity import, there is a stakeholder

18 process that's been going on at MISO that we've been

19 supporting. Right now -- and I probably have this a

20 little wrong, but you'll get the idea. Right now, in

21 order for a project to qualify for MISO planning, which

22 affects cost allocations and a lot of financial things, I

23 think it has to be a 245-kilovolt line. We've been

24 supporting a position to lower that threshold to

25 135-kilovolt lines, and if we were successful at that,


125

1 and it's not meeting a lot of opposition, but that will

2 help in this determination that we're -- we have a

3 shortfall, because they're more likely to be a

4 135-kilovolt line, in fact there are already some, but

5 they don't get counted because they're below the 245

6 threshold. And that's the outer limits of my knowledge

7 on that, and that's why I wish Douglas was here. But so

8 those, that's really what's on our plate right now. If

9 there's any questions.

10 MR. PASSMORE: Could you just say a

11 little bit about CARE, it's a new organization to me, and

12 just a little of --

13 MR. LISKEY: Yeah, I'd be happy to. And

14 I have a brochure that I've put in my packets for the two

15 of you. So CARE was something that I founded with Kelly

16 Kitchen's assistance back in 2009. I left the Attorney

17 General's office to form this nonprofit for the specific

18 purpose of intervening in these cases in the Upper

19 Peninsula and also get involved in FERC and MISO

20 activities. So we -- there's several requirements, one

21 is having members, you have to have residential members

22 that are actual ratepayers, so we did a direct mail

23 campaign to the Upper Peninsula voter list and asked

24 people to join and people joined, we have a website

25 people can join. And so we qualify -- we have fought off


126

1 many attempts to disqualify our interventions, so we've

2 had to regularly prove that, yes, we have customers in

3 your region and here's a copy of their bill, and so

4 that's kind of the nuts and bolts of that.

5 And we've been in, since 2009, in over 72

6 cases. The amount that we spend is a lot less than the

7 Detroit Edison and Consumers cases. We settle 90 percent

8 of our cases, maybe more. So that -- I don't know if you

9 want anymore.

10 MR. PASSMORE: No, that's' great. Thank

11 you.

12 MR. LISKEY: And then, again, there's

13 more information in our, in these binders, and happy to

14 talk on the phone if you have any other questions.

15 MR. PASSMORE: Terrific. Thanks.

16 MR. MacINNES: You know, on that topic,

17 that's a good question, I happen to have a list here of

18 some of the cases that our grantees have been involved

19 with over the years and what we spent on the case and

20 what we saved ratepayers. I'll just give you a few

21 samples. Specifically related to CARE, Case U-15664, it

22 was a 2009 reconciliation case, cost $19,000, we saved

23 ratepayers $139,000. The WEPCo case, plan case in 2014,

24 U-17312, the cost of the rate case for services is

25 $22,725, we saved the ratepayers $4,346,000. I'll just


127

1 give you one more for you and I'll give a couple for MEC.

2 UPPCo plan case, U-16881, we spent $28,800, we saved

3 ratepayers $2.968 million.

4 And then just on CARE -- or on MEC,

5 here's a case on we spent, Case U-17319, DTE 2014 PSCR

6 plan case, we spent $47,700, we saved ratepayers 8.9

7 million. This is my favorite one, Case U-16991, DTE

8 renewable generating assets depreciation case, we spent

9 $37,375, we saved ratepayers $35 million. And I don't

10 know if I can really top that, but anyway, you get the

11 idea.

12 And we track and we ask the grantees

13 periodically to give us a list of their successes, and

14 they're not all successful, but it doesn't take too many

15 to pay for the funds that we use, so.

16 Chris, do you have anything else you want

17 to add to the grantee reports?

18 MR. BZDOK: I appreciate Jim bringing up

19 that wind depreciation case because that's for the

20 Gratiot County Wind Park, so whenever I try to talk about

21 that in the car with my wife and my three year old, they

22 don't really want to hear about it. It's nice that

23 somebody's interested in it still.

24 MR. MacINNES: Okay. Anything else?

25 MR. BZDOK: Just very, very briefly,


128

1 because you've already heard a lot from me already, but

2 we do have a new order in the Consumers 2016 PSCR plan

3 case, it's summarized in the status report. There were

4 three issues in that case: One was the wind contracts

5 thing, which we've already talked about extensively; one

6 was a claim for expenses from -- and the reason I'm

7 bringing this up is because it is going to be one where

8 we're going to have to report an ROI, and I want to talk

9 to you about that. Consumers has been for 2 1/2 years

10 now contesting a rail transportation rate against CSX

11 Transportation Company for rail transport of coal from

12 Chicago to the Campbell 3, to the Campbell plant, and

13 Consumers has attempted to claim in two different cases

14 costs of litigation associated with that saying, well, it

15 has to do with fuel and fuel transport, so it's a PSCR

16 expense. In the Commission's order which came out in

17 October, the Commission agreed with us that that was not

18 an expense. We don't take a position on whether they

19 should or should not be contesting this rail rate, we

20 just say you can't collect that from PSCR customers; and

21 they say, we don't know where else to collect it; we say,

22 that's not our, you know, that's not our concern, you

23 know, it's not a PSCR expense, and the Commission agreed

24 with that, so there was $2.2 million that were being

25 claimed for 2016 for those expenses, and so that's a


129

1 savings, you know, on a $45,000 funding, there was a $2.2

2 million savings. Now, Consumers may -- so let me

3 complete the loop on that. So in the 2015, it's a little

4 bit of a time machine thing, because that was the 2016

5 case for 2016 expenses, the 2016 case is filed in the

6 fall of 2015, the 2015 reconciliation is filed in the

7 spring of 2016 wherein they claimed $3 million of

8 additional STB litigation expense for 2015. So even

9 though that expense was claimed earlier, it was filed for

10 later, and that case is still pending. Likely we're

11 going to see the same result in that case, which would,

12 if we do, you know, $5.2 million total savings.

13 Discovery in that case has also revealed that they are

14 expecting to incur another $661,000 of litigation expense

15 in that STB case in 2017; we are going to have discovery

16 out to them very shortly about whether that's included in

17 their PSCR plan for 2017 because it's not clear whether

18 it is or not.

19 What I don't know is, I don't know -- so

20 I could say, 17918, 45,000 spent, $2.2 million saved,

21 49-to-1, you know, return, cost-to-benefit ratio or

22 whatever, but I don't know if Consumers is going to come

23 back in some future other kind of proceeding and make a

24 claim for that, and if they do, I don't know if that will

25 be -- if they come back in a rate case, I'm not totally


130

1 sure it would apply to a rate case because it's not an

2 ongoing thing, for one, it's not incurred in the test

3 year, for two, I don't know how it compares to their,

4 what is their outside litigation expense budget that they

5 already include in general O&M. So I mean there's

6 questions there. So I mean I can report it just, you

7 know, 2.2 million on 45,000 maybe with an asterisk that

8 says, you know, (A) there may be other savings associated

9 with this in these other cases, (B) they may come back in

10 some future proceedings, in which case we'll have to

11 update this result. I don't know really how else to do

12 it. But I know the board has requested that in these

13 status reports we start including an ROI where we have a

14 savings and a final order.

15 MR. MacINNES: And what we do is like a

16 benefit to cost, we spent this much and we saved this

17 much, here was the cost, this is the benefit, and we use

18 like a zero discount rate, so we'll present value

19 everything at full value going forward.

20 MR. BZDOK: So if that's all right, I'll

21 just report it with a couple footnotes or something.

22 MR. MacINNES: You can't predict the

23 future.

24 MR. BZDOK: So we're pleased about that.

25 James was my witness on that, so we spent -- because we


131

1 spent our expert funds auditing that natural gas

2 management agreement, and that's reported in here as

3 well, so James just, as the policy director of MEC with

4 experience supervising PSCR cases was our witness on this

5 other issue, so that all ended well.

6 The natural gas agreement was more or

7 less an audit because it was a new agreement and we were

8 pointing out some potential issues of concern. The

9 Commission said, you know, we're not going to do anything

10 now, but they do appear to be issues of concern, we're

11 going to watch it in the future. I'm happy with that,

12 because in other contexts we've had, you know, we've

13 brought something up on an agreement that was entered

14 into five years ago, and they say, well, that agreement

15 was entered into and nobody said anything, so now at

16 least we've kind of said something and it's on the record

17 that the Commission's going to keep an eye on that, and

18 we will, too, so I'm happy with that outcome as well.

19 That's all I have.

20 MR. MacINNES: Okay. Thank you, Chris.

21 Let's move on to public comments. Are

22 there any public comments? No.

23 Next meeting is February 6. We'd really

24 appreciate people getting their material to us early.

25 I'm going to be gone the whole week prior to that,


132

1 returning the night of February 5, on vacation, and I

2 would love to not have to read all that while I'm on

3 vacation. I'll be glad to read it beforehand, though.

4 MR. LISKEY: Do you want us to resubmit

5 essentially what we submitted at the end, you know, of

6 the annual grant meeting, like for the --

7 MR. MacINNES: I don't think you need to

8 do that. I think it's just the updates and what you're

9 requesting and, you know, kind of updates and what's --

10 it helps us if you can be real specific, here's what I

11 would like, here's what you've done, here's what we would

12 like you to approve at this meeting, and here's my

13 update.

14 MR. LISKEY: Okay.

15 MR. MacINNES: So that we're not, you

16 know -- I mean we get a lot of stuff --

17 MR. LISKEY: You get too much paper, I

18 know.

19 MR. MacINNES: -- to read and it's like,

20 you know, we're not always exactly -- you have to kind of

21 walk us through it sometimes. So the more you can make

22 that real clear, the better, the easier it is for us.

23 MR. LISKEY: Yep, okay.

24 MR. MacINNES: Okay. Do we have a motion

25 to adjourn?


133

1 MS. HAROUTUNIAN: So moved.

2 MR. MacINNES: All those in favor?


4 MR. MacINNES: Okay. We're adjourned.

5 Thank you, all, so much.

6 (The meeting concluded at 3:59 p.m.)

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134

1 STATE OF MICHIGAN )

)

2 COUNTY OF MACOMB )

3 I, Lori Anne Penn, certify that this

4 transcript consisting of 134 pages is a complete, true,

5 and correct record of the Utility Consumer Participation

6 Board Meeting held on Monday, December 5, 2016.

7 I further certify that I am not

8 responsible for any copies of this transcript not made

9 under my direction or control and bearing my original

10 signature.

11 I also certify that I am not a relative

12 or employee of or an attorney for a party; or a relative

13 or employee of an attorney for a party; or financially

14 interested in the action.

15

16

17 December 20, 2016 _____________________________________

Date Lori Anne Penn, CSR-1315

18 Notary Public, Macomb County, Michigan

My Commission Expires June 15, 2019

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